As filed with the Securities and Exchange
Commission on December 1, 2011
Registration
No. 333-176265
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Amendment No. 3
to
Form S-1
REGISTRATION
STATEMENT
UNDER
THE SECURITIES ACT OF
1933
Mid-Con Energy Partners,
LP
(Exact name of registrant as
specified in its charter)
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Delaware
(State or other jurisdiction
of
incorporation or organization)
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1311
(Primary Standard
Industrial
Classification Code Number)
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45-2842469
(I.R.S. Employer
Identification Number)
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2501 North Harwood Street, Suite 2410
Dallas, Texas 75201
(918) 743-7575
(Address, including zip code,
and telephone number, including area code, of registrants
principal executive offices)
Charles R. Olmstead
Mid-Con Energy GP, LLC
2431 E. 61st Street, Suite 850
Tulsa, Oklahoma 74136
(918) 743-7575
(Name, address, including zip
code, and telephone number, including area code, of agent for
service)
Copies to:
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Richard M. Carson
GableGotwals
1100 ONEOK Plaza
100 W. Fifth Street
Tulsa, Oklahoma 74103
(918) 595-4800
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William J. Cooper
Andrews Kurth LLP
1350 I Street, NW
Suite 1100
Washington, DC 20005
(202) 662-2700
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J. Michael Chambers
Brett E. Braden
Latham & Watkins LLP
717 Texas Avenue, Suite 1600
Houston, Texas 77002
(713) 546-5400
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Approximate date of commencement of proposed sale to the
public: As soon as practicable after this
Registration Statement becomes effective.
If any of the securities being registered on this Form are to be
offered on a delayed or continuous basis pursuant to
Rule 415 under the Securities Act of 1933, check the
following
box. o
If this Form is filed to register additional securities for an
offering pursuant to Rule 462(b) under the Securities Act,
please check the following box and list the Securities Act
registration statement number of the earlier effective
registration statement for the same
offering. o
If this Form is a post-effective amendment filed pursuant to
Rule 462(d) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2 of the
Exchange Act. (Check one):
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Large
accelerated
filer o
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Accelerated
filer o
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Non-accelerated
filer þ
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Smaller reporting
company o
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(Do not check if a smaller
reporting company)
The Registrant hereby amends this Registration Statement on
such date or dates as may be necessary to delay its effective
date until the Registrant shall file a further amendment which
specifically states that this Registration Statement shall
thereafter become effective in accordance with Section 8(a)
of the Securities Act of 1933 or until the Registration
Statement shall become effective on such date as the Securities
and Exchange Commission, acting pursuant to said
Section 8(a), may determine.
The information in
this preliminary prospectus is not complete and may be changed.
We may not sell these securities until the registration
statement filed with the Securities and Exchange Commission is
effective. This preliminary prospectus is not an offer to sell
these securities and it is not soliciting an offer to buy these
securities in any jurisdiction where the offer or sale is not
permitted.
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Subject to Completion, dated
December 1, 2011
PRELIMINARY
PROSPECTUS
Mid-Con Energy Partners,
LP
5,400,000 Common
Units
Representing Limited Partner
Interests
We are a Delaware limited partnership formed in July 2011 to
own, operate, acquire, exploit and develop producing oil and
natural gas properties in North America, with a focus on the
Mid-Continent region of the United States. This is the initial
public offering of our common units. No public market currently
exists for our common units. We expect the initial public
offering price to be between $19.00 and $21.00 per common unit.
We have been approved to list our common units on the NASDAQ
Global Market under the symbol MCEP.
Investing in our common units involves risks. See Risk
Factors beginning on page 22.
These risks include the following:
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We may not have sufficient cash to pay the initial quarterly
distribution on our units following the establishment of cash
reserves and payment of expenses, including payments to our
general partner.
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We would not have generated sufficient available cash on a pro
forma basis to have paid the initial quarterly distribution on
all of our units for the twelve months ended September 30,
2011.
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Unless we replace the oil reserves we produce, our revenues and
production will decline, which would adversely affect our cash
flow from operations and our ability to make distributions to
our unitholders at the initial quarterly distribution rate.
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A decline in oil prices, or an increase in the differential
between the NYMEX or other benchmark prices of oil and the
wellhead price we receive for our production, will cause a
decline in our cash flow from operations, which could cause us
to reduce our distributions or cease paying distributions
altogether.
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Our general partner, who controls us, will have conflicts of
interest with, and owe limited fiduciary duties to, us, which
may permit them to favor their own interests to the detriment of
us and our unitholders.
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Neither we nor our general partner have any employees, and we
rely solely on an affiliate of our general partner to manage and
operate our business. The individuals who will manage us will
also provide substantially similar services to affiliates of our
general partner, and thus will not be solely focused on our
business.
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Common units held by persons who our general partner determines
are not eligible holders will be subject to redemption.
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Our unitholders have limited voting rights and are not entitled
to elect our general partner or its board of directors, which
could reduce the price at which our common units will trade.
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Even if our unitholders are dissatisfied, they cannot remove our
general partner without its consent.
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Our tax treatment depends on our status as a partnership for
federal income tax purposes. If the IRS were to treat us as a
corporation, then our cash available for distribution to our
unitholders would be substantially reduced.
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Our unitholders will be required to pay taxes on their share of
our taxable income even if they do not receive any cash
distributions from us.
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Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved of these
securities or determined if this prospectus is truthful or
complete. Any representation to the contrary is a criminal
offense.
PRICE
$
PER COMMON UNIT
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Per
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Common
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Unit
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Total
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Public offering price
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$
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$
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Underwriting discount(1)
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$
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$
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Proceeds, before expenses(2)
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$
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$
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(1)
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Excludes a structuring fee equal to
0.375% of the gross proceeds of this offering payable to RBC
Capital Markets, LLC.
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(2)
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After deducting the underwriting
discount, the structuring fee and the estimated offering
expenses and applying the offering proceeds as described in
Use of Proceeds on page 46, we do not expect
that any of the net proceeds of the offering will be available
for investment in our business.
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We have granted the underwriters a
30-day
option to purchase up to an additional 810,000 common units on
the same terms and conditions as set forth above if the
underwriters sell more than 5,400,000 common units in this
offering.
The underwriters expect to deliver the common units on or
about ,
2011.
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RBC
Capital Markets |
Raymond James |
Wells Fargo Securities |
,
2011
As of and
for the month ended September 30, 2011
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Total estimated proved reserves: 9.9 MMBoe, 98% oil and 69%
proved developed, on a Boe basis in each instance
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275 gross producing oil and natural gas wells (176 net
wells) and 123 gross injection wells (73 net wells),
99% of our properties are operated, 92% of our reserves were
being produced under waterflooding, both on a Boe basis.
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TABLE OF
CONTENTS
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1
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1
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5
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5
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7
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8
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8
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9
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9
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11
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15
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17
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19
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22
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22
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33
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41
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46
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48
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49
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50
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50
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52
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54
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56
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57
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59
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60
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66
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71
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71
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71
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72
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73
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76
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76
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76
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81
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82
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86
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92
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92
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93
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96
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96
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97
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97
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98
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98
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99
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100
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101
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103
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104
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104
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111
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116
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120
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125
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127
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127
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127
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128
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128
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128
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131
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132
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132
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133
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135
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137
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137
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140
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142
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142
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143
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144
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144
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146
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146
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151
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155
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155
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155
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157
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157
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157
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157
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157
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158
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159
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159
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160
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161
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163
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164
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164
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165
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166
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166
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166
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167
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167
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168
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168
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168
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169
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169
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169
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170
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171
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172
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173
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174
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180
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185
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187
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188
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188
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191
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192
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193
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195
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199
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200
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201
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You should rely only on the information contained in this
prospectus. We have not, and the underwriters have not,
authorized anyone to provide you with different information. If
anyone provides you with different or inconsistent information,
you should not rely on it. We are not, and the underwriters are
not, making an offer to sell these securities in any
jurisdiction where an offer or sale is not permitted. You should
assume that the information appearing in this prospectus is
accurate as of the date on the front cover of this prospectus
only. Our business, financial condition, results of operations
and prospects may have changed since that date.
Until ,
2011 (25 days after the date of this prospectus), all
dealers that buy, sell or trade our common units, whether or not
participating in this offering, may be required to deliver a
prospectus. This is in addition to the dealers obligation
to deliver a prospectus when acting as underwriters and with
respect to their unsold allotments or subscriptions.
This prospectus contains forward-looking statements that are
subject to a number of risks and uncertainties, many of which
are beyond our control. Please read Risk Factors and
Forward-Looking Statements.
Industry
and Market Data
The market data and certain other statistical information used
throughout this prospectus are based on independent industry
publications, government publications or other published
independent sources. Some data is also based on our good faith
estimates. Although we believe these third-party sources are
reliable and that the information is accurate and complete, we
have not independently verified the information.
PROSPECTUS SUMMARY
This summary highlights information contained elsewhere in
this prospectus. You should read the entire prospectus
carefully, including Risk Factors and the historical
and unaudited pro forma financial statements and the notes to
those financial statements. The information presented in this
prospectus assumes that the underwriters do not exercise their
option to purchase up to an additional 810,000 common units,
unless otherwise indicated. As used in this prospectus, unless
we indicate otherwise:
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Contributing Parties collectively refers to the
Founders, Yorktown, our executive officers, employees and other
individuals and entities who hold membership interests in our
predecessor;
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Founders collectively refers to Charles R.
Olmstead, S. Craig George and Jeffrey R. Olmstead;
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our general partner refers to Mid-Con Energy GP,
LLC;
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Mid-Con Affiliates collectively refers to Mid-Con
Energy III, LLC and Mid-Con Energy IV, LLC, which are affiliates
of our general partner;
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Mid-Con Energy Partners, the
partnership, we, our,
us or like terms when used in a historical context
refer to our predecessor, which will be merged with and into
Mid-Con Energy Properties, LLC, our wholly owned subsidiary, in
connection with this offering. When used in the present tense or
prospectively, those terms refer to Mid-Con Energy Partners, LP,
a Delaware limited partnership, and its subsidiaries;
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Mid-Con Energy Operating refers to Mid-Con Energy
Operating, Inc., an affiliate of our general partner;
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Mid-Con Energy Properties refers to Mid-Con
Energy Properties, LLC, our wholly owned subsidiary;
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our predecessor collectively refers to Mid-Con
Energy Corporation, prior to June 30, 2009, and to Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC, on a combined
basis, thereafter, our respective predecessors for accounting
purposes; and
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Yorktown collectively refers to Yorktown Partners
LLC, Yorktown Energy Partners VI, L.P., Yorktown Energy Partners
VII, L.P., Yorktown Energy Partners VIII, L.P. and/or Yorktown
Energy Partners IX, L.P.
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We include a glossary of some of the oil and natural gas
terms used in this prospectus in Appendix B. Our estimated
proved reserve information as of December 31, 2010 and
September 30, 2011 is based on a report prepared by our
reservoir engineering staff and audited by Cawley,
Gillespie & Associates, Inc., our independent reserve
engineers. A summary of our estimated proved reserve information
as of September 30, 2011 prepared by our reservoir
engineering staff and audited by Cawley, Gillespie &
Associates, Inc. is included in this prospectus in
Appendix C.
Mid-Con
Energy Partners, LP
Overview
We are a Delaware limited partnership formed in July 2011 to
own, operate, acquire, exploit and develop producing oil and
natural gas properties in North America, with a focus on the
Mid-Continent region of the United States. Our management team
has significant industry experience, especially with waterflood
projects and, as a result, our operations focus primarily on
enhancing the development of producing oil properties through
waterflooding. Through the continued development of our existing
properties and through future acquisitions, we will seek to
1
increase our reserves and production in order to maintain and,
over time, increase distributions to our unitholders. Also, in
order to enhance the stability of our cash flow for the benefit
of our unitholders, we will seek to hedge a significant portion
of our production volumes through various commodity derivative
contracts.
As of September 30, 2011, our total estimated proved
reserves were 9.9 MMBoe, of which approximately 98% were
oil and 69% were proved developed, both on a Boe basis. As of
September 30, 2011, we operated 99% of our properties
through our affiliate, Mid-Con Energy Operating, and 92% of our
properties were being produced under waterflood, in each
instance on a Boe basis. Our average net production for the
month ended September 30, 2011 was approximately
1,343 Boe per day and our total estimated proved reserves
had a
reserve-to-production
ratio of approximately 20 years. Our management team
developed approximately 60% of our total reserves through new
waterflood projects.
Our
Properties
Our properties are located in the Mid-Continent region of the
United States and primarily consist of mature, legacy onshore
oil reservoirs with long-lived, relatively predictable
production profiles and low production decline rates. Our core
areas of operation are located in Southern Oklahoma,
Northeastern Oklahoma and parts of Oklahoma and Colorado within
the Hugoton Basin. As of September 30, 2011, approximately
91% of the properties associated with our estimated reserves, on
a Boe basis, have been producing continuously since 1982 or
earlier. Through the application of waterflooding, we believe
these mature properties have attractive upside potential.
Waterflooding, a form of secondary oil recovery, works by
repressuring a reservoir through water injection and pushing or
sweeping oil to producing wellbores. Based on the
production estimates from our September 30, 2011 reserve
report, the average estimated decline rate for our proved
developed producing reserves is approximately 8.5% for 2012 and,
on a compounded average decline basis, approximately 11% for the
subsequent five years and approximately 10% thereafter.
The following table summarizes information by core area
regarding our estimated oil and natural gas reserves as of
September 30, 2011 and our average net production for the
month ended September 30, 2011.
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Average
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Net
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Estimated
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Production
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Net Proved Reserves
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for the Month Ended
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as of September 30, 2011
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September 30, 2011
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Average
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Gross Active Wells
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Reserve-to-
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Oil and
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% Proved
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Boe/d
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Boe/d
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Production
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Natural
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Injection
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(MBoe)
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% Operated
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% Oil
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Developed
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Gross
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Net
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Ratio(1)
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Gas Wells
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Wells
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Southern Oklahoma
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5,385
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100
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%
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100
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%
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66
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%
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2,139
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784
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19
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65
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42
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Northeastern Oklahoma
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3,129
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100
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%
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99
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%
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68
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%
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572
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329
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26
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154
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59
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Hugoton Basin
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1,045
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100
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%
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100
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%
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75
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%
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263
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160
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18
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43
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18
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Other
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349
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61
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%
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60
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%
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100
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%
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222
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70
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14
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13
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4
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|
|
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|
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|
|
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Total
|
|
|
9,908
|
|
|
|
99
|
%
|
|
|
98
|
%
|
|
|
69
|
%
|
|
|
3,196
|
|
|
|
1,343
|
|
|
|
20
|
|
|
|
275
|
|
|
|
123
|
|
|
|
|
|
|
|
|
|
|
|
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|
(1) |
The average
reserve-to-production
ratio is calculated by dividing estimated net proved reserves as
of September 30, 2011 by average net production for the
month ended September 30, 2011.
|
2
The following chart summarizes our pro forma total average net
Boe production volumes on a monthly basis, and illustrates the
100% increase in our production volumes over the twelve months
ended September 30, 2011. We achieved approximately 75% of
this production increase primarily through ongoing waterflood
response from existing development activities and approximately
25% of this production increase from workovers and acquisitions.
Our
Hedging Strategy
Our hedging strategy seeks to reduce the impact to our cash flow
from commodity price volatility. We intend to enter into
commodity derivative contracts at times and on terms designed to
maintain, over the long-term, a portfolio covering approximately
50% to 80% of our estimated oil production from proved reserves
over a
three-to-five
year period at any given point in time. For the years ending
December 31, 2011, 2012 and 2013, we have commodity
derivative contracts covering approximately 37%, 53% and 30%,
respectively, of our estimated oil production from proved
reserves as of September 30, 2011. All of our derivative
contracts for 2012 and 2013 are either swaps with fixed
settlements or collars. The weighted average minimum prices on
all of our derivative contracts for 2012 and 2013 are $101.18
and $100.14, respectively. A collar is a combination
of a put option we purchase and a call option we sell. The put
option portion of a collar is also referred to as a
floor. A floor establishes a minimum average sale
price for future oil production. In 2012, we have collars with a
floor of $100.00 and swaps with fixed price settlements ranging
from $100.97 to $104.28 covering approximately 11% and 42%,
respectively, of our total proved estimated oil production. In
2013, we have collars with a floor of $100.00 and swaps with
fixed price settlements ranging from $96.00 to $105.80 covering
9% and 21%, respectively, of our total proved estimated oil
production.
We intend to enter into additional commodity derivative
contracts in connection with material increases in our estimated
production and at times when we believe market conditions or
other circumstances suggest that it is prudent to do so as
opposed to entering into commodity
3
derivative contracts at predetermined times or on prescribed
terms. Additionally, we may take advantage of opportunities to
modify our commodity derivative portfolio to change the
percentage of our hedged production volumes or the duration of
our hedge contracts when circumstances suggest that it is
prudent to do so.
By removing a significant portion of price volatility associated
with our estimated future oil production, we have mitigated, but
not eliminated, the potential effects of changing oil prices on
our cash flow from operations for those periods. For a further
description of our commodity derivative contracts, please read
Managements Discussion and Analysis of Financial
Condition and Results of OperationsLiquidity and Capital
ResourcesDerivative Contracts.
Our
Business Strategies
Our primary business objective is to generate stable cash flow,
which will allow us to make quarterly cash distributions to our
unitholders at the initial quarterly distribution rate and, over
time, to increase our quarterly cash distributions. To achieve
our objective, we intend to execute the following business
strategies:
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Continue exploitation of our existing properties to maximize
production;
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Pursue acquisitions of long-lived, low-risk producing properties
with upside potential;
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Capitalize on our relationship with the Mid-Con Affiliates for
favorable acquisition opportunities;
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Maintain operational control and a focus on cost-effectiveness
in all our operations;
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Reduce the impact of commodity price volatility on our cash flow
through a disciplined commodity hedging strategy;
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Maintain a balanced capital structure to allow for financial
flexibility to execute our business strategies; and
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Utilize compensation programs that align the interests of our
management team with our unitholders.
|
For a more detailed description of our business strategies,
please read Business and PropertiesOur Business
Strategies.
Our
Competitive Strengths
We believe that the following competitive strengths will allow
us to successfully execute our business strategies and achieve
our objective of generating and growing cash available for
distribution:
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An asset portfolio largely consisting of properties with
existing waterflood projects that have relatively predictable
production profiles, that provide growth potential through
ongoing response to waterflooding and that have modest capital
requirements;
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The ability to further exploit existing mature properties by
utilizing our waterflooding expertise;
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Acquisition opportunities that are consistent with our criteria
of predictable production profiles with upside potential that
may arise as a result of our relationship with the
Mid-Con
Affiliates;
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Access to the collective expertise of Yorktowns employees
and their extensive network of industry relationships through
our relationship with Yorktown;
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The ability to better manage our operating costs, capital
expenditures and development schedule because of our high level
of operational control;
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4
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An enhanced ability to pursue acquisition opportunities arising
from our competitive cost of capital and balanced capital
structure; and
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The range and depth of our technical and operational expertise
will allow us to expand both geographically and operationally to
achieve our goals.
|
For a more detailed discussion of our competitive strengths,
please read Business and PropertiesOur Competitive
Strengths.
Our
Principal Business Relationships
Our
Relationship with the Mid-Con Affiliates
In June 2011, management and Yorktown formed two limited
liability companies, which we refer to collectively as the
Mid-Con Affiliates, to acquire and develop oil and natural gas
properties that are either undeveloped or that may require
significant capital investment and development efforts before
they meet our criteria for ownership. As these development
projects mature, we expect to have the opportunity to acquire
certain of these properties from the Mid-Con Affiliates. Through
this relationship with the Mid-Con Affiliates, we plan to avoid
much of the capital, engineering and geological risks associated
with the early development of any of these properties we may
acquire. However, the Mid-Con Affiliates may not be successful
in indentifying or consummating acquisitions or in successfully
developing the new properties they acquire. Further, the Mid-Con
Affiliates are not obligated to sell any properties to us and
they are not prohibited from competing with us to acquire oil
and natural gas properties. Please read Certain
Relationships and Related Party TransactionsReview,
Approval or Ratification of Transactions with Related
Persons.
Our
Relationship with Yorktown
We have a valuable relationship with Yorktown, a private
investment firm founded in 1991 and focused on investments in
the energy sector. Since 2004, Yorktown has made several equity
investments in our predecessor. Immediately following the
consummation of this offering, Yorktown will own an approximate
49.9% limited partner interest in us, making it our largest
unitholder, and will own a 50% interest in our affiliate Mid-Con
Energy Operating. Also, Peter A. Leidel, a principal of
Yorktown, will serve on our board of directors.
Yorktown currently has more than $3.0 billion in assets
under management and Yorktowns employees have extensive
investment experience in the oil and natural gas industry.
Yorktowns employees review a large number of potential
acquisitions and are involved in decisions relating to the
acquisition and disposition of oil and natural gas assets by the
various portfolio companies in which Yorktown owns interests.
With their extensive investment experience in the oil and
natural gas industry and their extensive network of industry
relationships, we believe that Yorktowns employees are
well positioned to assist us in identifying and evaluating
acquisition opportunities and in making strategic decisions.
Yorktown is not obligated to sell any properties to us and they
are not prohibited from competing with us to acquire oil and
natural gas properties. Investment funds managed by Yorktown
manage numerous other portfolio companies that are engaged in
the oil and natural gas industry and, as a result, Yorktown may
present acquisition opportunities to other Yorktown portfolio
companies that compete with us.
Risk
Factors
An investment in our common units involves risks. Below is a
summary of certain key risk factors that you should consider in
evaluating an investment in our common units. This list is not
exhaustive. Please read the full discussion of these risks and
other risks described under Risk Factors.
5
Risks
Related to Our Business
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We may not have sufficient cash to pay the initial quarterly
distribution on our units following the establishment of cash
reserves and payment of expenses, including payments to our
general partner.
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We would not have generated sufficient available cash on a pro
forma basis to have paid the initial quarterly distribution on
all of our units for the twelve months ended September 30,
2011.
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Unless we replace the oil reserves we produce, our revenues and
production will decline, which would adversely affect our cash
flow from operations and our ability to make distributions to
our unitholders at the initial quarterly distribution rate.
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A decline in oil prices, or an increase in the differential
between the NYMEX or other benchmark prices of oil and the
wellhead price we receive for our production, will cause a
decline in our cash flow from operations, which could cause us
to reduce our distributions or cease paying distributions
altogether.
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We may be unable to compete effectively with larger companies,
which may adversely affect our ability to generate sufficient
revenue to allow us to pay distributions to our unitholders at
the initial quarterly distribution rate.
|
Risks
Inherent in an Investment in Us
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|
Our general partner controls us, and the Founders and Yorktown
own a 57.4% interest in us. They will have conflicts of interest
with, and owe limited fiduciary duties to, us, which may permit
them to favor their own interests to the detriment of us and our
unitholders.
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Neither we nor our general partner have any employees, and we
rely solely on Mid-Con Energy Operating to manage and operate
our business. The management team of Mid-Con Energy Operating,
which includes the individuals who will manage us, will also
provide substantially similar services to the Mid-Con
Affiliates, and thus will not be solely focused on our business.
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Units held by persons who our general partner determines are not
eligible holders will be subject to redemption.
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Our unitholders have limited voting rights and are not entitled
to elect our general partner or its board of directors, which
could reduce the price at which our common units will trade.
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Even if our unitholders are dissatisfied, they cannot remove our
general partner without its consent.
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Control of our general partner may be transferred to a third
party without unitholder consent.
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We may issue an unlimited number of additional units, including
units that are senior to the common units, without unitholder
approval, which would dilute unitholders ownership
interests.
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Tax
Risks to Unitholders
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Our tax treatment depends on our status as a partnership for
federal income tax purposes. If the IRS were to treat us as a
corporation, then our cash available for distribution to our
unitholders would be substantially reduced.
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Our unitholders will be required to pay taxes on their share of
our taxable income even if they do not receive any cash
distributions from us.
|
6
Formation
Transactions and Partnership Structure
The following transactions, which we refer to as the formation
transactions, will occur at, or immediately prior to, the
closing of this offering:
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|
We will acquire working interests from J&A Oil Company and
Charles R. Olmstead and interests in derivative contracts from
J&A Oil Company for aggregate consideration of
approximately $6.0 million immediately prior to the closing
of this offering;
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|
We will enter into a contribution, conveyance, assumption and
merger agreement pursuant to which Mid-Con Energy I, LLC
and Mid-Con
Energy II, LLC will merge with and into our wholly owned
subsidiary, Mid-Con Energy Properties and our general partner
will make a contribution to us;
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We will enter into a new $250.0 million credit facility
under which we expect to borrow approximately $45.0 million
at the closing of this offering;
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We will issue 5,400,000 common units to the public, representing
a 30.0% limited partner interest in us;
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We will issue 12,240,000 common units to the Contributing
Parties as additional consideration for the merger;
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We will issue 360,000 general partner units to our general
partner, representing a 2.0% general partner interest in us, in
consideration for its contribution to us;
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We will repay in full the outstanding borrowings under our
existing credit facility and distribute approximately
$121.2 million to the Contributing Parties as the cash
portion of the consideration in respect of the merger discussed
in the second bullet above; and
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We will enter into a services agreement with Mid-Con Energy
Operating, pursuant to which Mid-Con Energy Operating will
provide management, administrative and operational services to
us.
|
The number of common units that we will issue to the public and
the Contributing Parties, as reflected in the fourth and fifth
bullet points above, assume that the underwriters do not
exercise their option to purchase up to an additional 810,000
common units. To the extent the underwriters exercise this
option, the number of common units issued to the public (as
reflected in the third bullet above) will increase by the
aggregate number of common units purchased by the underwriters
pursuant to such exercise, and the number of common units issued
to the Contributing Parties (as reflected in the fourth bullet
above) will decrease by the aggregate number of common units
purchased by the underwriters pursuant to such exercise.
7
Ownership
and Organizational Structure of Mid-Con Energy Partners,
LP
The diagram below depicts our organization and ownership after
giving effect to the offering and the related formation
transactions and assumes that the underwriters do not exercise
their option to purchase additional common units.
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Common units held by the public
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|
30.0
|
%
|
Common units held by the Contributing Parties:
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Common units held by the Founders
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7.5
|
%
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Common units held by Yorktown
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49.9
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%
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Common units held by the other Contributing Parties
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10.6
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%
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General partner units
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2.0
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%
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Total
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|
100.0
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%
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(1)
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|
The additional Contributing Parties
(other than the Founders and Yorktown) are not reflected in the
chart above. Certain of such additional Contributing Parties
also hold membership interests in the Mid-Con Affiliates.
|
|
(2)
|
|
The Founders are S. Craig George,
Charles R. Olmstead and Jeffrey R. Olmstead.
|
|
(3)
|
|
Yorktown IX Company LP is the sole
general partner of Yorktown Energy Partners IX, L.P. Yorktown
Associates LLC is the sole general partner of Yorktown IX
Company LP. For more information on the entities that control
Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII,
L.P., and Yorktown Energy Partners VIII, L.P, please see
Security Ownership of Certain Beneficial Owners and
Management.
|
Management
of Mid-Con Energy Partners, LP
We are managed and operated by the board of directors and
executive officers of our general partner, Mid-Con Energy GP,
LLC. Our unitholders will not be entitled to elect our general
partner or its directors or otherwise participate in our
management or operation. All of the executive officers of our
general partner are also officers and/or directors of the
Mid-Con Affiliates. For information about the executive officers
and directors of our general partner, please read
Management.
S. Craig George, the Executive Chairman of the board of
directors of our general partner, Charles R. Olmstead, the Chief
Executive Officer and a director of our general partner, and
Jeffrey R. Olmstead, the President and Chief Financial Officer
and a director of our general
8
partner, or collectively, the Founders, will each
own one-third of the member interests in our general partner. As
the holders of all of the member interests of our general
partner, the Founders will control our general partner, will be
entitled to appoint its entire board of directors and will
receive all of the distributions our general partner receives in
respect of its 2.0% general partner interest in us. Please see
Security Ownership of Certain Beneficial Owners and
Management.
Neither we, our general partner, nor our subsidiary have any
employees. In connection with the closing of this offering, we
and our general partner will enter into a services agreement
with Mid-Con Energy Operating, pursuant to which Mid-Con Energy
Operating will provide management, administrative and
operational services to us. Although all of the employees that
conduct our business are employed by Mid-Con Energy Operating,
we sometimes refer to these individuals in this prospectus as
our employees.
We will initially have one subsidiary, Mid-Con Energy
Properties, that will hold title to our properties.
Principal
Executive Offices and Internet Address
Our headquarters are located at 2501 North Harwood Street, Suite
2410, Dallas, Texas 75201. Our principal operating office is
located at 2431 East 61st Street, Suite 850,
Tulsa, Oklahoma 74136, and our telephone number is
(918) 743-7575.
Our website address is www.midconenergypartners.com and will be
activated in connection with the closing of this offering. We
expect to make our periodic reports and other information filed
with or furnished to the Securities and Exchange Commission,
which we refer to as the SEC, available free of charge through
our website as soon as reasonably practicable after those
reports and other information are electronically filed with or
furnished to the SEC. Information on our website or any other
website is not incorporated by reference into, and does not
constitute a part of, this prospectus.
Summary
of Conflicts of Interest and Fiduciary Duties
Under our partnership agreement, our general partner has a legal
duty to manage us in a manner that is in, or not opposed to, the
best interests of the holders of our common units. This legal
duty, as modified by our partnership agreement, originates in
statutes and judicial decisions and is commonly referred to as a
fiduciary duty. However, the officers and directors
of our general partner also have a fiduciary duty to manage the
business of our general partner in a manner beneficial to its
owners, the Founders. All of the executive officers of our
general partner are also officers
and/or
directors of the Mid-Con Affiliates and will have economic
interests in the Mid-Con Affiliates. In addition, Peter A.
Leidel, a principal of Yorktown, will serve on our board of
directors. Mr. Leidel has economic interests in Yorktown
and its affiliates that manage, hold and own investments in
other funds and companies that may compete with us. As a result
of these relationships, conflicts of interest may arise in the
future between us and our unitholders, on the one hand, and our
general partner and its owners and affiliates, on the other
hand. For example, our general partner is entitled to make
determinations that affect our ability to generate the cash flow
necessary to make cash distributions to our unitholders,
including determinations related to:
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|
purchases and sales of oil and natural gas properties and other
acquisitions and dispositions, including whether to pursue
acquisitions that may also be suitable for the Mid-Con
Affiliates, Yorktown or any Yorktown portfolio company;
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the manner in which our business is operated;
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the level of our borrowings;
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the amount, nature and timing of our capital
expenditures; and
|
9
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|
the amount of cash reserves necessary or appropriate to satisfy
our general, administrative and other expenses and debt service
requirements and to otherwise provide for the proper conduct of
our business.
|
For a more detailed description of the conflicts of interest and
fiduciary duties of our general partner, please read Risk
FactorsRisks Inherent in an Investment in Us and
Conflicts of Interest and Fiduciary Duties.
Our partnership agreement can be amended with the consent of our
general partner and the approval of the holders of a majority of
our outstanding common units (including any common units held by
affiliates of our general partner). Upon consummation of this
offering, our general partner will continue to be owned by the
Founders, and the Founders and Yorktown collectively will own
and control the voting of an aggregate of approximately 58.6% of
our outstanding common units. Assuming that we do not issue any
additional common units and the Founders and Yorktown do not
transfer their units, they will have the ability to amend our
partnership agreement, including our policy to distribute all of
our available cash to our unitholders, without the approval of
any other unitholders. Please see Risk FactorsRisks
Inherent in an Investment in Us and The Partnership
AgreementAmendment of the Partnership Agreement.
Partnership
Agreement Modification of Fiduciary Duties
Our partnership agreement limits the liability of our general
partner and reduces the fiduciary duties it owes to our
unitholders. Our partnership agreement also restricts the
remedies available to our unitholders for actions that might
otherwise constitute a breach of the fiduciary duties that our
general partner owes to our unitholders. By purchasing a common
unit, our unitholders agree to be bound by the terms of our
partnership agreement and, pursuant to the terms of our
partnership agreement, are treated as having consented to
various actions contemplated in our partnership agreement and
conflicts of interest that might otherwise be considered a
breach of fiduciary or other duties under Delaware law. Please
read Conflicts of Interest and Fiduciary
DutiesFiduciary Duties for a description of the
fiduciary duties imposed on our general partner by Delaware law,
the material modifications of these duties contained in our
partnership agreement and certain legal rights and remedies
available to our unitholders.
10
The
Offering
|
|
|
Common units offered by us |
|
5,400,000 common units, or 6,210,000 common units if the
underwriters exercise in full their option to purchase
additional common units. |
|
|
|
Units outstanding after this offering |
|
17,640,000 common units. |
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|
If the underwriters do not exercise their option to purchase
additional common units, we will issue that number of units to
the Contributing Parties at the expiration of the option period
as additional consideration in respect of the merger of Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC into Mid-Con
Energy Properties at closing. To the extent the underwriters
exercise their option to purchase up to an additional
810,000 common units, the number of common units purchased
by the underwriters pursuant to such exercise will be issued to
the public, and the remainder of the common units that are
subject to the option, if any, will be issued to the
Contributing Parties. Accordingly, the exercise of the
underwriters option will not affect the total number of
units outstanding or the amount of cash needed to pay the
initial quarterly distribution on all outstanding units. |
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In addition, our general partner will own general partner units
representing a 2.0% general partner interest in us. |
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Use of proceeds |
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We intend to use the expected net proceeds of approximately
$97.4 million from this offering, based upon the assumed
initial public offering price of $20.00 per common unit, after
deducting underwriting discounts, a structuring fee and
estimated expenses, together with borrowings of approximately
$45.0 million under our new revolving credit facility, to: |
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distribute approximately
$121.2 million to the Contributing Parties as the cash
portion of the consideration in respect of the merger of Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC into our
subsidiary at closing;
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repay in full $15.2 million of
indebtedness outstanding under our existing revolving credit
facilities; and
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acquire, for aggregate consideration of
approximately $6.0 million, certain working interests in
the Cushing Field from J&A Oil Company and Charles R.
Olmstead and interests in certain derivative contracts from
J&A Oil Company.
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After the uses described above, we do not expect that any of the
net proceeds of the offering will be available for investment in
our business. |
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If the underwriters exercise their option to purchase additional
common units in full, the additional net proceeds would be
approximately $15.1 million. The net proceeds from any
exercise of such option will be used to distribute |
11
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additional cash consideration in respect of the merger to the
Contributing Parties. Please read Use of Proceeds. |
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Cash distributions |
|
We intend to pay an initial quarterly distribution of $0.475 per
unit per quarter on all common and general partner units ($1.90
per unit on an annualized basis) to the extent we have
sufficient cash from operations, after the establishment of cash
reserves and the payment of fees and expenses. |
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There is no guarantee that unitholders will receive a quarterly
distribution from us. We do not have a legal obligation to pay
distributions at our initial quarterly distribution rate or at
any other rate except as provided in our partnership agreement.
Further, our ability to pay the initial quarterly distribution
is subject to various restrictions and other factors described
in more detail under the caption Our Cash Distribution
Policy and Restrictions on Distributions. We will prorate
the initial quarterly distribution payable for the period from
the closing of this offering through December 31, 2011,
based on the actual length of that period. |
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|
Assuming our general partner maintains its 2.0% general partner
interest in us, our partnership agreement requires that we
distribute 98.0% of our available cash each quarter to the
holders of our common units, pro rata, and 2.0% to our general
partner. |
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Unlike many publicly traded limited partnerships, our general
partner is not entitled to any incentive distributions, and we
do not have any subordinated units. |
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Pro forma cash available for distribution generated during the
year ended December 31, 2010 and the twelve months ended
September 30, 2011 was approximately $5.4 million and
$15.8 million, respectively. The amount of available cash
we will need to pay the initial quarterly distribution for four
quarters on our common units outstanding immediately after this
offering and the corresponding distributions on our general
partners 2.0% interest will be approximately
$34.2 million (or an average of approximately
$8.6 million per quarter). As a result, for the year ended
December 31, 2010, we would have generated available cash
sufficient to pay a cash distribution of $0.075 per unit per
quarter ($0.30 on an annualized basis), or approximately 15.8%
of the initial quarterly distribution on our common units during
that period. For the twelve months ended September 30,
2011, we would have generated available cash sufficient to pay a
cash distribution of $0.219 per unit per quarter ($0.878 on an
annualized basis), or approximately 46.3% of the initial
quarterly distribution on our common units during that period.
For a calculation of our ability to pay distributions to our
unitholders based on our pro forma results for the year ended
December 31, 2010 and the twelve months ended
September 30, 2011, please read Our Cash Distribution
Policy and Restrictions |
12
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on DistributionsUnaudited Pro Forma Available Cash for the
Year Ended December 31, 2010 and the Twelve Months Ended
September 30, 2011. |
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We believe, based on our financial forecast and the related
assumptions included under Our Cash Distribution Policy
and Restrictions on DistributionsEstimated Adjusted EBITDA
for the Year Ending December 31, 2012, that we will
have sufficient cash available for distribution to pay the
initial quarterly distribution of $0.475 per unit on all common
and general partner units for the four quarters ending
December 31, 2012. |
|
|
|
Issuance of additional units |
|
We can issue an unlimited number of additional units, including
units that are senior to the common units in right of
distributions, liquidation and voting, on terms and conditions
determined by our general partner, without the approval of our
unitholders. Please read Units Eligible for Future
Sale and The Partnership AgreementIssuance of
Additional Interests. |
|
|
|
Limited voting rights |
|
Our general partner will manage us and operate our business.
Unlike stockholders of a corporation, our unitholders will have
only limited voting rights on matters affecting our business.
Our unitholders will have no right to elect our general partner
or its board of directors on an annual or other continuing
basis. Our general partner may not be removed except by a vote
of the holders of at least
662/3%
of the outstanding units, including any units owned by our
general partner and its affiliates. Upon consummation of this
offering, the Founders and Yorktown will own an aggregate of
approximately 58.6% of our common units and, therefore, will be
able to prevent the removal of our general partner. Please read
The Partnership AgreementLimited Voting Rights. |
|
|
|
Limited call right |
|
If at any time our general partner and its affiliates own more
than 80% of the outstanding common units, our general partner
has the right, but not the obligation, to purchase all of the
remaining common units at a purchase price not less than the
then-current market price of the common units, as calculated
pursuant to the terms of our partnership agreement. Upon
consummation of this offering, the Founders will own an
aggregate of approximately 7.7% of our common units. Please read
The Partnership AgreementLimited Call Right. |
13
|
|
|
Eligible Holders and redemption |
|
Units held by persons who our general partner determines are not
Eligible Holders will be subject to redemption. As used herein,
an Eligible Holder means any person or entity qualified to hold
an interest in oil and natural gas leases on federal lands. If,
following a request by our general partner, a transferee or
unitholder, as the case may be, does not properly complete a
recertification for any reason, we will have the right to redeem
the units held by such person at the then-current market price
of the units held by such person. The redemption price will be
paid in cash or by delivery of a promissory note, as determined
by our general partner. Please read Description of the
Common UnitsTransfer Agent and RegistrarTransfer of
Common Units and The Partnership
AgreementNon-Citizen Unitholders; Redemption. |
|
Estimated ratio of taxable income to distributions |
|
We estimate that if our unitholders own the common units
purchased in this offering through the record date for
distributions for the period ending December 31, 2014, such
unitholders will be allocated, on a cumulative basis, an amount
of federal taxable income for that period that will be less than
40% of the cash distributed to such unitholders with respect to
that period. Please read Material Tax
ConsequencesTax Consequences of Unit OwnershipRatio
of Taxable Income to Distributions for the basis of this
estimate. |
|
Material tax consequences |
|
For a discussion of other material federal income tax
consequences that may be relevant to prospective unitholders who
are individual citizens or residents of the United States,
please read Material Tax Consequences. |
|
|
|
Listing and trading symbol |
|
We have been approved to list our common units on the NASDAQ
Global Market under the symbol MCEP. |
14
Summary
Historical and Pro Forma Financial Data
We were formed in July 2011 and do not have historical financial
operating results. Therefore, in this prospectus, we present the
historical financial statements of our predecessor, which
consist of the consolidated historical financial statements of
Mid-Con Energy Corporation through June 30, 2009 and the
combined historical financial statements of Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC, thereafter. The
following table presents summary historical financial data of
our predecessor and summary pro forma financial data of Mid-Con
Energy Partners, LP as of the dates and for the periods
indicated. The summary historical financial data as of
December 31, 2009 and 2010 and for the years ended
June 30, 2008 and 2009, the six months ended
December 31, 2009 and the year ended December 31, 2010
are derived from the audited historical financial statements of
our predecessor included elsewhere in this prospectus. The
summary historical financial data as of September 30, 2011
and for the nine months ended September 30, 2010 and 2011
are derived from the unaudited historical combined financial
statements of our predecessor included elsewhere in this
prospectus. These historical financial statements have been
restated to correct errors discovered in the calculation of
depreciation, depletion, and amortization and impairment of
proved properties for all periods prior to September 30,
2011, as well as the expensing of certain geological and
geophysical costs by Mid-Con Energy I, LLC for the six
months ended December 31, 2009.
The summary unaudited pro forma financial data as of
September 30, 2011 and for the nine months ended
September 30, 2011 and the year ended December 31,
2010 are derived from the unaudited pro forma condensed
financial statements of our predecessor included elsewhere in
this prospectus. Our unaudited pro forma condensed financial
statements give pro forma effect to the following:
|
|
|
|
|
the sale by Mid-Con Energy I, LLC and Mid-Con Energy II,
LLC of certain oil and natural gas properties representing less
than 1% of our proved reserves by value, as calculated using the
standardized measure, as of September 30, 2011, and certain
subsidiaries that do not own oil and natural gas reserves,
including Mid-Con Energy Operating, to the Mid-Con Affiliates
for aggregate consideration of $7.5 million;
|
|
|
|
|
|
the merger of Mid-Con Energy I, LLC and Mid-Con Energy II,
LLC with our wholly owned subsidiary in exchange for aggregate
consideration of 12,240,000 common units and
$121.2 million in cash;
|
|
|
|
|
|
the issuance to our general partner of 360,000 general
partner units, representing a 2.0% general partner interest in
us in exchange for a contribution from our general partner;
|
|
|
|
|
|
the issuance and sale by us to the public of
5,400,000 common units in this offering and the application
of the net proceeds as described in Use of Proceeds;
|
|
|
|
|
|
our borrowing of approximately $45.0 million under our new
credit facility and the application of the proceeds as described
in Use of Proceeds; and
|
|
|
our acquisition of additional working interests in the Cushing
Field from J&A Oil Company and Charles R. Olmstead
immediately prior to the closing of this offering.
|
The unaudited pro forma balance sheet data assume the events
listed above occurred as of September 30, 2011. The
unaudited pro forma statement of operations data for the nine
months ended September 30, 2011 and the year ended
December 31, 2010 assume the items listed above occurred as
of January 1, 2010. We have not given pro forma effect to
incremental general and administrative expenses of approximately
$3.0 million that we expect to incur annually as a result
of being a publicly traded partnership.
You should read the following table in conjunction with
Formation Transactions and Partnership
Structure, Use of Proceeds,
Managements Discussion and Analysis of Financial
Condition and Results of Operations, the historical
combined financial statements of our predecessor and the
unaudited pro forma condensed financial statements of Mid-Con
Energy Partners, LP and the notes thereto included elsewhere in
this prospectus. Among other things, those historical financial
statements and unaudited pro forma condensed financial
statements include more detailed information regarding the basis
of presentation for the following information.
15
The following table presents a non-GAAP financial measure,
Adjusted EBITDA, which we use in evaluating the financial
performance and liquidity of our business. This measure is not
calculated or presented in accordance with generally accepted
accounting principles, or GAAP. We explain this measure below
and reconcile it to the most directly comparable financial
measures calculated and presented in accordance with GAAP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Con Energy
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners, LP
|
|
|
|
|
|
|
|
|
|
|
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
(combined)
|
|
|
Pro Forma
|
|
|
|
Mid-Con Energy Corporation
|
|
|
|
Six Months
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
|
Nine Months
|
|
|
|
(consolidated)
|
|
|
|
Ended
|
|
|
Year Ended
|
|
|
Nine Months Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Year Ended June 30,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
September 30,
|
|
Statement of Operations
Data:
|
|
2008
|
|
|
2009
|
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
(in thousands)
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
(restated)
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
13,667
|
|
|
$
|
10,246
|
|
|
|
$
|
5,729
|
|
|
$
|
16,853
|
|
|
$
|
11,390
|
|
|
$
|
25,068
|
|
|
$
|
16,286
|
|
|
$
|
25,040
|
|
Natural gas sales
|
|
|
618
|
|
|
|
2,172
|
|
|
|
|
743
|
|
|
|
1,418
|
|
|
|
1,104
|
|
|
|
974
|
|
|
|
1,397
|
|
|
|
978
|
|
Realized loss on derivatives, net
|
|
|
(804
|
)
|
|
|
(669
|
)
|
|
|
|
(350
|
)
|
|
|
(90
|
)
|
|
|
(87
|
)
|
|
|
(799
|
)
|
|
|
(100
|
)
|
|
|
(875
|
)
|
Unrealized gain (loss) on derivatives, net
|
|
|
(2,035
|
)
|
|
|
1,679
|
|
|
|
|
(147
|
)
|
|
|
(707
|
)
|
|
|
182
|
|
|
|
9,400
|
|
|
|
(707
|
)
|
|
|
9,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
11,446
|
|
|
|
13,428
|
|
|
|
|
5,975
|
|
|
|
17,474
|
|
|
|
12,589
|
|
|
|
34,643
|
|
|
|
16,876
|
|
|
|
34,543
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
5,005
|
|
|
|
5,369
|
|
|
|
|
2,431
|
|
|
|
6,237
|
|
|
|
4,654
|
|
|
|
5,951
|
|
|
|
5,041
|
|
|
|
5,600
|
|
Oil and gas production taxes
|
|
|
946
|
|
|
|
631
|
|
|
|
|
269
|
|
|
|
822
|
|
|
|
522
|
|
|
|
1,116
|
|
|
|
797
|
|
|
|
1,119
|
|
Dry holes and abandonments of unproved properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,418
|
|
|
|
1,053
|
|
|
|
772
|
|
|
|
514
|
|
|
|
772
|
|
Geological and geophysical
|
|
|
1,296
|
|
|
|
507
|
|
|
|
|
|
|
|
|
394
|
|
|
|
253
|
|
|
|
171
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
1,599
|
|
|
|
2,293
|
|
|
|
|
2,552
|
|
|
|
5,851
|
|
|
|
4,743
|
|
|
|
4,318
|
|
|
|
3,327
|
|
|
|
4,128
|
|
Accretion of discount on asset retirement obligations
|
|
|
56
|
|
|
|
78
|
|
|
|
|
58
|
|
|
|
127
|
|
|
|
95
|
|
|
|
55
|
|
|
|
63
|
|
|
|
55
|
|
General and administrative
|
|
|
1,871
|
|
|
|
1,767
|
|
|
|
|
704
|
|
|
|
982
|
|
|
|
708
|
|
|
|
552
|
|
|
|
982
|
|
|
|
552
|
|
Impairment of proved oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
|
9,208
|
|
|
|
1,886
|
|
|
|
|
|
|
|
|
|
|
|
1,260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
10,773
|
|
|
|
10,645
|
|
|
|
|
15,222
|
|
|
|
17,717
|
|
|
|
12,028
|
|
|
|
12,935
|
|
|
|
11,984
|
|
|
|
12,226
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
673
|
|
|
|
2,783
|
|
|
|
|
(9,247
|
)
|
|
|
(243
|
)
|
|
|
561
|
|
|
|
21,708
|
|
|
|
4,892
|
|
|
|
22,317
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expenses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income and other
|
|
|
115
|
|
|
|
119
|
|
|
|
|
35
|
|
|
|
218
|
|
|
|
208
|
|
|
|
160
|
|
|
|
126
|
|
|
|
102
|
|
Interest expense
|
|
|
(3
|
)
|
|
|
(93
|
)
|
|
|
|
(2
|
)
|
|
|
(98
|
)
|
|
|
(59
|
)
|
|
|
(378
|
)
|
|
|
(1,350
|
)
|
|
|
(1,013
|
)
|
Gain on sale of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
354
|
|
|
|
354
|
|
|
|
1,559
|
|
|
|
|
|
|
|
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,671
|
)
|
|
|
|
|
|
|
(1,671
|
)
|
Other revenue and expenses, net
|
|
|
108
|
|
|
|
298
|
|
|
|
|
118
|
|
|
|
847
|
|
|
|
501
|
|
|
|
576
|
|
|
|
|
|
|
|
|
|
Income tax expensecurrent
|
|
|
|
|
|
|
(625
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (expense) benefitdeferred
|
|
|
(261
|
)
|
|
|
502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
632
|
|
|
$
|
2,984
|
|
|
|
$
|
(9,096
|
)
|
|
$
|
1,078
|
|
|
$
|
1,565
|
|
|
$
|
21,954
|
|
|
$
|
3,668
|
|
|
$
|
19,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
0.20
|
|
|
$
|
1.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of limited partner units outstanding
(basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,640
|
|
|
|
17,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
4,471
|
|
|
$
|
3,773
|
|
|
|
$
|
2,836
|
|
|
$
|
10,593
|
|
|
$
|
6,771
|
|
|
$
|
18,029
|
|
|
$
|
10,763
|
|
|
$
|
17,872
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
4,221
|
|
|
$
|
10,935
|
|
|
|
$
|
965
|
|
|
$
|
11,798
|
|
|
$
|
10,269
|
|
|
$
|
14,554
|
|
|
|
|
|
|
|
|
|
Investing activities
|
|
|
(7,646
|
)
|
|
|
(12,448
|
)
|
|
|
|
(5,018
|
)
|
|
|
(22,726
|
)
|
|
|
(15,922
|
)
|
|
|
(24,881
|
)
|
|
|
|
|
|
|
|
|
Financing activities
|
|
|
147
|
|
|
|
4,841
|
|
|
|
|
(1,164
|
)
|
|
|
10,387
|
|
|
|
5,133
|
|
|
|
10,291
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Con Energy I, LLC and
|
|
|
|
|
|
Mid-Con
|
|
|
|
|
|
|
|
|
|
|
Mid-Con Energy II, LLC
|
|
|
|
|
|
Energy Partners, LP
|
|
|
|
|
|
|
|
|
|
|
(combined)
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
|
|
As of September 30,
|
|
|
|
|
|
As of September 30,
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
2011
|
|
|
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital(1)
|
|
|
$
|
2,420
|
|
|
$
|
(1,256
|
)
|
|
|
|
|
|
$
|
6,819
|
|
|
|
|
|
|
$
|
5,236
|
|
Total assets
|
|
|
|
40,496
|
|
|
|
56,867
|
|
|
|
|
|
|
|
88,682
|
|
|
|
|
|
|
|
92,377
|
|
Total debt
|
|
|
|
337
|
|
|
|
5,513
|
|
|
|
|
|
|
|
15,210
|
|
|
|
|
|
|
|
45,000
|
|
Partners capital
|
|
|
|
36,779
|
|
|
|
43,072
|
|
|
|
|
|
|
|
69,955
|
|
|
|
|
|
|
|
43,860
|
|
|
|
|
(1)
|
|
For 2010, excludes
$5.3 million of current maturities under our
predecessors credit facilities. The maturity date for
these facilities was subsequently extended to December 2013.
|
16
Non-GAAP Financial
Measures
We include in this prospectus the non-GAAP financial measure
Adjusted EBITDA and provide our calculation of Adjusted EBITDA
and a reconciliation of Adjusted EBITDA to net income and net
cash from operating activities, our most directly comparable
financial measures calculated and presented in accordance with
GAAP. We define Adjusted EBITDA as net income (loss):
|
|
|
|
|
income tax expense (benefit), if any;
|
|
|
|
interest expense;
|
|
|
|
depreciation, depletion and amortization;
|
|
|
|
accretion of discount on asset retirement obligations;
|
|
|
|
unrealized losses on commodity derivative contracts;
|
|
|
|
impairment expenses;
|
|
|
|
dry hole costs and abandonments of unproved properties;
|
|
|
|
stock-based compensation; and
|
|
|
|
loss on sale of assets;
|
|
|
|
|
|
interest income;
|
|
|
|
unrealized gains on commodity derivative contracts; and
|
|
|
|
gain on sale of assets.
|
Adjusted EBITDA is used as a supplemental financial measure by
our management and by external users of our financial
statements, such as industry analysts, investors, lenders,
rating agencies and others, to assess:
|
|
|
|
|
the cash flow generated by our assets, without regard to
financing methods, capital structure or historical cost
basis; and
|
|
|
|
our ability to incur and service debt and fund capital
expenditures.
|
In addition, management uses Adjusted EBITDA to evaluate actual
cash flow available to pay distributions to our unitholders,
develop existing reserves or acquire additional oil properties.
Adjusted EBITDA should not be considered an alternative to net
income, operating income, cash flow from operating activities or
any other measure of financial performance or liquidity
presented in accordance with GAAP. Our Adjusted EBITDA may not
be comparable to similarly titled measures of another company
because all companies may not calculate Adjusted EBITDA in the
same manner. The following table presents our reconciliation of
Adjusted EBITDA to Net Income. The table below further presents
a reconciliation of Adjusted EBITDA to cash flow from operating
activities, our most directly comparable GAAP financial measure,
for each of the periods indicated.
17
Reconciliation
of Adjusted EBITDA to Net Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Con Energy I, LLC and
|
|
|
Mid-Con Energy
|
|
|
|
|
|
|
|
|
|
|
Mid-Con Energy II, LLC
|
|
|
Partners, LP
|
|
|
|
Mid-Con Energy
|
|
|
|
(combined)
|
|
|
Pro Forma
|
|
|
|
Corporation
|
|
|
|
Six Months
|
|
|
Year
|
|
|
Nine Months
|
|
|
Nine Months
|
|
|
Year
|
|
|
Nine Months
|
|
|
|
(consolidated)
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Year Ended June 30,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
September 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
(in thousands)
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
632
|
|
|
$
|
2,984
|
|
|
|
$
|
(9,096
|
)
|
|
$
|
1,078
|
|
|
$
|
1,565
|
|
|
$
|
21,954
|
|
|
$
|
3,668
|
|
|
$
|
19,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit)deferred
|
|
|
261
|
|
|
|
(502
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expensecurrent
|
|
|
|
|
|
|
625
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
3
|
|
|
|
93
|
|
|
|
|
2
|
|
|
|
98
|
|
|
|
59
|
|
|
|
378
|
|
|
|
1,350
|
|
|
|
1,013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
1,599
|
|
|
|
2,293
|
|
|
|
|
2,552
|
|
|
|
5,851
|
|
|
|
4,743
|
|
|
|
4,318
|
|
|
|
3,327
|
|
|
|
4,128
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of discount on asset retirement obligations
|
|
|
56
|
|
|
|
78
|
|
|
|
|
58
|
|
|
|
127
|
|
|
|
95
|
|
|
|
55
|
|
|
|
63
|
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized (gain) loss on derivatives, net
|
|
|
2,035
|
|
|
|
(1,679
|
)
|
|
|
|
147
|
|
|
|
707
|
|
|
|
(182
|
)
|
|
|
(9,400
|
)
|
|
|
707
|
|
|
|
(9,400
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of proved oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
|
9,208
|
|
|
|
1,886
|
|
|
|
|
|
|
|
|
|
|
|
1,260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dry holes and abandonments of unproved properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,418
|
|
|
|
1,053
|
|
|
|
772
|
|
|
|
514
|
|
|
|
772
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sales of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(354
|
)
|
|
|
(354
|
)
|
|
|
(1,559
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,671
|
|
|
|
|
|
|
|
1,671
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
(115
|
)
|
|
|
(119
|
)
|
|
|
|
(35
|
)
|
|
|
(218
|
)
|
|
|
(208
|
)
|
|
|
(160
|
)
|
|
|
(126
|
)
|
|
|
(102
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
4,471
|
|
|
$
|
3,773
|
|
|
|
$
|
2,836
|
|
|
$
|
10,593
|
|
|
$
|
6,771
|
|
|
$
|
18,029
|
|
|
$
|
10,763
|
|
|
$
|
17,872
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Adjusted
EBITDA to Net Cash Provided by Operating
Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Con Energy I, LLC and
|
|
|
|
|
|
|
|
|
|
Mid-Con
|
|
|
|
Mid-Con Energy II, LLC
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
|
(combined)
|
|
|
|
|
|
|
|
|
|
Corporation
|
|
|
|
Six Months
|
|
|
Year
|
|
|
Nine Months
|
|
|
Nine Months
|
|
|
|
|
|
|
|
|
|
(consolidated)
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
|
|
|
|
|
|
Year Ended June 30,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
4,221
|
|
|
$
|
10,935
|
|
|
|
$
|
965
|
|
|
$
|
11,798
|
|
|
$
|
10,269
|
|
|
$
|
14,554
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in working capital
|
|
|
521
|
|
|
|
(7,761
|
)
|
|
|
|
1,904
|
|
|
|
(1,085
|
)
|
|
|
(3,349
|
)
|
|
|
3,257
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expensecurrent
|
|
|
|
|
|
|
625
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bad debt expense
|
|
|
(159
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
3
|
|
|
|
93
|
|
|
|
|
2
|
|
|
|
98
|
|
|
|
59
|
|
|
|
378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
(115
|
)
|
|
|
(119
|
)
|
|
|
|
(35
|
)
|
|
|
(218
|
)
|
|
|
(208
|
)
|
|
|
(160
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
4,471
|
|
|
$
|
3,773
|
|
|
|
$
|
2,836
|
|
|
$
|
10,593
|
|
|
$
|
6,771
|
|
|
$
|
18,029
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
Summary
Pro Forma and Historical Reserve and Operating Data
The following table presents summary data with respect to the
estimated net proved oil and natural gas reserves that we will
own at the closing of this offering and the standardized measure
amounts associated with those estimated proved reserves as of
December 31, 2010 and as of September 30, 2011, both
based on reserve reports prepared by our internal reserve
engineers and audited by Cawley, Gillespie &
Associates, Inc., our independent reserve engineers. Our
estimated proved reserves as of December 31, 2010 are
presented on a pro forma basis and exclude certain properties of
our predecessor that were sold to the Mid-Con Affiliates on
June 30, 2011. The properties we sold represented less than
1% of our proved reserves by value, as calculated using the
standardized measure, as of September 30, 2011.
These reserve estimates were prepared in accordance with the
SECs rules regarding oil and natural gas reserve reporting
that are currently in effect. Our proved developed reserves
increased by 83% from December 31, 2010 to September 30, 2011 as
a result of development drilling and production responses to
waterflooding which exceeded our December 31, 2010 estimates in
our Southern Oklahoma core area; acquisition of the War
Party I and II Units in the Hugoton Basin; and
acquisitions, infill drilling, expansion of waterflood
operations and workovers in our Northeastern Oklahoma core area.
We spent a total of $19.3 million and $31.2 million in capital
expenditures for the year ended December 31, 2010 and the nine
months ended September 30, 2011, respectively, which contributed
to increasing the September 30, 2011 reserves.
During the first nine months of 2011, we spent approximately
$16.4 million in the Southern Oklahoma core area resulting in
production increases and reclassifications of 1.5 million
barrels from proved undeveloped reserves to proved developed
reserves. Additionally, we spent approximately $9.4 million
during the first nine months of 2011 to acquire new leases in
the Hugoton Basin and Northeastern Oklahoma, with proved
developed reserves of approximately 0.9 million barrels. Another
$0.7 million was spent on workover activities and $0.6 million
on drilling during the first nine months of 2011 in Northeastern
Oklahoma, adding 0.5 million barrels to proved developed
reserves.
For a discussion of risks associated with internal reserve
estimates, please read Risk FactorsRisks Related to
Our BusinessOur estimated proved reserves and future
production rates are based on many assumptions that may prove to
be inaccurate. Any material inaccuracies in these reserve
estimates or underlying assumptions will materially affect the
quantities and present value of our estimated reserves.
Please also read Managements Discussion and Analysis
of Financial Condition and Results of Operations,
Business and PropertiesOil and Natural Gas Reserves
and ProductionEstimated Proved Reserves, and the
summary of our
19
pro forma reserve reports dated December 31, 2010 and
September 30, 2011 included in this prospectus in
evaluating the material presented below.
|
|
|
|
|
|
|
|
|
|
|
Pro Forma as of
|
|
|
Pro Forma as of
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2010(1)
|
|
|
2011(2)
|
|
|
Reserve Data:
|
|
|
|
|
|
|
|
|
Estimated proved reserves:
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
6,938
|
|
|
|
9,730
|
|
Natural Gas (MMcf)
|
|
|
1,070
|
|
|
|
1,069
|
|
|
|
|
|
|
|
|
|
|
Total (Mboe)
|
|
|
7,116
|
|
|
|
9,908
|
|
|
|
|
|
|
|
|
|
|
Proved developed (MBoe)
|
|
|
3,710
|
|
|
|
6,801
|
|
Oil (MBbl)
|
|
|
3,531
|
|
|
|
6,619
|
|
Natural Gas (MMcf)
|
|
|
1,082
|
|
|
|
1,093
|
|
Proved undeveloped (MBoe)
|
|
|
3,406
|
|
|
|
3,107
|
|
Oil (MBbl)
|
|
|
3,407
|
|
|
|
3,111
|
|
Natural Gas (MMcf)
|
|
|
(12
|
)
|
|
|
(24
|
)
|
Proved developed reserves as a percentage of total proved
reserves
|
|
|
52.1
|
%
|
|
|
68.6
|
%
|
Standardized Measure (in millions)(3)
|
|
$
|
182.1
|
|
|
$
|
312.0
|
|
Oil and Natural Gas Prices(4):
|
|
|
|
|
|
|
|
|
Oil NYMEX WTI per Bbl
|
|
$
|
79.43
|
|
|
$
|
94.50
|
|
Natural gas NYMEX Henry Hub per MMBtu
|
|
$
|
4.37
|
|
|
$
|
4.17
|
|
|
|
|
(1)
|
|
Excludes certain properties, which
represented less than 1% of our proved reserves by value, as
calculated using the standardized measure, as of
September 30, 2011, that were sold to the Mid-Con
Affiliates on June 30, 2011.
|
|
|
|
(2)
|
|
Includes the working interests to
be acquired from J&A Oil Company and Charles R. Olmstead
immediately prior to the closing of this offering.
|
|
(3)
|
|
Standardized measure is calculated
in accordance with Statement of Financial Accounting Standards
No. 69, Disclosures About Oil and Gas Producing Activities,
as codified in ASC Topic 932, Extractive ActivitiesOil
and Gas. Because we were not subject to federal or state
income taxes for the periods presented, we make no provision for
federal or state income taxes in the calculation of our
standardized measure. For a description of our commodity
derivative contracts, please read Managements
Discussion and Analysis of Financial Condition and Results of
OperationsLiquidity and Capital ResourcesDerivative
Contracts.
|
|
|
|
(4)
|
|
Our estimated net proved reserves
and related standardized measure were determined using index
prices for oil and natural gas, without giving effect to
commodity derivative contracts, held constant throughout the
life of the properties. The unweighted arithmetic average
first-day-of-the-month
prices for the prior twelve months were $79.43 per Bbl for oil
and $4.37 per MMBtu for natural gas at December 31, 2010
and $94.50 per Bbl for oil and $4.17 per MMBtu for natural gas
at September 30, 2011. These prices were adjusted by lease
for quality, transportation fees, location differentials,
marketing bonuses or deductions and other factors affecting the
price received at the wellhead. For the year ended
December 31, 2010, the relevant average realized prices for
oil and natural gas were $74.15 per Bbl and $7.58 per Mcf,
respectively, on a pro forma basis. For the nine months ended
September 30, 2011, the relevant average realized prices
for oil and natural gas were $90.22 per Bbl and $7.83 per Mcf,
respectively, on a pro forma basis. Realized natural gas sales
price per Mcf includes the sale of natural gas liquids for both
the year ended December 31, 2010 and the nine months ended
September 30, 2011.
|
20
|
|
|
|
|
|
|
|
|
|
|
Pro Forma(1)
|
|
|
|
|
Nine Months
|
|
|
Year Ended
|
|
Ended
|
|
|
December 31,
|
|
September 30,
|
|
|
2010
|
|
2011
|
|
|
(restated)
|
|
|
|
Production and operating data:
|
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
220
|
|
|
|
278
|
|
Natural gas (MMcf)
|
|
|
184
|
|
|
|
125
|
|
Total (MBoe)
|
|
|
250
|
|
|
|
298
|
|
Average net production (Boe/d)
|
|
|
686
|
|
|
|
1,093
|
|
Average sales price:(2)
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
74.15
|
|
|
$
|
90.22
|
|
Natural gas (per Mcf)(3)
|
|
$
|
7.58
|
|
|
$
|
7.83
|
|
Average price per Boe
|
|
$
|
70.64
|
|
|
$
|
87.20
|
|
Average unit costs per Boe:
|
|
|
|
|
|
|
|
|
Oil and natural gas production expenses
|
|
$
|
20.14
|
|
|
$
|
18.77
|
|
Production taxes
|
|
$
|
3.18
|
|
|
$
|
3.75
|
|
General and administrative and other(4)
|
|
$
|
3.92
|
|
|
$
|
1.85
|
|
Depreciation, depletion and amortization
|
|
$
|
13.29
|
|
|
$
|
13.84
|
|
|
|
|
(1)
|
|
Excludes production from certain
properties, which represent less than 1% of our proved reserves
by value, as calculated using the standardized measure, as of
September 30, 2011, that were sold to the Mid-Con
Affiliates on June 30, 2011.
|
|
|
|
(2)
|
|
Prices do not include the effects
of derivative cash settlements.
|
|
(3)
|
|
Realized natural gas sales price
per Mcf includes the sale of natural gas liquids.
|
|
(4)
|
|
Pro forma general and
administrative expenses do not include the additional expenses
we would have incurred as a publicly traded partnership. We
estimate these additional expenses would have been
$3.0 million, or $11.99 per Boe, for the year ended
December 31, 2010 and $2.3 million, or $7.72 per Boe,
for the nine months ended September 30, 2011 on a pro forma
basis.
|
21
RISK
FACTORS
Limited partner interests are inherently different from the
capital stock of a corporation. Prospective unitholders should
carefully consider the following risk factors together with all
of the other information included in this prospectus in
evaluating an investment in our common units.
If any of the following risks were actually to occur, our
business, financial condition or results of operations could be
materially adversely affected. In that case, we might not be
able to pay distributions on our common units, the trading price
of our common units could decline and our unitholders could lose
all or part of their investment.
Risks
Related to Our Business
We may not have sufficient cash to pay the initial
quarterly distribution on our units following the establishment
of cash reserves and payment of expenses, including payments to
our general partner.
We may not have sufficient available cash each quarter to pay
the initial quarterly distribution of $0.475 per unit (or
$8.6 million in the aggregate), or any distribution at all,
on our units. Under the terms of our partnership agreement, the
amount of cash available for distribution will be reduced by our
operating expenses and the amount of any cash reserves
established by our general partner to provide for future
operations, future capital expenditures, including development
of our oil and natural gas properties, future debt service
requirements and future cash distributions to our unitholders.
The amount of cash that we distribute to our unitholders will
depend principally on the cash we generate from operations,
which will depend on, among other factors:
|
|
|
|
|
the amount of oil and natural gas we produce;
|
|
|
|
the prices at which we sell our oil and natural gas production;
|
|
|
|
the amount and timing of settlements on our commodity derivative
contracts;
|
|
|
|
the level of our capital expenditures, including scheduled and
unexpected maintenance expenditures;
|
|
|
|
the level of our operating costs, including payments to our
general partner; and
|
|
|
|
the level of our interest expense, which will depend on the
amount of our outstanding indebtedness and the applicable
interest rate.
|
Further, the amount of cash we have available for distribution
depends primarily on our cash flow, including cash from
financial reserves and borrowings, and not solely on
profitability, which will be affected by non-cash items. As a
result, we may make cash distributions during periods when we
record losses for financial accounting purposes and may not make
cash distributions during periods when we record net income for
financial accounting purposes.
We would not have generated sufficient available cash on a
pro forma basis to have paid the initial quarterly distribution
on all of our units for the twelve months ended
September 30, 2011.
On a pro forma historical basis, assuming we had completed our
formation transactions on October 1, 2010, our unaudited
pro forma available cash generated during the twelve months
ended September 30, 2011 would have been approximately
$15.8 million, which would have been sufficient to pay only
46.3% of the aggregate initial quarterly distribution on our
common units. For a calculation of our ability to have made
distributions to our unitholders based on our pro forma results
of operations for the year ended December 31, 2010 and the
twelve months ended September 30, 2011, please read
Our Cash Distribution Policy and Restrictions on
22
DistributionsUnaudited Pro Forma Available Cash for the
Year Ended December 31, 2010 and the Twelve Months Ended
September 30, 2011.
The assumptions underlying the forecast of cash available
for distribution we include in Our Cash Distribution
Policy and Restrictions on Distributions may prove
inaccurate and are subject to significant risks and
uncertainties that could cause actual results to differ
materially from our forecasted results.
Our managements forecast of cash available for
distribution set forth in Our Cash Distribution Policy and
Restrictions on Distributions includes our forecasted
results of operations, Adjusted EBITDA and cash available for
distribution for the twelve months ending December 31,
2012. The assumptions underlying the forecast may prove
inaccurate and are subject to significant risks and
uncertainties that could cause actual results to differ
materially from those forecasted. If our actual results are
significantly below forecasted results, we may not generate
enough cash available for distribution to pay the initial
quarterly distribution, or any distribution at all, on our
common units, which may cause the market price of our common
units to decline materially. For prospective financial
information regarding our ability to pay the initial quarterly
distribution on our common units and general partner units for
the twelve months ending December 31, 2012, please read
Our Cash Distribution Policy and Restrictions on
DistributionsEstimated Adjusted EBITDA for the Year Ending
December 31, 2012.
Unless we replace the oil reserves we produce, our
revenues and production will decline, which would adversely
affect our cash flow from operations and our ability to make
distributions to our unitholders at the initial quarterly
distribution rate.
We may be unable to sustain the initial quarterly distribution
rate without substantial capital expenditures that maintain our
asset base. Producing oil reservoirs are characterized by
declining production rates that vary depending upon reservoir
characteristics and other factors. Our future oil reserves and
production and, therefore, our cash flow and ability to make
distributions are highly dependent on our success in efficiently
developing and exploiting our current reserves. Our production
decline rates may be significantly higher than currently
estimated if our wells do not produce as expected. Further, our
decline rate may change when we make acquisitions. We may not be
able to develop, find or acquire additional reserves to replace
our current and future production on economically acceptable
terms, which would adversely affect our business, financial
condition and results of operations and reduce cash available
for distribution to our unitholders.
Our operations may require substantial capital
expenditures, which could reduce our cash available for
distribution and could materially affect our ability to make
distributions to our unitholders.
We may be required to make substantial capital expenditures from
time to time in connection with the production of our oil
reserves. Further, if the borrowing base under our new credit
facility or our revenues decrease as a result of lower oil
prices, declines in estimated reserves or production or for any
other reason, we may have limited ability to obtain the capital
necessary to sustain our operations at the expected levels so as
to generate an amount of cash necessary to make distributions to
our unitholders.
Developing and producing oil is a costly and high-risk
activity with many uncertainties that could adversely affect our
financial condition or results of operations and, as a result,
our ability to pay distributions to our unitholders.
The cost of developing and operating oil properties,
particularly under a waterflood, is often uncertain, and cost
and timing factors can adversely affect the economics of a well.
Our efforts may be uneconomical if our properties are productive
but do not produce as much oil as we had
23
estimated. Furthermore, our producing operations may be
curtailed, delayed or canceled as a result of other factors,
including:
|
|
|
|
|
high costs, shortages or delivery delays of equipment, labor or
other services;
|
|
|
|
unexpected operational events and conditions;
|
|
|
|
adverse weather conditions and natural disasters;
|
|
|
|
injection plant or other facility or equipment malfunctions and
equipment failures or accidents;
|
|
|
|
unitization difficulties;
|
|
|
|
pipe or cement failures, casing collapses or other downhole
failures;
|
|
|
|
lost or damaged oilfield service tools;
|
|
|
|
unusual or unexpected geological formations and reservoir
pressure;
|
|
|
|
loss of injection fluid circulation;
|
|
|
|
costs or delays imposed by or resulting from compliance with
regulatory requirements;
|
|
|
|
fires, blowouts, surface craterings, explosions and other
hazards that could also result in personal injury and loss of
life, pollution and suspension of operations; and
|
|
|
|
uncontrollable flows of oil well fluids.
|
If any of these factors were to occur with respect to a
particular property, we could lose all or a part of our
investment in the property, or we could fail to realize the
expected benefits from the property, either of which could
materially and adversely affect our revenue and cash available
for distribution to our unitholders.
We inject water into most of our properties to maintain and, in
some instances, to increase the production of oil. We may in the
future employ other secondary or tertiary recovery methods in
our operations. The additional production and reserves
attributable to the use of secondary recovery methods and of
tertiary recovery methods are inherently difficult to predict.
If our recovery methods do not result in expected production
levels, we may not realize an acceptable return on the
investments we make to use such methods.
Hydraulic fracturing has been a part of the completion process
for the majority of the wells on our producing properties, and
most of our properties are dependent on our ability to
hydraulically fracture the producing formations. We engage
third-party contractors to provide hydraulic fracturing services
and generally enter into service orders on a job-by-job basis.
Some such service orders limit the liability of these
contractors. Hydraulic fracturing operations can result in
surface spillage or, in rare cases, the underground migration of
fracturing fluids. Any such spillage or migration could result
in litigation, government fines and penalties or remediation or
restoration obligations. Our current insurance policies provide
some coverage for losses arising out of our hydraulic fracturing
operations. However, these policies may not cover fines,
penalties or costs and expenses related to government-mandated
clean-up activities, and total losses related to a spill or
migration could exceed our per occurrence or aggregate policy
limits. Any losses due to hydraulic fracturing that are not
fully covered by insurance could have a material adverse effect
on our financial position, results of operations and cash flows.
24
A decline in oil prices, or an increase in the
differential between the NYMEX or other benchmark prices of oil
and the wellhead price we receive for our production, will cause
a decline in our cash flow from operations, which could cause us
to reduce our distributions or cease paying distributions
altogether.
Lower oil prices may decrease our revenues and, therefore, our
cash available for distribution to our unitholders.
Historically, oil prices have been extremely volatile. For
example, for the five years ended December 31, 2010, the
NYMEXWTI oil price ranged from a high of $145.29 per Bbl
to a low of $33.87 per Bbl. A significant decrease in commodity
prices may cause us to reduce the distributions we pay to our
unitholders or to cease paying distributions altogether.
Also, the prices that we receive for our oil production often
reflect a regional discount, based on the location of the
production, to the relevant benchmark prices that are used for
calculating hedge positions, such as NYMEX. These discounts, if
significant, could similarly reduce our cash available for
distribution to our unitholders and adversely affect our
financial condition.
If commodity prices decline and remain depressed for a
prolonged period, production from a significant portion of our
oil properties may become uneconomic and cause write downs of
the value of such oil properties, which may adversely affect our
financial condition and our ability to make distributions to our
unitholders.
Significantly lower oil prices may render many of our
development projects uneconomic and result in a downward
adjustment of our reserve estimates, which would negatively
impact our borrowing base and ability to borrow to fund our
operations or make distributions to our unitholders. As a
result, we may reduce the amount of distributions paid to our
unitholders or cease paying distributions. In addition, a
significant or sustained decline in oil prices could hinder our
ability to effectively execute our hedging strategy. For
example, during a period of declining commodity prices, we may
enter into commodity derivative contracts at relatively
unattractive prices in order to mitigate a potential decrease in
our borrowing base upon a redetermination.
Further, deteriorating commodity prices may cause us to
recognize impairments in the value of our oil properties. In
addition, if our estimates of drilling costs increase,
production data factors change or drilling results deteriorate,
accounting rules may require us to write down, as a non-cash
charge to earnings, the carrying value of our oil properties as
impairments. We may incur impairment charges in the future,
which could have a material adverse effect on our results of
operations in the period taken.
Our hedging strategy may be ineffective in removing the
impact of commodity price volatility from our cash flow, which
could result in financial losses or could reduce our income,
which may adversely affect our ability to pay distributions to
our unitholders.
We expect to enter into commodity derivative contracts at times
and on terms designed to maintain, over the long-term, a
portfolio covering approximately 50% to 80% of our estimated oil
production from proved reserves over a three-to-five year
period at any given point of time, although we may from time to
time hedge more or less than this approximate range. The prices
at which we are able to enter into commodity derivative
contracts covering our production in the future will be
dependent upon oil prices at the time we enter into these
transactions, which may be substantially higher or lower than
current oil prices. Accordingly, our price hedging strategy may
not protect us from significant declines in oil prices received
for our future production.
In addition, our new credit facility may hinder our ability to
effectively execute our hedging strategy. To the extent our new
credit facility limits the maximum percentage of our production
that we can hedge or the duration of those hedges, we may be
unable to enter into additional commodity derivative contracts
during favorable market conditions and, thus, unable to lock in
attractive future prices for our product sales. Conversely,
while our new credit facility will not require us to hedge a
minimum percentage of our production, it may cause us to enter
into
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commodity derivative contracts at inopportune times. For
example, during a period of declining commodity prices, we may
enter into commodity derivative contracts at relatively
unattractive prices in order to mitigate a potential decrease in
our borrowing base upon a redetermination.
Our hedging activities could result in cash losses, could
reduce our cash available for distribution and may limit the
prices we would otherwise realize for our production.
Many of the derivative contracts that we will be a party to will
require us to make cash payments to the extent the applicable
index exceeds a predetermined price, thereby limiting our
ability to realize the benefit of increases in oil prices. If
our actual production and sales for any period are less than our
hedged production and sales for that period (including
reductions in production due to operational delays), we might be
forced to satisfy all or a portion of our hedging obligations
without the benefit of the cash flow from our sale of the
underlying physical commodity, which may materially impact our
liquidity and our cash available for distribution to our
unitholders.
Our hedging transactions expose us to counterparty credit
risk.
Our hedging transactions expose us to risk of financial loss if
a counterparty fails to perform under a derivative contract.
Disruptions in the financial markets could lead to sudden
decreases in a counterpartys liquidity, which could make
them unable to perform under the terms of the derivative
contract and we may not be able to realize the benefit of the
derivative contract.
Our estimated proved reserves and future production rates
are based on many assumptions that may prove to be inaccurate.
Any material inaccuracies in these reserve estimates or
underlying assumptions will materially affect the quantities and
present value of our estimated reserves.
It is not possible to measure underground accumulations of oil
in an exact way. Oil reserve engineering is complex, requiring
subjective estimates of underground accumulations of oil and
assumptions concerning future oil prices, future production
levels and operating and development costs.
As a result, estimated quantities of proved reserves,
projections of future production rates and the timing of
development expenditures may prove inaccurate. For example, if
the prices used in our December 31, 2010 reserve reports had
been $10.00 less per barrel for oil, the standardized measure of
our estimated proved reserves, without asset retirement
obligations, as of that date on a pro forma basis would have
decreased by $33.3 million, from $183.2 million to $149.9
million.
Any material inaccuracies in these reserve estimates or
underlying assumptions will materially affect the quantities and
present value of our reserves which could affect our business,
results of operations and financial condition and our ability to
make distributions to our unitholders.
The standardized measure of our estimated proved reserves
is not necessarily the same as the current market value of our
estimated proved oil reserves.
The present value of future net cash flow from our proved
reserves, or standardized measure, may not represent the current
market value of our estimated proved oil reserves. In accordance
with SEC requirements, we base the estimated discounted future
net cash flow from our estimated proved reserves on the
12-month
average oil index prices, calculated as the unweighted
arithmetic average for the
first-day-of-the-month
price for each month and costs in effect as of the date of the
estimate, holding the prices and costs constant throughout the
life of the properties.
Actual future prices and costs may differ materially from those
used in the net present value estimate, and future net present
value estimates using then current prices and costs may be
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significantly less than current estimates. In addition, the 10%
discount factor we use when calculating discounted future net
cash flow for reporting requirements in compliance with
Accounting Standards Codification 932, Extractive
ActivitiesOil and Gas, may not be the most
appropriate discount factor based on interest rates in effect
from time to time and risks associated with us or the oil and
natural gas industry in general.
If we do not make acquisitions on economically acceptable
terms, our future growth and ability to pay or increase
distributions will be limited.
Our ability to grow and to increase distributions to our
unitholders depends in part on our ability to make acquisitions
that result in an increase in available cash per unit. We may be
unable to make such acquisitions because we are:
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unable to identify attractive acquisition candidates or
negotiate acceptable purchase contracts with their owners;
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unable to obtain financing for these acquisitions on
economically acceptable terms; or
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outbid by competitors.
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If we are unable to acquire properties containing estimated
proved reserves, our total level of estimated proved reserves
will decline as a result of our production, and we will be
limited in our ability to increase or possibly even to maintain
our level of cash distributions to our unitholders.
Any acquisitions we complete are subject to substantial
risks that could reduce our ability to make distributions to
unitholders.
One of our growth strategies is to capitalize on opportunistic
acquisitions of oil reserves. Even if we make acquisitions that
we believe will increase available cash per unit, these
acquisitions may nevertheless result in a decrease in available
cash per unit. Any acquisition involves potential risks,
including, among other things:
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the validity of our assumptions about estimated proved reserves,
future production, commodity prices, revenues, operating
expenses and costs;
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an inability to successfully integrate the assets we acquire;
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a decrease in our liquidity by using a significant portion of
our available cash or borrowing capacity to finance acquisitions;
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a significant increase in our interest expense or financial
leverage if we incur additional debt to finance acquisitions;
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the assumption of unknown liabilities, losses or costs for which
we are not indemnified or for which our indemnity is inadequate;
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the diversion of managements attention from other business
concerns;
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an inability to hire, train or retain qualified personnel to
manage and operate our growing assets; and
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facts and circumstances that could give rise to significant cash
and certain non-cash charges, such as the impairment of oil
properties, goodwill or other intangible assets, asset
devaluations or restructuring charges.
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Our decision to acquire a property will depend in part on the
evaluation of data obtained from production reports and
engineering studies, geophysical and geological analyses and
seismic data and other information, the results of which are
often inconclusive and subject to various interpretations.
Also, our reviews of properties acquired from third parties (as
opposed to from the Mid-Con Affiliates) may be incomplete
because it generally is not feasible to perform an in-depth
review of
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such properties, given the time constraints imposed by most
sellers. Even a detailed review of the records associated with
properties owned by third parties may not reveal existing or
potential problems, nor will such a review permit us to become
sufficiently familiar with such properties to assess fully the
deficiencies and potential issues associated with such
properties. We may not always be able to inspect every well on
properties owned by third parties, and environmental problems,
such as groundwater contamination, are not necessarily
observable even when an inspection is undertaken.
Adverse developments in our operating areas would reduce
our ability to make distributions to our unitholders.
We only own oil and natural gas properties and related assets,
all of which are currently located in Oklahoma and Colorado. An
adverse development in the oil and natural gas business in these
geographic areas could have an impact on our results of
operations and cash available for distribution to our
unitholders.
We are primarily dependent upon a small number of
customers for our production sales and we may experience a
temporary decline in revenues and production if we lose any of
those customers.
Sales to a subsidiary of Sunoco Logistics Partners L.P., or
Sunoco Logistics, accounted for approximately 76% of our total
sales revenues for the year ended December 31, 2010 and
approximately 87% of our total sales revenues for the nine
months ended September 30, 2011. Our production is and will
continue to be marketed by our affiliate, Mid-Con Energy
Operating, under these crude oil purchase contracts. By selling
a substantial majority of our current production to Sunoco
Logistics under these contracts, we believe that we have
obtained and will continue to receive more favorable pricing
than would otherwise be available to us if smaller amounts had
been sold to several purchasers based on posted prices. To the
extent Sunoco Logistics or any other significant customer
reduces the volume of oil they purchase from us, we could
experience a temporary interruption in sales of, or may receive
a lower price for, our oil production, and our revenues and cash
available for distribution could decline which could adversely
affect our ability to make cash distributions to our unitholders
at the then-current distribution rate or at all.
In addition, a failure by Sunoco Logistics or any of our other
significant customers, or any purchasers of our production, to
perform their payment obligations to us could have a material
adverse effect on our results of operations. To the extent that
purchasers of our production rely on access to the credit or
equity markets to fund their operations, there could be an
increased risk that those purchasers could default in their
contractual obligations to us. If for any reason we were to
determine that it was probable that some or all of the accounts
receivable from any one or more of the purchasers of our
production were uncollectible, we would recognize a charge in
the earnings of that period for the probable loss and could
suffer a material reduction in our liquidity and ability to make
distributions to our unitholders.
Unitization difficulties may prevent us from developing
certain properties or greatly increase the cost of their
development.
Regulation of waterflood unit formation is typically governed by
state law. In Oklahoma, where most of our properties are
located, 63% of the leasehold and mineral owners in a proposed
unit area must consent to a unitization plan before the Oklahoma
Corporation Commission (the regulatory body which oversees
issues related to unitization and well spacing) will issue a
unitization order. We may be required to dedicate significant
amounts of time and financial resources to obtaining consents
from other owners and the necessary approvals from the Oklahoma
Corporation Commission and similar regulatory agencies in other
states. Obtaining these consents and approvals may also delay
our ability to begin developing our new waterflood projects and
may prevent us from developing our properties in the way we
desire.
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Other owners of mineral rights may object to our
waterfloods.
It is difficult to predict the movement of the injection fluids
that we use in connection with waterflooding. It is possible
that certain of these fluids may migrate out of our areas of
operations and into neighboring properties, including properties
whose mineral rights owners have not consented to participate in
our operations. This may result in litigation in which the
owners of these neighboring properties may allege, among other
things, a trespass and may seek monetary damages and possibly
injunctive relief, which could delay or even permanently halt
our development of certain of our oil properties.
We may be unable to compete effectively with larger
companies, which may adversely affect our ability to generate
sufficient revenue to allow us to pay distributions to our
unitholders at the initial quarterly distribution rate.
The oil and natural gas industry is intensely competitive, and
we compete with companies that possess and employ financial,
technical and personnel resources substantially greater than
ours. Our ability to acquire additional properties and to
discover reserves in the future will depend on our ability to
evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Many of our
larger competitors not only drill for and produce oil and
natural gas but also carry on refining operations and market
petroleum and other products on a regional, national or
worldwide basis. These companies may be able to pay more for
properties and evaluate, bid for and purchase a greater number
of properties than our financial, technical or personnel
resources permit. In addition, there is substantial competition
for investment capital in the oil and natural gas industry.
These larger companies may have a greater ability to continue
development activities during periods of low oil prices and to
absorb the burden of present and future federal, state, local
and other laws and regulations. Our inability to compete
effectively with larger companies could have a material adverse
impact on our business activities, financial condition and
results of operations and our ability to make distributions to
our unitholders.
Many of our leases are in areas that have been partially
depleted or drained by offset wells.
Many of our leases are in areas that have already been partially
depleted or drained by earlier offset drilling. The owners of
leasehold interests adjoining our interests could take actions,
such as drilling additional wells, which could adversely affect
our operations. When a new well is completed and produced, the
pressure differential in the vicinity of the well causes the
migration of reservoir fluids towards the new wellbore (and
potentially away from existing wellbores). As a result, the
drilling and production of these potential locations could cause
a depletion of our proved reserves, and may inhibit our ability
to further exploit and develop our reserves.
We may incur additional debt to enable us to pay our
quarterly distributions, which may negatively affect our ability
to pay future distributions or execute our business plan.
We may be unable to pay distributions at our initial quarterly
distribution rate or the then-current distribution rate without
borrowing under our new credit facility. If we use borrowings
under our new credit facility to pay distributions to our
unitholders for an extended period of time rather than to fund
capital expenditures and other activities relating to our
operations, we may be unable to maintain or grow our business.
Such a curtailment of our business activities, combined with our
payment of principal and interest on our future indebtedness to
pay these distributions, will reduce our cash available for
distribution on our units and will have a material adverse
effect on our business, financial condition and results of
operations. If we borrow to pay distributions to our unitholders
during periods of low commodity prices and commodity prices
remain low, we may have to reduce our distribution to our
unitholders to avoid excessive leverage.
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Our new credit facility will have restrictions and
financial covenants that may restrict our business and financing
activities and our ability to pay distributions to our
unitholders.
Our new credit facility will restrict, among other things, our
ability to incur debt and pay distributions under certain
circumstances, and will require us to comply with customary
financial covenants and specified financial ratios. If market or
other economic conditions deteriorate, our ability to comply
with these covenants may be impaired. If we violate any
provisions of our new credit facility that are not cured or
waived within specific time periods, a significant portion of
our indebtedness may become immediately due and payable, our
ability to make distributions to our unitholders will be
inhibited and our lenders commitment to make further loans
to us may terminate. We might not have, or be able to obtain,
sufficient funds to make these accelerated payments. In
addition, our obligations under our new credit facility will be
secured by substantially all of our assets, and if we are unable
to repay our indebtedness under our new credit facility, the
lenders could seek to foreclose on our assets.
The total amount we will be able to borrow under our new credit
facility will be limited by a borrowing base, which will be
primarily based on the estimated value of our oil and natural
gas properties and our commodity derivative contracts, as
determined by our lenders in their sole discretion. The
borrowing base will be subject to redetermination on a
semi-annual basis and more frequent redetermination in certain
circumstances. Any substantial or sustained decline in commodity
prices would likely lead to a decrease in our borrowing base
upon redetermination. In the future, we may be unable to access
sufficient capital under our new credit facility as a result of
a decrease in our borrowing base due to a subsequent borrowing
base redetermination.
In addition, our new credit facility may hinder our ability to
effectively execute our hedging strategy. To the extent our new
credit facility limits the maximum percentage of our production
that we can hedge or the duration of those hedges, we may be
unable to enter into additional commodity derivative contracts
during favorable market conditions and, thus, unable to lock in
attractive future prices for our product sales. Conversely, our
new credit facility may cause us to enter into commodity
derivative contracts at inopportune times. For example, during a
period of declining commodity prices, we may enter into
commodity derivative contracts at relatively unattractive prices
in order to mitigate a potential decrease in our borrowing base
upon a redetermination.
Our business depends in part on transportation, pipelines
and refining facilities owned by others. Any limitation in the
availability of those facilities could interfere with our
ability to market our production and could harm our
business.
The marketability of our production depends in part on the
availability, proximity and capacity of pipelines, tanker trucks
and other transportation methods, and refining facilities owned
by third parties. The amount of oil that can be produced and
sold is subject to curtailment in certain circumstances, such as
pipeline interruptions due to scheduled and unscheduled
maintenance, excessive pressure, physical damage or lack of
available capacity on such systems, tanker truck availability
and extreme weather conditions. The curtailments arising from
these and similar circumstances may last from a few days to
several months. In many cases, we are provided only with
limited, if any, notice as to when these circumstances will
arise and their duration. Any significant curtailment in
gathering system or transportation or refining facility capacity
could reduce our ability to market our oil production and harm
our business. Our access to transportation options can also be
affected by federal and state regulation of oil production and
transportation, general economic conditions and changes in
supply and demand. In addition, the third parties on whom we
rely for transportation services are subject to complex federal,
state, tribal and local laws that could adversely affect the
cost, manner or feasibility of conducting our business.
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Climate change legislation, regulatory initiatives and
litigation could result in increased operating costs and reduced
demand for the oil and natural gas that we produce.
On December 15, 2009, the EPA published its findings that
emissions of carbon dioxide, methane and other greenhouse gases
(GHGs) present an endangerment to human health and
the environment because emissions of such gases are, according
to the EPA, contributing to the warming of the Earths
atmosphere and other climate changes. These findings by the EPA
allow the agency to proceed with the adoption and implementation
of regulations that would restrict emissions of GHGs under
existing provisions of the federal Clean Air Act. The EPA
adopted two sets of regulations under the existing Clean Air Act
requiring a reduction in emissions of GHGs from motor vehicles
that became effective on January 2, 2011. The EPA also
determined that a permit review for GHG emissions from certain
stationary sources was triggered under the federal air permit
programs. EPA adopted a tiered approach to implementing the
permitting of GHG emissions from stationary sources in May 2010.
The so-called tailoring rule only requires the
stationary sources with the largest emissions to undergo an
assessment of GHG emissions under the best available control
technology under the federal permitting programs. In addition,
on September 22, 2009, the EPA issued a final rule
requiring the reporting of GHGs emissions from specified large
GHG emission sources in the United States beginning in 2011 for
emissions occurring in 2010. On November 30, 2010, the EPA
published mandatory reporting rules for certain oil and gas
facilities requiring reporting starting in 2012 for emissions in
2011. The adoption and implementation of any regulations
imposing reporting obligations on, or limiting emissions of GHGs
from, our equipment and operations could require us to incur
costs to reduce emissions of GHGs associated with our operations
or could adversely affect demand for the oil and natural gas
that we produce.
In recent years, the U.S. Congress has considered
legislation to restrict or regulate emissions of GHGs, such as
carbon dioxide and methane, which are understood to contribute
to global warming. It presently appears unlikely that
comprehensive climate legislation will be passed by Congress in
the near future, although energy legislation and other
initiatives are expected to be proposed that may be relevant to
emissions of GHGs. In addition, almost half of the states in
the United States have begun to address GHG emissions, primarily
through the planned development of GHG emission inventories or
regional GHG cap and trade programs.
Any future laws or implementing regulations that may be adopted
to address greenhouse gas emissions could require us to incur
increased operating costs or reduce emissions of and could
adversely affect demand for the oil that we produce. Please read
Business and PropertiesEnvironmental Matters and
Regulation.
Our operations are subject to environmental and
operational safety laws and regulations that may expose us to
significant costs and liabilities.
We may incur significant costs and liabilities as a result of
environmental and safety requirements applicable to our oil
development and production activities. These costs and
liabilities could arise under a wide range of federal, state,
tribal and local environmental and safety laws and regulations,
including regulations and enforcement policies, which have
tended to become increasingly strict over time. Failure to
comply with these laws and regulations may result in the
assessment of administrative, civil and criminal penalties,
imposition of cleanup and site restoration costs and liens, and
to a lesser extent, issuance of injunctions to limit or cease
operations. In addition, we may experience delays in obtaining
or be unable to obtain required permits, which may delay or
interrupt our operations and limit our growth and revenue.
Claims for damages to persons or property from private parties
and governmental authorities may result from environmental and
other impacts of our operations.
Strict, joint and several liability may be imposed under certain
environmental laws, which could cause us to become liable for
the conduct of others or for consequences of our own actions
that were in compliance with all applicable laws at the time
those actions were taken. New laws,
31
regulations or enforcement policies could be more stringent and
impose unforeseen liabilities or significantly increase
compliance costs.
We may be required to incur certain capital expenditures in the
next few years for air pollution control equipment or other air
emissions-related issues. For example, on July 28, 2011,
the EPA proposed four sets of new rules which, if adopted, will
impose stringent new standards for air emissions from oil and
natural gas development and production operations, including
crude oil storage tanks with a throughput of at least
20 barrels per day, condensate storage tanks with a
throughput of at least one barrel per day, completions of new
hydraulically fractured natural gas wells, and recompletions of
existing natural gas wells that are fractured or refractured.
The EPA will receive public comment and hold hearings regarding
the proposed rules and must take final action on them by
April 3, 2012. If adopted, these rules may require us to
incur additional expenses to control air emissions from current
operations and during new well developments by installing
emissions control technologies and adhering to a variety of work
practice and other requirements. If we were not able to recover
the resulting costs through insurance or increased revenues, our
ability to make cash distributions to our unitholders could be
adversely affected.
In addition, we may be required to establish reserves against
these liabilities. Although we believe we have established
appropriate reserves for known liabilities, we could be required
to set aside additional reserves in the future if additional
liabilities arise, which could have an adverse effect on our
operating results.
Please read Business and PropertiesEnvironmental
Matters and Regulation for more information.
The recent adoption of derivatives legislation by the U.S.
Congress could have an adverse effect on our ability to use
derivative contracts to reduce the effect of commodity price,
interest rate and other risks associated with our
business.
The July 2010 Dodd-Frank Wall Street Reform and Consumer
Protection Act (the Act) establishes a new statutory
and regulatory requirements for derivative transactions,
including oil and gas hedging transactions. Certain transactions
will be required to be cleared on exchanges and cash collateral
will have to be posted (commonly referred to as
margin). The Act provides for a potential exemption
from these clearing and cash collateral requirements for
commercial end-users and it includes a number of defined terms
that will be used in determining how this exemption applies to
particular derivative transactions and the parties to those
transactions. Since the Act mandates the Commodities Futures
Trading Commission (the CFTC) to promulgate rules to
define these terms, we do not know the definitions the CFTC will
actually adopt or how these definitions will apply to us. The
CFTC has also proposed regulations to set position limits for
certain futures and option contracts in the major energy markets
and for swaps that are their economic equivalent. Certain bona
fide hedging transactions or positions would be exempt from
these position limits. It is not possible at this time to
predict if and when the CFTC will finalize these regulations.
Although we currently do not, and do not anticipate that we will
in the future, voluntarily enter into derivative transactions
that require an initial deposit of cash collateral, depending on
the rules and definitions ultimately adopted by the CFTC, we
might in the future be required to post cash collateral for our
commodities derivative transactions. Posting of cash collateral
could cause liquidity issues for us by reducing our ability to
use our cash for capital expenditures or other partnership
purposes. Also, if commodity prices move in a manner adverse to
us, we may be required to meet margin calls. A requirement to
post cash collateral could therefore reduce our ability to
execute strategic hedges to reduce commodity price uncertainty
and thus protect cash flow. Although the CFTC has issued
proposed rules under the Act, we are at risk unless and until
the CFTC adopts rules and definitions that confirm that
companies such as us are not required to post cash collateral
for our derivative hedging contracts. In addition, even if we
are not required to post cash collateral for our derivative
contracts, the banks and other derivatives dealers who are our
contractual counterparties will be required to comply with the
Acts new
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requirements, and the costs of their compliance will likely be
passed on to customers, including us, thus decreasing the
benefits to us of hedging transactions and reducing the
profitability of our cash flow.
Federal and state legislative and regulatory initiatives
relating to hydraulic fracturing could result in increased costs
and additional operating restrictions or delays.
The U.S. Congress is considering legislation to amend the
federal Safe Drinking Water Act to require the disclosure of
chemicals used by the oil and natural gas industry in the
hydraulic fracturing process. Hydraulic fracturing is a commonly
used process in the completion of unconventional wells in shale
formations, as well as tight conventional formations including
many of those that we complete and produce. This process
involves the injection of water, sand and chemicals under
pressure into rock formations to stimulate oil and natural gas
production. If adopted, this legislation could establish an
additional level of regulation and permitting at the federal
level, and could make it easier for third parties to initiate
legal proceedings based on allegations that chemicals used in
the fracturing process could adversely affect the environment,
including groundwater, soil and surface water. In addition, the
EPA has recently asserted regulatory authority over certain
hydraulic fracturing activities involving diesel fuel under the
Safe Drinking Water Acts Underground Injection Program and
has begun the process of drafting guidance documents on
regulatory requirements for companies that plan to conduct
hydraulic fracturing using diesel fuel. Moreover, the EPA
announced on October 20, 2011 that it is also launching a
study regarding wastewater resulting from hydraulic fracturing
activities and currently plans to propose standards by 2014 that
such wastewater must meet before being transported to a
treatment plant. In addition, a number of other federal agencies
are also analyzing a variety of environmental issues associated
with hydraulic fracturing and could potentially take regulatory
actions that impair our ability to conduct hydraulic fracturing
operations. Some states, including Texas, and various local
governments have adopted, and others are considering,
regulations to restrict and regulate hydraulic fracturing. Any
additional level of regulation could lead to operational delays
or increased operating costs which could result in additional
regulatory burdens that could make it more difficult to perform
hydraulic fracturing and would increase our costs of compliance
and doing business, resulting in a decrease of cash available
for distribution to our unitholders.
Risks
Inherent in an Investment in Us
In addition to the risk factors presented below, there are other
risk factors related to conflicts of interests and our general
partners fiduciary duties inherent in an investment in us.
See Conflicts of Interest and Fiduciary Duties for a
discussion of those risks.
Our general partner controls us, and the Founders and
Yorktown own a 57.4% interest in us. They will have conflicts of
interest with, and owe limited fiduciary duties to, us, which
may permit them to favor their own interests to the detriment of
us and our unitholders.
Our general partner will have control over all decisions related
to our operations. Upon consummation of this offering, our
general partner will be owned by the Founders. The Founders and
Yorktown will own a 57.4% interest in us. Although our general
partner has a fiduciary duty to manage us in a manner beneficial
to us and our unitholders, the executive officers and directors
of our general partner have a fiduciary duty to manage our
general partner in a manner beneficial to its owners. All of the
executive officers and non-independent directors of our general
partner are also officers
and/or
directors of the Mid-Con Affiliates and will continue to have
economic interests in, as well as management and fiduciary
duties to, the Mid-Con Affiliates. Additionally, one of the
directors of our general partner is a principal with Yorktown.
As a result of these relationships, conflicts of interest may
arise in the future between the Mid-Con Affiliates and Yorktown
and their respective affiliates, including our general partner,
on the one hand, and us and our unitholders, on the other hand.
In resolving these conflicts of interest, our general partner
may favor its own
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interests and the interests of its affiliates over the interests
of our common unitholders. These potential conflicts include,
among others:
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Our partnership agreement limits our general partners
liability, reduces its fiduciary duties and also restricts the
remedies available to our unitholders for actions that, without
these limitations, might constitute breaches of fiduciary duty.
By purchasing common units, unitholders are consenting to some
actions and conflicts of interest that might otherwise
constitute a breach of fiduciary or other duties under
applicable law;
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Neither our partnership agreement nor any other agreement
requires the Mid-Con Affiliates and Yorktown or their respective
affiliates (other than our general partner) to pursue a business
strategy that favors us. The officers and directors of the
Mid-Con Affiliates and Yorktown and their respective affiliates
(other than our general partner) have a fiduciary duty to make
these decisions in the best interests of their respective equity
holders, which may be contrary to our interests;
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The Mid-Con Affiliates and Yorktown and their affiliates are not
limited in their ability to compete with us, including with
respect to future acquisition opportunities, and are under no
obligation to offer or sell assets to us;
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All of the executive officers of our general partner who will
provide services to us will also devote a significant amount of
time to the Mid-Con Affiliates and will be compensated for those
services rendered;
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Our general partner determines the amount and timing of our
development operations and related capital expenditures, asset
purchases and sales, borrowings, issuance of additional
partnership interests, other investments, including investment
capital expenditures in other partnerships with which our
general partner is or may become affiliated, and cash reserves,
each of which can affect the amount of cash that is distributed
to unitholders;
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We will enter into a services agreement with Mid-Con Energy
Operating pursuant to which Mid-Con Energy Operating will
provide management, administrative and operational services to
us, and Mid-Con Energy Operating will also provide these
services to the Mid-Con Affiliates;
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Our general partner determines which costs incurred by it and
its affiliates are reimbursable by us;
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Our partnership agreement does not restrict our general partner
from causing us to pay it or its affiliates for any services
rendered to us or entering into additional contractual
arrangements with any of these entities on our behalf;
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Our general partner intends to limit its liability regarding our
contractual and other obligations and, in some circumstances, is
entitled to be indemnified by us;
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Our general partner may exercise its limited right to call and
purchase common units if it and its affiliates own more than 80%
of the common units;
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Our general partner controls the enforcement of obligations owed
to us by our general partner and its affiliates; and
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Our general partner decides whether to retain separate counsel,
accountants or others to perform services for us.
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Please read Certain Relationships and Related Party
Transactions and Conflicts of Interest and Fiduciary
Duties.
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Neither we nor our general partner have any employees, and
we rely solely on Mid-Con Energy Operating to manage and operate
our business. The management team of Mid-Con Energy Operating,
which includes the individuals who will manage us, will also
provide substantially similar services to the Mid-Con
Affiliates, and thus will not be solely focused on our
business.
Neither we nor our general partner have any employees, and we
rely solely on Mid-Con Energy Operating to manage us and operate
our assets. Upon the closing of this offering, we will enter
into a services agreement with Mid-Con Energy Operating pursuant
to which Mid-Con Energy Operating will provide management,
administrative and operational services to us.
Mid-Con Energy Operating will also continue to provide
substantially similar services and personnel to the Mid-Con
Affiliates and, as a result, may not have sufficient human,
technical and other resources to provide those services at a
level that it would be able to provide to us if it did not
provide similar services to these other entities. Additionally,
Mid-Con Energy Operating may make internal decisions on how to
allocate its available resources and expertise that may not
always be in our best interest compared to those of the Mid-Con
Affiliates or other affiliates of our general partner. There is
no requirement that Mid-Con Energy Operating favor us over these
other entities in providing its services. If the employees of
Mid-Con Energy Operating do not devote sufficient attention to
the management and operation of our business, our financial
results may suffer and our ability to make distributions to our
unitholders may be reduced.
We have material weaknesses in our internal control over
financial reporting. If one or more material weaknesses persist
or if we fail to establish and maintain effective internal
control over financial reporting, our ability to accurately
report our financial results could be adversely affected.
Prior to the completion of this offering, we were a private
entity with limited accounting personnel and other supervisory
resources to adequately execute our accounting processes and
address our internal control over financial reporting.
Subsequent to the review of the interim combined financial
information as of June 30, 2011 and for the six month
period then ended, our independent registered accounting firm
identified and communicated material weaknesses related to
ineffective internal controls to ensure that misstatements of
more than a significant magnitude were detected during the
routine financial statement closing process, which resulted in
errors in the calculation of depreciation, depletion and
amortization and impairment of proved oil and gas properties and
in the recording of certain geological and geophysical costs.
These errors caused us to make several adjustments to our
financial statements, resulting in a restatement of many of our
financial statements for the periods presented in this
registration statement. A material weakness is a
deficiency, or combination of deficiencies, in internal controls
over financial reporting such that there is a reasonable
possibility that a material misstatement of our financial
statements will not be prevented, or detected on a timely basis.
A control deficiency exists when the design or operation of a
control does not allow management or employees, in the normal
course of performing their assigned functions, to prevent or
detect misstatements on a timely basis. In particular, our
independent registered accounting firm informed us that our
system of internal controls relied too heavily on one key
individual in our accounting and financial reporting group to
perform period-end calculations and to ensure the financial
statements and disclosures were materially correct. Further, our
independent registered accounting firm suggested that we develop
a more formalized system of procedures performed by lower level
accounting and reporting staff and implement controls to ensure
that those procedures are operating as designed and that the
data generated is accurate.
Our management recently hired additional accounting personnel
and purchased new accounting software in an effort to enhance
its internal controls over financial reporting.
While we have begun the process of evaluating the design and
operation of our internal control over financial reporting, we
are in the early phases of our review and will not complete
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our review until after this offering is completed. We cannot
predict the outcome of our review at this time. During the
course of the review, we may identify additional control
deficiencies, which could give rise to significant deficiencies
and other material weaknesses, in addition to the material
weaknesses described above. Each of the material weaknesses
described above could result in a misstatement of our accounts
or disclosures that would result in a material misstatement of
our annual or interim combined financial statements that would
not be prevented or detected. We cannot assure you that the
measures we have taken to date, or any measures we may take in
the future, will be sufficient to remediate the material
weaknesses described above or avoid potential future material
weaknesses.
We are not currently required to comply with the SECs
rules implementing Section 404 of the Sarbanes Oxley Act of
2002, and are therefore not required to make a formal assessment
of the effectiveness of our internal control over financial
reporting for that purpose. Upon becoming a publicly traded
partnership, we will be required to comply with the SECs
rules implementing Sections 302 and 404 of the Sarbanes
Oxley Act of 2002, which will require our management to certify
financial and other information in our quarterly and annual
reports and provide an annual management report on the
effectiveness of our internal control over financial reporting.
Though we will be required to disclose changes made to our
internal controls and procedures on a quarterly basis, we will
not be required to make our first annual assessment of our
internal control over financial reporting pursuant to
Section 404 until the year following our first annual
report required to be filed with the SEC. To comply with the
requirements of being a publicly traded partnership, we will
need to implement additional internal controls, reporting
systems and procedures and hire additional accounting, finance
and legal staff.
Further, our independent registered public accounting firm is
not yet required to formally attest to the effectiveness of our
internal controls over financial reporting until the year
following our first annual report required to be filed with the
SEC. If it is required to do so, our independent registered
public accounting firm may issue a report that is adverse in the
event it is not satisfied with the level at which our controls
are documented, designed or operating. Our remediation efforts
may not enable us to remedy or avoid material weaknesses or
significant deficiencies in the future. Any failure to develop
or maintain effective internal controls, or difficulties
encountered in implementing or improving our internal controls,
could harm our operating results or cause us to fail to meet our
reporting obligations. Ineffective internal controls could also
cause investors to lose confidence in our reported financial
information, which would likely have a negative effect on the
trading price of our units.
Increases in interest rates could adversely impact our
unit price and our ability to issue additional equity and incur
debt.
Interest rates on future credit facilities and debt offerings
could be higher than current levels, causing our financing costs
to increase. In addition, as with other yield-oriented
securities, our unit price is impacted by the level of our cash
distributions to our unitholders and implied distribution yield.
This implied distribution yield is often used by investors to
compare and rank similar
yield-oriented
securities for investment decision-making purposes. Therefore,
changes in interest rates, either positive or negative, may
affect the yield requirements of investors who invest in our
common units, and a rising interest rate environment could have
an adverse impact on our unit price and our ability to issue
additional equity or incur debt.
Public unitholders do not have a priority right to receive
distributions and are not entitled to receive any payments of
arrearages.
Unlike many publicly traded partnerships, initially we will not
have any incentive distribution rights or subordinated units.
Because we will have no subordinated units after this offering,
our public unitholders will not be senior in payment of
distributions at the initial quarterly distribution rate, or at
any rate, over the Contributing Parties. In addition, if the
amount of any
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future distribution is less than the initial quarterly
distribution rate, public unitholders will not have any right to
receive any payments of arrearages in future periods.
Units held by persons who our general partner determines
are not eligible holders will be subject to redemption.
To comply with U.S. laws with respect to the ownership of
interests in oil and natural gas leases on federal lands, we
have adopted certain requirements regarding those investors who
may own our common units. As used herein, an Eligible Holder
means a person or entity qualified to hold an interest in oil
and natural gas leases on federal lands. As of the date hereof,
Eligible Holder means:
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a citizen of the United States;
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a corporation organized under the laws of the United States or
of any state thereof;
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a public body, including a municipality;
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an association of United States citizens, such as a partnership
or limited liability company, organized under the laws of the
United States or of any state thereof, but only if such
association does not have any direct or indirect foreign
ownership, other than foreign ownership of stock in a parent
corporation organized under the laws of the United States or of
any state thereof; or
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a limited partner whose nationality, citizenship or other
related status would not, in the determination of our general
partner, create a substantial risk of cancellation or forfeiture
of any property in which we or our subsidiary has an interest.
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Onshore mineral leases or any direct or indirect interest
therein may be acquired and held by aliens only through stock
ownership, holding or control in a corporation organized under
the laws of the United States or of any state thereof.
Unitholders who are not persons or entities who meet the
requirements to be an Eligible Holder run the risk of having
their common units redeemed by us at the then-current market
price. The redemption price will be paid in cash or by delivery
of a promissory note, as determined by our general partner.
Please read Description of the Common Units Transfer
Agent and RegistrarTransfer of Common Units and
The Partnership AgreementNon-Citizen Unitholders;
Redemption.
Our unitholders have limited voting rights and are not
entitled to elect our general partner or its board of directors,
which could reduce the price at which our common units will
trade.
Unlike the holders of common stock in a corporation, unitholders
have only limited voting rights on matters affecting our
business and, therefore, limited ability to influence
managements decisions regarding our business. Our
unitholders will have no right on an annual or ongoing basis to
elect our general partner or its board of directors. The board
of directors of our general partner, including the independent
directors, is chosen entirely by the Founders, as a result of
their ownership of our general partner, and not by our
unitholders. Please read ManagementManagement of
Mid-Con Energy Partners, LP and Certain
Relationships and Related Party Transactions. Unlike
publicly traded corporations, we will not conduct annual
meetings of our unitholders to elect directors or conduct other
matters routinely conducted at annual meetings of stockholders
of corporations. As a result of these limitations, the price at
which the common units will trade could be diminished because of
the absence or reduction of a takeover premium in the trading
price.
Even if our unitholders are dissatisfied, they cannot
remove our general partner without its consent.
The public unitholders will be unable initially to remove our
general partner without its consent because affiliates of our
general partner and Yorktown will own sufficient units upon
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completion of this offering to be able to prevent the removal
of our general partner. The vote of the holders of at least
662/3%
of all outstanding units is required to remove our general
partner. Following consummation of this offering, the Founders
and Yorktown will own approximately 58.6% of our outstanding
common units, which will enable those holders, collectively, to
prevent the removal of our general partner.
Control of our general partner may be transferred to a
third party without unitholder consent.
Our general partner may transfer its general partner interest to
a third party in a merger or in a sale of all or substantially
all of its assets without the consent of the unitholders.
Furthermore, our partnership agreement does not restrict the
ability of the Founders from transferring all or a portion of
their ownership interests in our general partner to a third
party. The new owner of our general partner would then be in a
position to replace the board of directors and officers of our
general partner with their own choices and thereby influence the
decisions made by the board of directors and officers in a
manner that may not be aligned with the interests of our
unitholders.
We may not make cash distributions during periods when we
record net income.
The amount of cash we have available for distribution to our
unitholders depends primarily on our cash flow, including cash
from reserves established by our general partner and borrowings,
and not solely on profitability, which will be affected by
non-cash items. As a result, we may make cash distributions to
our unitholders during periods when we record net losses and may
not make cash distributions to our unitholders during periods
when we record net income.
We may issue an unlimited number of additional units,
including units that are senior to the common units, without
unitholder approval, which would dilute unitholders
ownership interests.
Our partnership agreement does not limit the number of
additional common units that we may issue at any time without
the approval of our unitholders. In addition, we may issue an
unlimited number of units that are senior to the common units in
right of distribution, liquidation and voting. The issuance by
us of additional common units or other equity interests of equal
or senior rank will have the following effects:
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our unitholders proportionate ownership interest in us
will decrease;
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the amount of cash available for distribution on each unit may
decrease;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding unit
may be diminished; and
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the market price of our common units may decline.
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Our partnership agreement restricts the limited voting
rights of unitholders, other than our general partner and its
affiliates, owning 20% or more of our common units, which may
limit the ability of significant unitholders to influence the
manner or direction of management.
Our partnership agreement restricts unitholders limited
voting rights by providing that any common units held by a
person, entity or group owning 20% or more of any class of
common units then outstanding, other than our general partner,
its affiliates, their transferees and persons who acquired such
common units with the prior approval of the board of directors
of our general partner, cannot vote on any matter. Our
partnership agreement also contains provisions limiting the
ability of unitholders to call meetings or to acquire
information about our operations, as well as other provisions
limiting unitholders ability to influence the manner or
direction of management.
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Once our common units are publicly traded, the Founders,
Yorktown and the other Contributing Parties may sell common
units in the public markets, which sales could have an adverse
impact on the trading price of the common units.
After the sale of the common units offered hereby, the Founders,
Yorktown and the other Contributing Parties will own
12,240,000 common units or approximately 69.4% of our
limited partner interests. The sale of these units in the public
markets could have an adverse impact on the price of the common
units or on any trading market that may develop.
Our unitholders liability may not be limited if a
court finds that unitholder action constitutes control of our
business.
A general partner of a partnership generally has unlimited
liability for the obligations of the partnership, except for
those contractual obligations of the partnership that are
expressly made without recourse to the general partner. Our
partnership is organized under Delaware law and we conduct
business in a number of other states. The limitations on the
liability of holders of limited partner interests for the
obligations of a limited partnership have not been clearly
established in some of the other states in which we do business.
A unitholder could be liable for our obligations as if it was a
general partner if:
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a court or government agency determined that we were conducting
business in a state but had not complied with that particular
states partnership statute; or
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a unitholders right to act with other unitholders to
remove or replace the general partner, to approve some
amendments to our partnership agreement or to take other actions
under our partnership agreement constitute control
of our business.
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Please read The Partnership AgreementLimited
Liability for a discussion of the implications of the
limitations of liability on a unitholder.
Our unitholders may have liability to repay
distributions.
Under certain circumstances, unitholders may have to repay
amounts wrongfully returned or distributed to them. Under
Section 17-607
of the Delaware Revised Uniform Limited Partnership Act, we may
not make distributions to unitholders if the distribution would
cause our liabilities to exceed the fair value of our assets.
Liabilities to partners on account of their partnership
interests and liabilities that are non-recourse to us are not
counted for purposes of determining whether a distribution is
permitted. Delaware law provides that for a period of three
years from the date of an impermissible distribution, limited
partners who received the distribution and who knew at the time
of the distribution that it violated Delaware law will be liable
to the limited partnership for the distribution amount. A
purchaser of common units who becomes a limited partner is
liable for the obligations of the transferring limited partner
to make contributions to us that are known to such purchaser of
common units at the time it became a limited partner and for
unknown obligations if the liabilities could be determined from
our partnership agreement.
Our unitholders may have limited liquidity for their
common units, a trading market may not develop for the common
units and our unitholders may not be able to resell their common
units at the initial public offering price.
Prior to this offering, there has been no public market for the
common units. After this offering, there will be publicly traded
common units. We do not know the extent to which investor
interest will lead to the development of a trading market or how
liquid that market might be. Our unitholders may not be able to
resell their common units at or above the initial public
offering price. Additionally, a lack of liquidity would likely
result in wide bid-ask spreads, contribute to significant
fluctuations in the market price of the common units and limit
the number of investors who are able to buy the common units.
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If our common unit price declines after the initial public
offering, our unitholders could lose a significant part of their
investment.
The initial public offering price for the common units will be
determined by negotiations between us and the representatives of
the underwriters and may not be indicative of the market price
of the common units that will prevail in the trading market. The
market price of our common units could be subject to wide
fluctuations in response to a number of factors, most of which
we cannot control, including:
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changes in commodity prices;
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changes in securities analysts recommendations and their
estimates of our financial performance;
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public reaction to our press releases, announcements and filings
with the SEC;
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fluctuations in broader securities market prices and volumes,
particularly among securities of oil and natural gas companies
and securities of publicly traded limited partnerships and
limited liability companies;
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changes in market valuations of similar companies;
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departures of key personnel;
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commencement of or involvement in litigation;
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variations in our quarterly results of operations or those of
other oil and natural gas companies;
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variations in the amount of our quarterly cash distributions to
our unitholders;
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future issuances and sales of our common units; and
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changes in general conditions in the U.S. economy,
financial markets or the oil and natural gas industry.
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In recent years, the securities market has experienced extreme
price and volume fluctuations. This volatility has had a
significant effect on the market price of securities issued by
many companies for reasons unrelated to the operating
performance of these companies. Future market fluctuations may
result in a lower price of our common units.
Our unitholders will experience immediate and substantial
dilution of $17.56 per unit.
The assumed initial offering price of $20.00 per common unit
exceeds our pro forma net tangible book value after this
offering of $2.44 per common unit. Based on the assumed initial
offering price of $20.00 per common unit, our unitholders will
incur immediate and substantial dilution of $17.56 per common
unit. This dilution will occur primarily because the assets
contributed by affiliates of our general partner are recorded,
in accordance with GAAP, at their historical cost, and not their
fair value.
Our partnership agreement requires that we distribute all
of our available cash, which could limit our ability to grow our
reserves and production and make acquisitions.
Our partnership agreement provides that we will distribute all
of our available cash each quarter. As a result, we may be
dependent on the issuance of additional common units and other
partnership securities and borrowings to finance our growth. A
number of factors will affect our ability to issue securities
and borrow money to finance growth, as well as the costs of such
financings, including:
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general economic and market conditions, including interest
rates, prevailing at the time we desire to issue securities or
borrow funds;
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conditions in the oil and gas industry;
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the market price of, and demand for, our common units;
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our results of operations and financial condition; and
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prices for oil and natural gas.
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In addition, because we distribute all of our available cash,
our growth may not be as fast as that of businesses that
reinvest their available cash to expand ongoing operations. To
the extent we issue additional units in connection with any
acquisitions or growth capital expenditures, the payment of
distributions on those additional units may increase the risk
that we will be unable to maintain or increase our per unit
distribution level. There are no limitations in our partnership
agreement or in our new credit facility on our ability to issue
additional units, including units ranking senior to the common
units. The incurrence of additional commercial borrowings or
other debt to finance our growth strategy would result in
increased interest expense, which, in turn, may impact the
available cash that we have to distribute to our unitholders.
Tax Risks
to Unitholders
In addition to reading the following risk factors, prospective
unitholders should read Material Tax Consequences
for a more complete discussion of the expected material federal
income tax consequences of owning and disposing of our units.
Our tax treatment depends on our status as a partnership
for federal income tax purposes. If the IRS were to treat us as
a corporation, then our cash available for distribution to our
unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in
the units depends largely on our being treated as a partnership
for federal income tax purposes. We have not requested, and do
not plan to request, a ruling from the IRS on this or any other
tax matter affecting us.
Despite the fact that we are a limited partnership under
Delaware law, it is possible in certain circumstances for a
partnership such as ours to be treated as a corporation for
federal income tax purposes. Although we do not believe based on
our current operations that we are so treated, a change in our
business (or a change in current law) could cause us to be
treated as a corporation for federal income tax purposes or
otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our taxable income
at the corporate tax rate, which is currently a maximum of 35%,
and would likely pay state income tax at varying rates.
Distributions to unitholders would generally be taxed again as
corporate distributions, and no income, gains, losses or
deductions would flow through to unitholders. Because a tax
would be imposed upon us as a corporation, our cash available
for distribution to unitholders would be substantially reduced.
Therefore, treatment of us as a corporation would result in a
material reduction in the anticipated cash flow and after-tax
return to our unitholders, likely causing a substantial
reduction in the value of our units.
If we were subjected to a material amount of additional
entity-level taxation by individual states, it would reduce our
cash available for distribution to our unitholders.
Changes in current state law may subject us to additional
entity-level taxation by individual states. Because of
widespread state budget deficits and other reasons, several
states are evaluating ways to subject partnerships to
entity-level taxation through the imposition of state income,
franchise and other forms of taxation. Imposition of any such
taxes may substantially reduce the cash available for
distribution to our unitholders and, therefore, negatively
impact the value of an investment in our units.
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The tax treatment of publicly traded partnerships or an
investment in our units could be subject to potential
legislative, judicial or administrative changes and differing
interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded
partnerships, including us, or an investment in our units may be
modified by administrative, legislative or judicial
interpretation at any time. For example, the Obama
Administration and members of Congress have considered
substantive changes to the existing federal income tax laws that
would affect the tax treatment of certain publicly traded
partnerships. Any modification to the federal income tax laws
and interpretations thereof may or may not be applied
retroactively. Although we are unable to predict whether any of
these changes, or other proposals, will ultimately be enacted,
any such changes could negatively impact the value of an
investment in our units.
Certain U.S. federal income tax deductions currently
available with respect to oil and natural gas exploration and
production may be eliminated as a result of future
legislation.
Both the Obama Administrations budget proposal for fiscal
year 2012 and the proposed American Jobs Act of 2011 include
potential legislation that would, if enacted, make significant
changes to United States tax laws, including the elimination of
certain key U.S. federal income tax incentives currently
available to oil and natural gas exploration and production
companies. These changes include, but are not limited to,
(i) the repeal of the percentage depletion allowance for
oil and natural gas properties, (ii) the elimination of
current deductions for intangible drilling and development
costs, (iii) the elimination of the deduction for certain
domestic production activities, and (iv) an extension of
the amortization period for certain geological and geophysical
expenditures. It is unclear whether these or similar changes
will be enacted and, if enacted, how soon any such changes could
become effective. The passage of any legislation as a result of
these proposals or any other similar changes in
U.S. federal income tax laws could eliminate or postpone
certain tax deductions that are currently available with respect
to oil and natural gas exploration and development, and any such
change could increase the taxable income allocable to our
unitholders and negatively impact the value of an investment in
our units.
If the IRS contests any of the federal income tax
positions we take, the market for our units may be adversely
affected, and the costs of any IRS contest will reduce our cash
available for distribution to our unitholders.
We have not requested, and do not plan to request, a ruling from
the IRS with respect to our treatment as a partnership for
federal income tax purposes or any other matter affecting us.
The IRS may adopt positions that differ from the conclusions of
our counsel expressed in this prospectus or from the positions
we take. It may be necessary to resort to administrative or
court proceedings to sustain some or all of our counsels
conclusions or the positions we take. A court may not agree with
some or all of our counsels conclusions or the positions
we take. Any contest with the IRS may materially and adversely
impact the market for our units and the price at which they
trade. In addition, the costs of any contest with the IRS will
be borne indirectly by our unitholders and our general partner
because the costs will reduce our cash available for
distribution.
Our unitholders will be required to pay taxes on their
share of our taxable income even if they do not receive any cash
distributions from us.
Because our unitholders will be treated as partners to whom we
will allocate taxable income, which could be different in amount
than the cash we distribute, our unitholders will be required to
pay any federal income taxes and, in some cases, state and local
income taxes on their share of our taxable income even if they
receive no cash distributions from us. Our unitholders may not
receive cash distributions from us equal to their share of our
taxable income or even equal to the actual tax liability that
results from that income.
42
Tax gain or loss on the disposition of our units could be
more or less than expected.
If our unitholders sell their units, they will recognize a gain
or loss equal to the difference between the amount realized and
their adjusted tax basis in those units. Because prior
distributions in excess of their allocable share of our total
net taxable income decrease their tax basis in their units, the
amount, if any, of such prior excess distributions with respect
to the units they sell will, in effect, become taxable income to
them if they sell such units at a price greater than their tax
basis in those units, even if the price they receive is less
than their original cost. Furthermore, a substantial portion of
the amount realized, whether or not representing gain, may be
taxed as ordinary income due to potential recapture items,
including depreciation, depletion, amortization and IDC
recapture. In addition, because the amount realized may include
a unitholders share of our nonrecourse liabilities, they
may incur a tax liability in excess of the amount of cash they
receive from the sale. Please read Material Tax
ConsequencesDisposition of UnitsRecognition of Gain
or Loss.
Tax-exempt entities and
non-U.S.
persons face unique tax issues from owning our units that may
result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, such as employee
benefit plans and individual retirement accounts, or IRAs, and
non-U.S. persons
raises issues unique to them. For example, virtually all of our
income allocated to organizations that are exempt from federal
income tax, including IRAs and other retirement plans, will be
unrelated business taxable income and will be taxable to them.
Distributions to
non-U.S. persons
will be reduced by withholding taxes at the highest applicable
effective tax rate, and
non-U.S. persons
will be required to file U.S. federal income tax returns
and pay tax on their share of our taxable income. Prospective
unitholders who are tax-exempt entities or
non-U.S. persons
should consult their tax advisor before investing in our units.
We will treat each purchaser of units as having the same
tax benefits without regard to the units purchased. The IRS may
challenge this treatment, which could adversely affect the value
of the units.
Because we cannot match transferors and transferees of units and
because of other reasons, we will adopt depreciation, depletion
and amortization positions that may not conform with all aspects
of existing Treasury Regulations. A successful IRS challenge to
those positions could adversely affect the amount of tax
benefits available to our unitholders. It also could affect the
timing of these tax benefits or the amount of gain from the sale
of units and could have a negative impact on the value of our
units or result in audits of and adjustments to a
unitholders tax returns. Please read Material Tax
ConsequencesTax Consequences of Unit
OwnershipSection 754 Election for a further
discussion of the effect of the depreciation, depletion and
amortization positions we will adopt.
We will prorate our items of income, gain, loss and
deduction between transferors and transferees of our units each
month based upon the ownership of our units on the first day of
each month, instead of on the basis of the date a particular
unit is transferred. The IRS may challenge this treatment, which
could change the allocation of items of income, gain, loss and
deduction among our unitholders.
We will prorate our items of income, gain, loss and deduction
between transferors and transferees of our units each month
based upon the ownership of our units on the first day of each
month, instead of on the basis of the date a particular unit is
transferred. The use of this proration method may not be
permitted under existing Treasury Regulations. If the IRS were
to challenge our proration method or new Treasury Regulations
were issued, we may be required to change the allocation of
items of income, gain, loss and deduction among our unitholders.
Andrews Kurth LLP has not rendered an opinion with respect to
whether our monthly convention for allocating taxable income and
losses is permitted by existing Treasury
43
Regulations. Please read Material Tax
ConsequencesDisposition of UnitsAllocations Between
Transferors and Transferees.
A unitholder whose units are loaned to a short
seller to effect a short sale of units may be considered
as having disposed of those units. If so, such unitholder would
no longer be treated for tax purposes as a partner with respect
to those units during the period of the loan and may recognize
gain or loss from the disposition.
Because a unitholder whose units are loaned to a short
seller to effect a short sale of units may be considered
as having disposed of the loaned units, such unitholder may no
longer be treated for tax purposes as a partner with respect to
those units during the period of the loan to the short seller
and the unitholder may recognize gain or loss from such
disposition. Moreover, during the period of the loan to the
short seller, any of our income, gain, loss or deduction with
respect to those units may not be reportable by the unitholder
and any cash distributions received by the unitholder as to
those units could be fully taxable as ordinary income. Andrews
Kurth LLP has not rendered an opinion regarding the treatment of
a unitholder where units are loaned to a short seller to effect
a short sale of units; therefore, unitholders desiring to assure
their status as partners and avoid the risk of gain recognition
from a loan to a short seller are urged to consult a tax advisor
to discuss whether it is advisable to modify any applicable
brokerage account agreements to prohibit their brokers from
borrowing their units.
The sale or exchange of 50% or more of our capital and
profits interests during any twelve-month period will result in
the termination of our partnership for federal income tax
purposes.
We will be considered to have technically terminated for federal
income tax purposes if there is a sale or exchange of 50% or
more of the total interests in our capital and profits within a
twelve-month period. For purposes of determining whether the 50%
threshold has been met, multiple sales of the same unit will be
counted only once. While we would continue our existence as a
Delaware limited partnership, our technical termination would,
among other things, result in the closing of our taxable year
for all unitholders, which would result in us filing two tax
returns (and our unitholders could receive two Schedules K-1 if
special relief from the IRS is not available) for one fiscal
year and could result in a significant deferral of depreciation
deductions allowable in computing our taxable income. In the
case of a unitholder reporting on a taxable year other than a
fiscal year ending December 31, the closing of our taxable
year may also result in more than twelve months of our taxable
income or loss being includable in such unitholders
taxable income for the year of termination. A technical
termination should not affect our classification as a
partnership for federal income tax purposes, but instead, we
would be treated as a new partnership for tax purposes. If
treated as a new partnership, we must make new tax elections and
could be subject to penalties if we are unable to determine that
a technical termination occurred. Please read Material Tax
ConsequencesDisposition of UnitsConstructive
Termination for a discussion of the consequences of our
termination for federal income tax purposes.
A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss being
allocated to our unitholders. It also could affect the amount of
taxable gain from our unitholders sale of common units and
could have a negative impact on the value of the common units or
result in audit adjustments to our unitholders tax returns
without the benefit of additional deductions.
As a result of investing in our units, our unitholders may
become subject to state and local taxes and return filing
requirements in jurisdictions where we operate or own or acquire
property.
In addition to federal income taxes, our unitholders will likely
be subject to other taxes, including foreign, state and local
taxes, unincorporated business taxes and estate, inheritance or
intangible taxes that are imposed by the various jurisdictions
in which we conduct business or
44
own property now or in the future even if such unitholders do
not live in those jurisdictions. Our unitholders likely will be
required to file state and local income tax returns and pay
state and local income taxes in some or all of these various
jurisdictions. Further, unitholders may be subject to penalties
for failure to comply with those requirements. We initially will
own property and conduct business in Oklahoma and Colorado, each
of which currently imposes a personal income tax on individuals.
These states also impose an income tax on corporations and other
entities. As we make acquisitions or expand our business, we may
own assets or conduct business in additional states that impose
a personal income tax. We may own property or conduct business
in other states or foreign countries in the future. It is a
unitholders responsibility to file all U.S. federal,
state and local tax returns. Andrews Kurth LLP has not rendered
an opinion on the state or local tax consequences of an
investment in our units.
Compliance with and changes in tax laws could adversely
affect our performance.
We are subject to extensive tax laws and regulations, including
federal, state and foreign income taxes and transactional taxes
such as excise, sales/use, payroll, franchise and ad valorem
taxes. New tax laws and regulations and changes in existing tax
laws and regulations are continuously being enacted that could
result in increased tax expenditures in the future. Many of
these tax liabilities are subject to audits by the respective
taxing authority. These audits may result in additional taxes as
well as interest and penalties.
45
USE OF
PROCEEDS
We intend to use the estimated net proceeds of approximately
$97.4 million from this offering, based upon the assumed
initial public offering price of $20.00 per common unit, after
deducting underwriting discounts, a structuring fee and
estimated offering expenses, together with borrowings of
approximately $45.0 million under our new revolving credit
facility, to:
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|
|
|
|
distribute approximately $121.2 million to the Contributing
Parties as the cash portion of the consideration in respect of
the merger of Mid-Con Energy I, LLC and Mid-Con Energy II,
LLC into our subsidiary at closing;
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|
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repay in full $15.2 million of indebtedness outstanding
under our existing credit facilities; and
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|
|
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|
acquire, for aggregate consideration of approximately
$6.0 million, certain working interests in the Cushing
Field from J&A Oil Company and Charles R. Olmstead and
interests in certain derivative contracts from J&A Oil
Company.
|
After the uses described above, we do not expect that any of the
net proceeds of the offering will be available for investment in
our business.
As of September 30, 2011, the interest rate on our two
existing credit facilities was 4% for each facility, and the
credit facilities mature on December 31, 2013. Borrowings
made under these facilities within the last twelve months were
used for acquisitions and development activities.
The following table illustrates our use of proceeds from this
offering and our borrowings under our new credit facility:
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|
|
|
|
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Sources of Cash (in millions)
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|
|
Uses of Cash (in millions)
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Gross proceeds from this offering(1)
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$
|
108.0
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|
Distribution to Contributing Parties(1)
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$
|
121.2
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|
Borrowings under our new credit facility
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$
|
45.0
|
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Repayment of indebtedness under our
existing credit facilities
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$
|
15.2
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|
|
|
|
|
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Acquisition of certain working interests in Cushing Field and
derivative contracts
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$
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6.0
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|
|
|
|
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Underwriting discounts, a structuring fee
and estimated offering expenses
payable by us
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$
|
10.6
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Total
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$
|
153.0
|
|
|
Total
|
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$
|
153.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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(1)
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|
If the underwriters exercise their
option to purchase additional common units in full, the
additional net proceeds would be approximately
$15.1 million, and the total distribution to the
Contributing Parties would be approximately $136.3 million.
|
If and to the extent the underwriters exercise their option to
purchase additional common units, the number of common units
purchased by the underwriters pursuant to such exercise will be
issued to the public. If the underwriters exercise their option
to purchase 810,000 additional common units in full, the
additional net proceeds would be approximately
$15.1 million. The net proceeds from any exercise of such
option will be used to distribute additional cash consideration
to the Contributing Parties in respect of the merger of Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC into our
subsidiary at closing. If the underwriters do not exercise their
option to purchase 810,000 additional common units in full, we
will issue the number of remaining common units to the
Contributing Parties upon the expiration of the option
(810,000 common units if the option is not exercised at
all) as additional consideration in respect of the merger of
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC into our
subsidiary at closing. We will not receive any additional
consideration from the Contributing Parties in connection with
such
46
issuance. The exercise of the underwriters option will not
affect the total number of common units outstanding or the
amount of cash needed to pay the initial quarterly distribution
on all units. Please read Underwriting.
A $1.00 increase or decrease in the assumed initial public
offering price of $20.00 per common unit would cause the net
proceeds from this offering, after deducting underwriting
discounts, a structuring fee and estimated offering expenses
payable by us, to increase or decrease, respectively, by
approximately $5.0 million. In addition, we may also
increase or decrease the number of common units we are offering.
Each increase of 1.0 million common units offered by us,
together with a concurrent $1.00 increase in the assumed public
offering price of $20.00 per common unit, would increase net
proceeds to us from this offering by approximately
$24.5 million. Similarly, each decrease of 1.0 million
common units offered by us, together with a concurrent $1.00
decrease in the assumed initial offering price of $20.00 per
common unit, would decrease the net proceeds to us from this
offering by approximately $22.7 million.
47
CAPITALIZATION
The following table shows:
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historical capitalization as of September 30, 2011; and
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our as adjusted capitalization as of September 30, 2011,
which gives effect to the formation transactions described under
Prospectus SummaryFormation Transactions and
Partnership Structure on and the application of the net
proceeds from this offering as described under Use of
Proceeds.
|
We derived this table from, and it should be read in conjunction
with and is qualified in its entirety by reference to, our
historical and unaudited pro forma financial statements and the
accompanying notes included elsewhere in this prospectus. You
should also read this table in conjunction with
Managements Discussion and Analysis of Financial
Condition and Results of Operations. For a description of
the pro forma adjustments, please read our Unaudited Pro Forma
Condensed Financial Statements.
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As of September 30, 2011
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Mid-Con
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Our
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Energy
|
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Predecessor
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Partners, LP
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Historical
|
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As Adjusted
|
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(in thousands)
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Cash and cash equivalents
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$
|
186
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|
|
$
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|
|
|
|
|
|
|
|
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Long-term debt
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|
$
|
15,210
|
|
|
$
|
45,000
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Members/partners capital/net equity:
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Predecessor members capital
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$
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69,955
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$
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43,860
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Common units held by purchasers in this offering
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13,158
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Common units held by the Contributing Parties
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29,825
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General partner interest
|
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|
|
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877
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|
|
|
|
|
|
|
|
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Total members/partners capital/net equity
|
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69,955
|
|
|
|
43,860
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|
|
|
|
|
|
|
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Total capitalization
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$
|
85,165
|
|
|
$
|
88,860
|
|
|
|
|
|
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48
DILUTION
Dilution is the amount by which the offering price paid by the
purchasers of common units sold in this offering will exceed the
net tangible book value per unit after this offering. Net
tangible book value is our total tangible assets less total
liabilities. Assuming an initial offering price of $20.00 per
common unit (the midpoint of the price range set forth on the
cover of this prospectus), on a pro forma basis as of
September 30, 2011, after giving effect to the transactions
described under Prospectus SummaryFormation
Transactions and Partnership Structure, including this
offering of common units and the application of the related net
proceeds, our net tangible book value would have been
$43.9 million, or $2.44 per unit. Purchasers of common
units in this offering will experience substantial and immediate
dilution in net tangible book value per common unit for
accounting purposes, as illustrated in the following table:
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Assumed initial public offering price per common unit
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$
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20.00
|
|
Pro forma net tangible book value per unit before this
offering(1)
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$
|
5.55
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|
|
|
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|
Decrease in net tangible book value per unit attributable to
purchasers in the offering
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(3.11
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)
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Less: Pro forma net tangible book value per unit after this
offering(2)
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|
|
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|
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2.44
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|
|
|
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Immediate dilution in tangible net book value per common unit to
purchasers in the offering(3)
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|
|
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$
|
17.56
|
|
|
|
|
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(1)
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Determined by dividing the pro
forma net tangible book value of our net assets immediately
prior to the offering by the number of units
(12,240,000 common units to be issued to the Contributing
Parties and the issuance of 360,000 general partner units) to be
issued to the Contributing Parties and our general partner.
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(2)
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Determined by dividing our pro
forma as adjusted net tangible book value, after giving effect
to the application of the net proceeds of this offering, by the
total number of units to be outstanding after this offering
(17,640,000 common units and 360,000 general partner units).
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(3)
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Because the total number of units
outstanding following the consummation of this offering will not
be impacted by any exercise of the underwriters option to
purchase additional common units and any net proceeds from such
exercise will not be retained by us, there will be no change to
the dilution in net tangible book value per common unit to
purchasers in the offering due to any such exercise of the
underwriters option to purchase additional common units.
|
The following table sets forth the number of units that we will
issue and the total consideration contributed to us by our
general partner and the Contributing Parties, including the
Founders and Yorktown, and by the purchasers of common units in
this offering upon the closing of the transactions contemplated
by this prospectus:
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|
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|
|
|
|
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|
|
Units Acquired
|
|
|
Total Consideration
|
|
|
|
Number
|
|
|
Percent
|
|
|
Amount
|
|
|
Percent
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
General partner and Contributing Parties(1)(2)
|
|
|
12,600,000
|
|
|
|
70.0
|
%
|
|
$
|
(53,540
|
)
|
|
|
|
%
|
Purchasers in the offering(3)
|
|
|
5,400,000
|
|
|
|
30.0
|
%
|
|
|
97,400
|
|
|
|
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total
|
|
|
18,000,000
|
|
|
|
100.0
|
%
|
|
$
|
43,860
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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(1)
|
|
Upon the consummation of the
transactions contemplated by this prospectus, and assuming the
underwriters do not exercise their option to purchase additional
common units, our general partner, its owners and their
affiliates will own 12,240,000 common units and 360,000 general
partner units.
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|
(2)
|
|
The assets we will own as a result
of the merger of our affiliates into our wholly owned subsidiary
were recorded at historical cost in accordance with GAAP. Total
consideration provided by affiliates of our general partner is
equal to the net tangible book value of such assets as of
September 30, 2011.
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|
(3)
|
|
Total consideration is after
deducting underwriting discounts, a structuring fee and
estimated offering expenses.
|
49
OUR CASH
DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
You should read the following discussion of our cash
distribution policy in conjunction with the factors and
assumptions upon which our cash distribution policy is based,
which are included under the heading Assumptions and
Considerations below. In addition, you should read
Forward-Looking Statements and Risk
Factors for information regarding statements that do not
relate strictly to historical or current facts and certain risks
inherent in our business.
For additional information regarding our historical and pro
forma operating results, you should refer to our audited
historical financial statements for the years ended
June 30, 2008 and 2009, the six months ended
December 31, 2009 and the year ended December 31,
2010, our unaudited historical financial statements for the nine
months ended September 30, 2011 and our unaudited pro forma
financial statements for the year ended December 31, 2010
and nine months ended September 30, 2011 included elsewhere
in this prospectus.
General
Rationale for Our Cash Distribution Policy
Our partnership agreement requires us to distribute all of our
available cash quarterly. Our cash distribution policy reflects
a basic judgment that our unitholders generally will be better
served by us distributing our available cash, after expenses and
reserves, rather than retaining it. Our available cash is the
sum of our cash on hand at the end of a quarter after the
payment of our expenses and the establishment of reserves for
future capital expenditures and operational needs. We intend to
fund a portion of our capital expenditures with additional
borrowings or issuances of additional units. We may also borrow
to make distributions to unitholders, for example, in
circumstances where we believe that the distribution level is
sustainable over the long-term, but short-term factors have
caused available cash from operations to be insufficient to pay
the distribution at the current level. Our partnership agreement
will not restrict our ability to borrow to pay distributions.
Because we are not subject to an entity-level federal income
tax, we expect to have more cash to distribute to our
unitholders than would be the case if we were subject to such
federal income tax.
Restrictions and Limitations on Cash Distributions and Our
Ability to Change Our Cash Distribution Policy
There is no guarantee that unitholders will receive quarterly
distributions from us. We do not have a legal obligation to pay
distributions at our initial quarterly distribution rate or at
any other rate. As a result, there are no consequences to the
Partnership (such as an obligation to pay arrearages in future
periods) if it was to pay distributions in an amount less the
initial quarterly distribution rate. If the Partnership has
available cash in respect of any quarter in excess of an amount
that would enable it to pay a distribution at the initial
quarterly distribution rate to all unitholders, such excess will
be distributed to the general partner and all unitholders on a
pro rata basis in accordance with their respective interests in
the Partnership. Our cash distribution policy may be changed at
any time and is or may become subject to certain restrictions,
including the following:
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Our cash distribution policy will be subject to restrictions on
distributions under our new credit facility or other debt
agreements that we may enter into in the future. Specifically,
our new credit facility will contain financial tests and
covenants that we must satisfy. These financial tests and
covenants are described in Managements Discussion
and Analysis of Financial Condition and Results of
OperationsLiquidity and Capital ResourcesNew Credit
Facility. Should we be unable to satisfy these
restrictions, or if a default occurs under our new credit
facility, we would be prohibited from making cash distributions
to our unitholders notwithstanding our stated cash distribution
policy. Any future indebtedness may contain similar or more
stringent restrictions.
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50
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Our general partner will have the authority to establish
reserves for the prudent conduct of our business and for future
cash distributions to our unitholders, and the establishment of
or increase of those reserves could result in a reduction in
cash distributions to our unitholders from the levels we
currently anticipate pursuant to our stated cash distribution
policy. Any determination to establish cash reserves made by our
general partner in good faith will be binding on our
unitholders. Our partnership agreement does not set a limit on
the amount of cash reserves that our general partner may
establish, other than with respect to reserves for future cash
distributions. Our partnership agreement provides that in order
for a determination by our general partner to be considered to
have been made in good faith, our general partner must believe
that the determination is in, or not opposed to, our best
interests. We intend to reserve a sufficient portion of our cash
generated from operations to fund our exploitation and
development capital expenditures. If our general partner does
not set aside sufficient cash reserves or make sufficient cash
expenditures to maintain the current production levels over the
long-term of our oil and natural gas properties, we will be
unable to pay distributions at our initial quarterly
distribution rate or the then-current distribution rate from
cash generated from operations and would therefore expect to
reduce our distributions. We are unlikely to be able to sustain
the initial quarterly distribution rate without making accretive
acquisitions or capital expenditures that maintain the current
production levels of our oil and natural gas properties.
Decreases in commodity prices from current levels will adversely
affect our ability to pay distributions. If our asset base
decreases and we do not reduce our distributions, a portion of
the distributions may have the effect of, and may effectively
represent, a return of part of our unitholders investment
in us as opposed to a return on our unitholders investment.
|
|
|
|
Prior to making any distribution on our common units, we will
reimburse our general partner and its affiliates for all direct
and indirect expenses they incur on our behalf. Our partnership
agreement does not set a limit on the amount of expenses for
which our general partner and its affiliates may be reimbursed.
These expenses include salary, bonus, incentive compensation,
employment benefits, and other amounts paid to persons who
perform services for us or on our behalf and expenses allocated
to our general partner by its affiliates. Our partnership
agreement provides that our general partner will determine in
good faith the expenses that are allocable to us. The
reimbursement of expenses and payment of fees, if any, to our
general partner and its affiliates will reduce the amount of
cash available to pay cash distributions to our unitholders.
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|
|
|
|
|
Although our partnership agreement requires us to distribute all
of our available cash, our partnership agreement, including the
provisions requiring us to make cash distributions contained
therein, may be amended with the consent of our general partner
and the approval of the holders of a majority of our outstanding
common units (including common units held by affiliates of our
general partner). At the closing of this offering, the Founders
will own and control our general partner, and the Founders and
Yorktown will own approximately 58.6% of our outstanding common
units or 58.6% of our limited partner interests. Please read
The Partnership AgreementAmendment of the
Partnership Agreement.
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|
|
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|
Even if our cash distribution policy is not modified or revoked,
the amount of distributions we pay under our cash distribution
policy and the decision to make any distribution is determined
by our general partner, taking into consideration the terms of
our partnership agreement, our new credit facility and any other
debt agreements we may enter into in the future.
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|
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Under
Section 17-607
of the Delaware Revised Uniform Limited Partnership Act, we may
not make a distribution to our unitholders if the distribution
would cause our liabilities to exceed the fair value of our
assets.
|
|
|
|
We may lack sufficient cash to pay distributions to our
unitholders due to a number of factors, including decreases in
commodity prices, decreases in our oil and natural gas
|
51
|
|
|
|
|
production or increases in our general and administrative
expenses, principal and interest payments on our outstanding
debt, tax expenses, working capital requirements or anticipated
cash needs. For a discussion of additional factors that may
affect our ability to pay distributions, please read Risk
Factors.
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|
|
|
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|
If and to the extent our cash available for distribution
materially declines, we may reduce our quarterly distribution in
order to service or repay our debt or fund growth capital
expenditures.
|
|
|
|
Capital expenditures reduce cash available to pay distributions
to the extent such amounts are funded from cash generated by
operating activities.
|
|
|
|
Our ability to make distributions to our unitholders depends on
the performance of our operating subsidiary and its ability to
distribute cash to us. The ability of our operating subsidiary
to make distributions to us may be restricted by, among other
things, the provisions of existing and future indebtedness,
applicable state partnership and limited liability company laws
and other laws and regulations.
|
Our Ability to Grow Depends on Our Ability to Access
External Capital
Because we will distribute all of our available cash to our
unitholders, we expect that we will rely primarily upon external
financing sources, including borrowings under our new credit
facility and the issuance of debt and equity securities, rather
than operating cash flow, to fund our acquisitions and growth
capital expenditures. As a result, to the extent we are unable
to finance our growth externally, our cash distribution policy
will significantly impair our ability to grow. In addition,
because we will distribute all of our available cash, our growth
may not be as fast as that of businesses that reinvest their
available cash to expand their ongoing operations. To the extent
we issue additional units in connection with any capital
expenditures, the payment of distributions on those additional
units may increase the risk that we will be unable to maintain
or increase our quarterly per unit distribution level. There are
no limitations in our partnership agreement or in our new credit
facility on our ability to issue additional units, including
units ranking senior to the common units. The incurrence of
additional commercial borrowings (under our credit facility or
otherwise) or other debt to finance our growth strategy will
increase our interest expense, which in turn may impact the
available cash that we have to distribute to our unitholders.
Our
Initial Quarterly Distribution Rate
Upon completion of this offering, the board of directors of our
general partner will adopt a cash distribution policy pursuant
to which we will establish an initial quarterly distribution of
$0.475 per unit per quarter, or $1.90 per unit on an annualized
basis, to be paid no later than 45 days after the end of
each fiscal quarter, beginning with the quarter ending
December 31, 2011. This equates to an aggregate cash
distribution of approximately $8.6 million per quarter, or
$34.2 million on an annualized basis, based on the number
of common units and general partner units expected to be
outstanding immediately after the closing of this offering. We
will prorate our first distribution for the period from the
closing of this offering through December 31, 2011 based on
the length of that period. The number of outstanding common
units and general partner units on which we have based such
belief does not include any common units that may be issued
under the long-term incentive program that our general partner
is expected to adopt prior to the closing of this offering.
To the extent the underwriters exercise their option to purchase
additional common units in connection with this offering, the
number of units purchased by the underwriters pursuant to such
exercise will be issued to the public, and the remaining common
units subject to the option, if any, will be issued to the
Contributing Parties, at the expiration of the option period.
Accordingly, the exercise of the underwriters option will
not affect the total number of common units outstanding or the
amount of cash needed to pay the initial quarterly distribution
on all units. Please read Use of Proceeds.
52
Initially, our general partner will be entitled to 2.0% of all
distributions that we make prior to our liquidation. Our general
partners initial 2.0% interest in our distributions may be
reduced if we issue additional limited partner units in the
future (other than the issuance of common units upon exercise by
the underwriters of their option to purchase additional common
units, the issuance of common units to the Contributing Parties,
upon expiration of the underwriters option to purchase
additional common units or the issuance of common units upon
conversion of any outstanding partnership interests that may be
converted into common units) and our general partner does not
contribute a proportionate amount of capital to us in exchange
for additional general partner units to maintain its initial
2.0% general partner interest. Our general partner has the
right, but is not obligated, to contribute a proportionate
amount of capital to us in exchange for additional general
partner units to maintain its then current general partner
interest.
The table below sets forth the number of common units and
general partner units expected to be outstanding immediately
following the closing of this offering and the aggregate
distribution amounts payable on such units during the year
following the closing of this offering at our initial quarterly
distribution of $0.475 per unit per quarter, or $1.90 per unit
on an annualized basis.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Initial Quarterly Distribution
|
|
|
|
Units
|
|
|
One Quarter
|
|
|
Four Quarters
|
|
|
Common units held by the public(1)(2)
|
|
|
5,400,000
|
|
|
$
|
2,565,000
|
|
|
$
|
10,260,000
|
|
Common units held by the Contributing Parties(1)(2)(3)
|
|
|
12,240,000
|
|
|
|
5,814,000
|
|
|
|
23,256,000
|
|
General partner units
|
|
|
360,000
|
|
|
|
171,000
|
|
|
|
684,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
18,000,000
|
|
|
$
|
8,550,000
|
|
|
$
|
34,200,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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(1)
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|
Assumes the underwriters do not
exercise their option to purchase additional common units. If
the underwriters do not exercise their option to purchase an
additional 810,000 common units, we will issue the
additional 810,000 common units to the Contributing
Parties, upon the expiration of the option. To the extent the
underwriters exercise their option to purchase additional common
units, the number of units purchased by the underwriters
pursuant to such exercise will be issued to the public, and the
remainder, if any, will be issued to the Contributing Parties.
Accordingly, the exercise of the underwriters option will
not affect the total number of units outstanding or the amount
of cash needed to pay the initial quarterly distribution on all
units.
|
|
|
|
(2)
|
|
Does not include any common units
that may be issued under the long-term incentive program that
our general partner is expected to adopt prior to the closing of
this offering.
|
|
|
|
(3)
|
|
Includes 1,356,027 common
units held by the Founders and 8,986,988 common units held
by Yorktown.
|
Our partnership agreement provides that any determination made
by our general partner in its capacity as our general partner
must be made in good faith and that any such determination will
not be subject to any other standard imposed by our partnership
agreement, the Delaware limited partnership statute or any other
law, rule or regulation or imposed at equity. Holders of our
common units may pursue judicial action to enforce provisions of
our partnership agreement, including those related to
requirements to make cash distributions as described above.
However, our partnership agreement provides that our general
partner is entitled to make the determinations described above
without regard to any standard other than the requirement to act
in good faith. Our partnership agreement provides that, in order
for a determination by our general partner to be made in
good faith, our general partner must believe that
the determination is in the best interests of the Partnership.
Please read Conflicts of Interest and Fiduciary
Duties.
Our cash distribution policy, as expressed in our partnership
agreement, may not be modified or repealed without amending our
partnership agreement. The actual amount of our cash
distributions for any quarter is subject to fluctuation based on
the amount of cash we generate from our business and the amount
of reserves our general partner establishes in accordance with
our partnership agreement as described above. Our partnership
agreement, including provisions contained therein requiring us
to make cash distributions, may be amended by a vote of the
holders of a majority of our common units. At the closing of
this offering, the Founders will own and control our general
partner, and the Founders and Yorktown will own approximately
58.6% of our outstanding common
53
units, or 58.6% of our limited partner interests. Assuming we
do not issue any additional common units and the Founders and
Yorktown do not transfer their common units, they will have the
ability to amend our partnership agreement without the approval
of any other unitholder. Please read The Partnership
AgreementAmendment of the Partnership Agreement.
We will pay our quarterly distributions on or about the
15th of February, May, August and November to holders of
record on or about the 1st day of each such month. If the
distribution date does not fall on a business day, we will make
the distribution on the business day immediately preceding the
indicated distribution date. For our first quarterly
distribution, we will prorate the initial quarterly distribution
payable for the period from the closing of this offering through
December 31, 2011 based on the actual length of the period.
We expect to pay this cash distribution on or before
February 15, 2012.
In the sections that follow, we present in detail the basis for
our belief that we will be able to fully fund our initial
quarterly distribution of $0.475 per unit for the year ending
December 31, 2012. In those sections, we present two
tables, consisting of:
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Unaudited Pro Forma Available Cash, in which we
present the amount of cash we would have had available for
distribution to our unitholders and our general partner for the
year ended December 31, 2010 and the twelve months ended
September 30, 2011, based on our unaudited pro forma
financial statements. Our calculation of unaudited pro forma
available cash in this table should only be viewed as a general
indication of the amount of available cash that we might have
generated had the formation transactions contemplated in this
prospectus occurred in an earlier period; and
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|
|
|
Estimated Cash Available for Distribution, in which
we demonstrate our ability to generate the minimum Adjusted
EBITDA necessary for us to have sufficient cash available for
distribution to pay the full initial quarterly distribution on
all the outstanding units, including our general partner units,
for the year ending December 31, 2012.
|
Unaudited
Pro Forma Available Cash for the Year Ended December 31,
2010 and the Twelve Months Ended September 30,
2011
If we had completed the formation transactions contemplated in
this prospectus on January 1, 2010, our unaudited pro forma
available cash for the year ended December 31, 2010 would
have been approximately $5.4 million. This amount would
have been sufficient to pay a cash distribution of $0.075 per
unit per quarter ($0.30 on an annualized basis), or
approximately 15.8% of the initial quarterly distribution on our
common units during that period.
If we had completed the transactions contemplated in this
prospectus on October 1, 2010, our unaudited pro forma
available cash generated for the twelve months ended
September 30, 2011 would have been approximately
$15.8 million. This amount would have been sufficient to
pay a cash distribution of $0.219 per unit per quarter ($0.878
on an annualized basis), or approximately 46.3% of the initial
quarterly distribution on our common units during that period.
Our unaudited pro forma cash available for distribution includes
incremental general and administrative expenses that we expect
we will incur as a result of being a publicly traded
partnership, consisting of costs associated with SEC reporting
requirements, including annual and quarterly reports to
unitholders, tax return and
Schedule K-1
preparation and distribution, independent auditor fees, investor
relations activities, Sarbanes-Oxley Act compliance, NASDAQ
Global Market listing, registrar and transfer agent fees,
incremental director and officer liability insurance costs and
officer and director compensation. We estimate that these
incremental general and administrative expenses initially will
be approximately $3.0 million per year. These incremental
general and administrative expenses are not reflected in our pro
forma Adjusted EBITDA or in our historical and pro forma
financial statements.
54
The pro forma financial statements, from which pro forma cash
available for distribution is derived, do not purport to present
our results of operations had the transactions contemplated in
this prospectus actually been completed as of the dates
indicated. Furthermore, cash available for distribution is a
cash accounting concept, while our unaudited pro forma financial
statements have been prepared on an accrual basis. We derived
the amounts of pro forma cash available for distribution stated
above in the manner described in the table below. As a result,
the amount of pro forma cash available for distribution should
only be viewed as a general indication of the amount of cash
available for distribution that we might have generated had we
been formed and completed the transactions contemplated in this
prospectus in earlier periods.
The following table illustrates, on an unaudited pro forma basis
for the year ended December 31, 2010 and the twelve months
ended September 30, 2011, the amount of available cash that
would have been available for distribution to our unitholders,
assuming that the formation transactions had been consummated on
January 1, 2010 and October 1, 2010, respectively.
Each of the pro forma adjustments reflected or presented below
is explained in the footnotes to such adjustments.
55
Mid-Con
Energy Partners, LP
Unaudited Pro Forma Available Cash
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|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
Year
|
|
|
Twelve Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2010
|
|
|
2011
|
|
|
|
(in thousands, except per unit data)
|
|
|
|
(restated)
|
|
|
|
|
|
Net income
|
|
$
|
3,668
|
|
|
$
|
18,980
|
|
Plus:
|
|
|
|
|
|
|
|
|
Income tax expense (benefit), if any
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
1,350
|
|
|
|
1,350
|
|
Depreciation, depletion and amortization
|
|
|
3,327
|
|
|
|
4,771
|
|
Accretion of discount on asset retirement obligations
|
|
|
63
|
|
|
|
71
|
|
Unrealized (gain) loss on derivatives, net
|
|
|
707
|
|
|
|
(7,280
|
)
|
Impairment of proved oil and gas properties
|
|
|
1,260
|
|
|
|
1,234
|
|
Dry hole costs and abandonments of unproved properties
|
|
|
514
|
|
|
|
1,149
|
|
Interest income
|
|
|
(126
|
)
|
|
|
(179
|
)
|
Stock-based compensation
|
|
|
|
|
|
|
1,671
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA(1)
|
|
$
|
10,763
|
|
|
$
|
21,767
|
|
Less:
|
|
|
|
|
|
|
|
|
Incremental general and administrative expense(2)
|
|
|
3,000
|
|
|
|
3,000
|
|
Cash interest expense(3)
|
|
|
1,350
|
|
|
|
1,350
|
|
Maintenance capital expenditures(4)
|
|
|
1,014
|
|
|
|
1,596
|
|
|
|
|
|
|
|
|
|
|
Pro Forma Available cash
|
|
$
|
5,399
|
|
|
$
|
15,821
|
|
Pro Forma Annualized distributions per unit
|
|
|
1.90
|
|
|
|
1.90
|
|
Pro Forma Estimated annual cash distributions:
|
|
|
|
|
|
|
|
|
Distributions on common units held by purchasers in this offering
|
|
$
|
10,260
|
|
|
$
|
10,260
|
|
Distributions on common units held by the Contributing Parties
|
|
|
23,256
|
|
|
|
23,256
|
|
Distributions on general partner units
|
|
|
684
|
|
|
|
684
|
|
|
|
|
|
|
|
|
|
|
Total estimated annual cash distributions
|
|
$
|
34,200
|
|
|
$
|
34,200
|
|
|
|
|
|
|
|
|
|
|
Shortfall
|
|
$
|
(28,801
|
)
|
|
$
|
(18,379
|
)
|
|
|
|
|
|
|
|
|
|
Percent of initial quarterly distributions payable to common
unitholders
|
|
|
15.8
|
%
|
|
|
46.3
|
%
|
|
|
|
(1)
|
|
Adjusted EBITDA is defined in
Prospectus SummaryNon-GAAP Financial
Measures.
|
|
(2)
|
|
Reflects the $3.0 million of
estimated incremental annual general and administrative expenses
associated with being a publicly traded partnership that we
expect to incur.
|
|
(3)
|
|
In connection with this offering,
we intend to enter into a new $250.0 million credit
facility under which we expect to incur approximately
$45.0 million of borrowings upon the closing of this
offering. The pro forma cash interest expense is based on
$45.0 million of borrowings at an assumed weighted-average
rate of 3.0%.
|
|
(4)
|
|
We define maintenance capital
expenditures as capital expenditures that we expect to make on
an ongoing basis to maintain waterflood operations over the
long-term. We define growth capital expenditures as those that
we expect to make to either develop new waterfloods or add
primary production through newly initiated development programs.
Following this offering, we generally expect to fund maintenance
capital expenditures with cash flow from operations, while we
plan primarily to use external financing sources, including
borrowings under our new credit facility and the issuance of
debt and equity securities, to fund growth capital expenditures.
Historically, we did not distinguish between maintenance capital
expenditures and growth capital expenditures. As a result, the
amounts included in the table above represent the approximate
amounts of our total capital expenditures for the periods
presented that we believe would have been maintenance capital
expenditures in those periods. Excluded are approximately
$18.7 million and $40.0 million of capital
expenditures for the year ended December 31, 2010 and the
twelve months ended September 30, 2011, respectively, which
are the amounts of capital expenditures that we believe would
have been growth capital expenditures in those periods.
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56
Estimated
Adjusted EBITDA for the Year Ending December 31,
2012
Set forth below is a Statement of Estimated Adjusted EBITDA that
supports our belief that we will be able to generate sufficient
cash available for distribution to pay the aggregate annualized
initial quarterly distribution on all of our outstanding units
for the twelve months ending December 31, 2012. The
financial forecast presents, to the best of our knowledge and
belief, our expected results of operations, Adjusted EBITDA and
cash available for distribution for the forecast period. Based
upon the assumptions and considerations set forth in the table
below, to fund cash distributions to our unitholders at our
annualized initial quarterly distribution of $1.90 per common
unit and general partner unit, or $34.2 million in the
aggregate, for the year ending December 31, 2012, our
Adjusted EBITDA for the year ending December 31, 2012 must
be at least $40.6 million. The number of outstanding common
units on which we have based such belief does not include any
common units that may be issued under the long-term incentive
program that our general partner is expected to adopt prior to
the closing of this offering.
Our Statement of Estimated Adjusted EBITDA reflects our
judgment, as of the date of this prospectus, of conditions we
expect to exist and the course of action we expect to take in
order to be able to pay the annualized initial quarterly
distribution on all of our outstanding common and general
partner units for the year ending December 31, 2012. The
assumptions discussed below under Assumptions and
Considerations are those that we believe are significant
to our ability to generate the minimum Adjusted EBITDA. We
believe our actual results of operations and cash flow will be
sufficient to generate the minimum Adjusted EBITDA necessary to
pay the aggregate annualized initial quarterly distribution. We
can, however, give you no assurance that we will generate this
amount. There will likely be differences between our estimated
Adjusted EBITDA and our actual results, and those differences
could be material. If we fail to generate the estimated Adjusted
EBITDA contained in our forecast, we may not be able to pay the
aggregate annualized initial quarterly distribution to all of
our unitholders.
While we do not as a matter of course make public projections as
to future sales, earnings or other results, our management has
prepared the prospective financial information that is the basis
of our estimated Adjusted EBITDA below to substantiate our
belief that we will have sufficient cash to pay the initial
quarterly distribution on all our common units and general
partner units for the year ending December 31, 2012. This
forecast is a forward-looking statement and should be read
together with our historical financial statements and the
accompanying notes included elsewhere in this prospectus and
Managements Discussion and Analysis of Financial
Condition and Results of Operations. The accompanying
prospective financial information was not prepared with a view
toward complying with the published guidelines of the SEC or the
guidelines established by the American Institute of Certified
Public Accountants with respect to prospective financial
information, but, in the view of our management, is
substantially consistent with those guidelines and was prepared
on a reasonable basis, reflects the best currently available
estimates and judgments, and presents, to the best of
managements knowledge and belief, the assumptions and
considerations on which we base our belief that we can generate
the minimum Adjusted EBITDA necessary for us to pay the initial
quarterly distribution on all of our outstanding common and
general partner units for the year ending December 31,
2012. Readers of this prospectus are cautioned not to place
undue reliance on this prospective financial information. Please
read Assumptions and Considerations.
The prospective financial information included in this
prospectus has been prepared by, and is the responsibility of,
our management. Grant Thornton LLP has not compiled, examined or
performed any procedures with respect to the accompanying
prospective financial information and, accordingly, Grant
Thornton LLP does not express an opinion or any other form of
assurance with respect thereto. The Grant Thornton LLP reports
included in the registration statement relate to our historical
financial information. It does not extend to the prospective
financial information and should not be read to do so.
57
When considering our financial forecast, you should keep in mind
the risk factors and other cautionary statements under
Risk Factors. Any of the risks discussed in this
prospectus, to the extent they are realized, could cause our
actual results of operations to vary significantly from those
that would enable us to generate the minimum Adjusted EBITDA
necessary to pay the aggregate annualized initial quarterly
distribution on all of our outstanding common and general
partner units for the year ending December 31, 2012.
We are providing the Statement of Estimated Adjusted EBITDA to
supplement our historical financial statements and in support of
our belief that we will have sufficient available cash to pay
the aggregate annualized initial quarterly distribution on all
of our outstanding common and general partner units for the year
ending December 31, 2012. Please read below under
Assumptions and Considerations for further
information about the assumptions we have made for the financial
forecast.
We do not undertake any obligation to release publicly the
results of any future revisions we may make to this prospective
financial information or to update this prospective financial
information to reflect events or circumstances after the date of
this prospectus. Therefore, you are cautioned not to place undue
reliance on this information.
Our Estimated Adjusted EBITDA
To pay the annualized initial quarterly distribution to our
unitholders of $0.475 per unit for the year ending
December 31, 2012, our aggregate cash available to pay
distributions must be at least approximately $8.6 million
over that period. We have calculated that the amount of
estimated Adjusted EBITDA for the year ending December 31,
2012 that will be necessary to generate cash available to pay an
aggregate annualized distribution of approximately
$34.2 million over that period is approximately
$40.6 million. Adjusted EBITDA should not be considered an
alternative to net income, income before income taxes, cash flow
from operating activities or any other measure calculated in
accordance with GAAP.
Adjusted EBITDA is a significant financial metric that will be
used by our management to indicate (prior to the establishment
of any reserves by the board of directors of our general
partner) the cash distributions we expect to pay to our
unitholders. Specifically, we intend to use this financial
measure to assist us in determining whether we are generating
operating cash flow at a level that can sustain or support an
increase in our quarterly distribution rates. For a definition
of Adjusted EBITDA, please read Prospectus
SummaryNon-GAAP Financial Measures.
58
Mid-Con
Energy Partners, LP
Statement of Estimated Adjusted EBITDA
|
|
|
|
|
|
|
Year Ending
|
|
|
|
December 31, 2012
|
|
|
|
(in thousands, except
|
|
|
|
per unit amounts)
|
|
|
Revenue and realized commodity derivative gains(losses)(1)
|
|
$
|
63,832
|
|
Less:
|
|
|
|
|
Lease operating expenses
|
|
|
9,396
|
|
Oil and gas production taxes
|
|
|
3,043
|
|
General and administrative(2)
|
|
|
4,000
|
|
Depreciation, depletion and amortization
|
|
|
15,000
|
|
Interest expense
|
|
|
1,350
|
|
|
|
|
|
|
Net income excluding unrealized gains (losses) on derivatives
|
|
$
|
31,043
|
|
Adjustments to reconcile net income excluding unrealized
derivative gains (losses) to estimated Adjusted EBITDA:
|
|
|
|
|
Add:
|
|
|
|
|
Depreciation, depletion and amortization
|
|
$
|
15,000
|
|
Interest expense
|
|
|
1,350
|
|
|
|
|
|
|
Estimated Adjusted EBITDA(3)
|
|
$
|
47,393
|
|
Adjustments to reconcile estimated Adjusted EBITDA to
estimated cash available for distribution:
|
|
|
|
|
Less:
|
|
|
|
|
Cash interest expense
|
|
$
|
1,350
|
|
Maintenance capital expenditures(4)
|
|
|
5,000
|
|
|
|
|
|
|
Estimated cash available for distribution
|
|
$
|
41,043
|
|
Annualized initial quarterly distribution per unit
|
|
$
|
1.90
|
|
Estimated annual cash distributions(5):
|
|
|
|
|
Distributions on common units held by purchasers in this offering
|
|
$
|
10,260
|
|
Distributions on common units held by the Contributing Parties
|
|
|
23,256
|
|
Distributions on general partner units
|
|
|
684
|
|
Total estimated annual cash distributions
|
|
$
|
34,200
|
|
Excess cash available for distribution
|
|
$
|
6,843
|
|
|
|
|
(1)
|
|
Includes the forecasted effect of
cash settlements of commodity derivative instruments. This
amount does not include unrealized commodity derivative gains
(losses), as such amounts represent non-cash items and cannot be
reasonably estimated in the forecast period.
|
|
(2)
|
|
Includes $3.0 million of
estimated incremental annual general and administrative expenses
associated with being a publicly traded partnership that we
expect to incur.
|
|
(3)
|
|
Adjusted EBITDA is defined in
Prospectus SummaryNon-GAAP Financial
Measures.
|
|
(4)
|
|
Reflects estimated maintenance
capital expenditures for the year ending December 31, 2012.
We define maintenance capital expenditures as those we expect to
make on an ongoing basis to maintain our waterflood operations
over the long-term. Following this offering, we generally expect
to fund maintenance capital expenditures with cash flow from
operations.
|
|
|
|
(5)
|
|
The number of outstanding common
units assumed herein does not include any common units that may
be issued under the long-term incentive program that our general
partner is expected to adopt prior to the closing of this
offering. We estimate that the maximum number of awards that we
would grant during the year ending December 31, 2012 under
the long-term incentive program would be an aggregate of 350,000
restricted units, phantom units or other unit-based awards. If
all of the 350,000 units underlying such awards were
entitled to receive four quarterly distributions at the initial
distribution rate during the year ending December 31, 2012,
the aggregate amount distributable on such units would be
$665,000. In that case, the amount of our excess cash available
for distribution for the year would be reduced to $6,178,000.
|
59
Assumptions
and Considerations
Based upon the specific assumptions outlined below with respect
to the year ending December 31, 2012, we expect to generate
estimated Adjusted EBITDA sufficient to establish reserves for
capital expenditures and to pay the aggregate annualized initial
quarterly distribution on all common and general partner units
for the year ending December 31, 2012.
While we believe that these assumptions are reasonable in light
of managements current expectations concerning future
events, the estimates underlying these assumptions are
inherently uncertain and are subject to significant business,
economic, regulatory, environmental and competitive risks and
uncertainties that could cause actual results to differ
materially from those we anticipate. If our assumptions do not
materialize, the amount of actual cash available to pay
distributions could be substantially less than the amount we
currently estimate and could, therefore, be insufficient to
permit us to pay quarterly cash distributions equal to our
initial quarterly distribution (absent additional borrowings
under our new revolving credit facility), or any amount, on all
common and general partner units, in which event the market
price of our common units may decline substantially. We are
unlikely to be able to sustain our initial quarterly
distribution over the
long-term
without making accretive acquisitions or substantial capital
expenditures that maintain the current production levels of our
oil and natural gas properties. We expect to rely primarily on
external financing sources, including bank borrowings and the
issuance of equity and debt securities, rather than operating
cash flow to fund our growth capital expenditures. If we do not
make sufficient cash expenditures from operating cash flow to
maintain the current production levels of our oil and natural
gas properties, we may be unable to pay distributions at our
initial quarterly distribution rate or the then-current
distribution rate from cash generated from operations and would
therefore expect to reduce our distributions over time. In
addition, decreases in commodity prices from current levels will
adversely affect our ability to pay distributions. When reading
this section, you should keep in mind the risk factors and other
cautionary statements described under Risk Factors
and Forward-Looking Statements. Any of the risks
discussed in this prospectus could cause our actual results to
vary significantly from our estimates.
Operations and Revenue
Production. The following table sets forth
information regarding net production of oil and natural gas on a
pro forma basis for the year ended December 31, 2010 and
the twelve months ended September 30, 2011 and on a
forecasted basis for the year ending December 31, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
Pro Forma
|
|
|
Forecasted
|
|
|
|
Year Ended
|
|
|
Twelve Months
|
|
|
Year Ending
|
|
|
|
December 31,
|
|
|
Ended September 30,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Annual production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
220
|
|
|
|
347
|
|
|
|
659
|
|
Natural gas (MMcf)
|
|
|
184
|
|
|
|
158
|
|
|
|
115
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
250
|
|
|
|
373
|
|
|
|
678
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average net daily production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl/d)
|
|
|
602
|
|
|
|
951
|
|
|
|
1,800
|
|
Natural Gas (Mcf/d)
|
|
|
505
|
|
|
|
434
|
|
|
|
314
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Boe/d)
|
|
|
686
|
|
|
|
1,023
|
|
|
|
1,852
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60
We estimate that our total oil and natural gas production for
the year ending December 31, 2012 will be 1,852 Boe per day
as compared to 686 Boe per day on a pro forma basis for the year
ended December 31, 2010 and 1,023 Boe per day on a pro
forma basis for the twelve months ended September 30, 2011.
For the months ended June 30, 2011, July 31, 2011,
August 31, 2011 and September 30, 2011, our average
net production was 1,248 Boe per day, 1,272 Boe per day, 1,327
Boe per day and 1,343 Boe per day, respectively. The 2012
forecast reflects a 509 Boe per day production increase from our
September 30, 2011 production. A portion of this increase
relates to our Highlands Unit. Under the unitization order
governing the Highlands Unit, the working and net revenue
interests of each owner in the unit depend on the classification
of reserves currently produced from the unit. The unitization
order divides reserves into two classifications based on agreed
upon volumesthose capable of production under primary
recovery techniques and those capable of production under
secondary recovery techniques (e.g., waterflooding). Our working
and net revenue interests in the Highlands Unit for the first
reserve category were 44.5% and 36.3%, respectively, but
increased to 57.5% and 46.8%, respectively, when the unit began
producing from the second reserve category on November 1,
2011. During September 2011, our average net production from the
Highlands Unit was 238 Boe day. Had the unit been producing from
the second reserve category during that same time, our average
net production would have been 307 Boe per day. We have similar
arrangements in place in several of our other units, and many of
these units have already begun producing from the second reserve
category, resulting in an increase in our working and net
revenue interests.
Since January 2010 we have drilled approximately 78 gross
(47 net) infill development wells, mostly in our Southern
Oklahoma core area. Approximately half of these wells are
injection wells, which have allowed us to increase injection in
our waterflood units, leading to higher reservoir pressures and
ultimately increases in our production over time. We spent
approximately $12.9 million on this drilling program in
2010 and have spent approximately $22.3 million in the
first nine months of 2011. We expect to spend approximately
$5.2 million on these activities during the last three
months of 2011. The typical response time for waterflood
projects after injection is initiated ranges from six to
eighteen months, and consequently, our capital expenditures do
not ordinarily result in corresponding immediate increases in
our production levels or consistent increases over a period of
time. However, we believe that our capital expenditures in 2010
and 2011 will enable us to achieve our forecasted production
level of 1,852 Boe per day for the year ending December 31,
2012. In addition, we estimate that we will spend an average of
$5.0 million per year on maintenance capital expenditures
in order to maintain our forecasted production level, which we
intend to fund with cash generated from operations.
Prices. The table below illustrates the
relationship between average oil and natural gas realized sales
prices and average NYMEX prices on a pro forma basis for the
year ended
61
December 31, 2010 and the twelve months ended
September 30, 2011 and our forecast for the year ending
December 31, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
Pro Forma
|
|
Forecasted
|
|
|
Year Ended
|
|
Twelve Months
|
|
Year Ending
|
|
|
December 31,
|
|
Ended September 30,
|
|
December 31,
|
|
|
2010
|
|
2011
|
|
2012
|
|
Average oil sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily NYMEX-WTI oil price per Bbl
|
|
$
|
79.61
|
|
|
$
|
94.50
|
|
|
$
|
96.00
|
|
Differential to NYMEX-WTI oil per Bbl
|
|
$
|
(5.46
|
)
|
|
$
|
(6.22
|
)
|
|
$
|
(3.08
|
)
|
Realized oil sales price per Bbl (excluding cash settlements of
derivatives)
|
|
$
|
74.15
|
|
|
$
|
88.28
|
|
|
$
|
92.92
|
|
Realized oil sales price per Bbl (including cash settlements of
derivatives)
|
|
$
|
73.69
|
|
|
$
|
85.74
|
|
|
$
|
95.75
|
|
Average natural gas sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily NYMEX-Henry Hub natural gas price per MMBtu
|
|
$
|
4.38
|
|
|
$
|
4.17
|
|
|
$
|
3.86
|
|
Differential to NYMEX-Henry Hub natural gas per MMBtu
|
|
$
|
3.18
|
|
|
$
|
3.71
|
|
|
$
|
2.70
|
|
Realized natural gas sales price per Mcf(1)
|
|
$
|
7.58
|
|
|
$
|
7.88
|
|
|
$
|
6.56
|
|
|
|
|
(1)
|
|
We had no natural gas derivative
contracts for the pro forma periods and assume that we will not
enter into any such contracts for the year ending
December 31, 2012. Realized natural gas sales price per Mcf
includes the sale of natural gas liquids.
|
Price Differentials. Our oil production, which
is predominantly light sweet oil, typically sells at
a discount to the NYMEX-WTI price due to quality, transportation
fees, location differentials, marketing bonuses or deductions
and other factors affecting the price received at the wellhead.
Our natural gas production has historically sold at a positive
basis differential from the NYMEX-Henry Hub price primarily due
to the rich Btu and liquids content of the production
attributable to our operating areas. The adjustments we have
made to reflect the basis differentials for our forecasted
production during the year ending December 31, 2012 are
presented in the following table and shown per Bbl for oil and
per Mcf for natural gas, as adjusted to reflect our oil purchase
contracts effective as of January 1, 2012.
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
Natural Gas
|
Operating Area
|
|
Per Bbl
|
|
Per Mcf(1)
|
|
Southern Oklahoma
|
|
$
|
(3.64
|
)
|
|
$
|
0.92
|
|
Northeastern Oklahoma
|
|
$
|
(1.37
|
)
|
|
$
|
(1.61
|
)
|
Hugoton Basin
|
|
$
|
(4.21
|
)
|
|
$
|
(1.20
|
)
|
Other
|
|
$
|
(1.35
|
)
|
|
$
|
4.39
|
|
Weighted Average
|
|
$
|
(3.08
|
)
|
|
$
|
2.70
|
|
|
|
|
(1)
|
|
Realized natural gas sales price
per Mcf includes the sale of natural gas liquids.
|
62
Use of Commodity Derivative Contracts. For
purposes of our forecast, we have assumed that our commodity
derivative contracts will cover 360 MBbl, or approximately
55%, of our forecasted total oil production of 659 MBbl for the
year ending December 31, 2012. Our commodity derivative
contracts consist of swap and collar agreements based upon
NYMEX-WTI prices. The table below shows the volumes and prices
covered by the commodity derivative contracts for the year
ending December 31, 2012. For purposes of our forecast, we
have assumed that we will not enter into natural gas derivative
contracts or additional oil derivative contracts during the
forecast period, although we may do so on an opportunistic basis
if market conditions are favorable.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps
|
|
Collars
|
|
|
|
|
Weighted
|
|
|
|
Weighted
|
|
Weighted
|
|
|
|
|
Average
|
|
|
|
Average
|
|
Average
|
|
|
Bbl
|
|
Price
|
|
Bbl
|
|
Floor Price
|
|
Ceiling Price
|
|
Oil:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
JanuaryDecember 2012
|
|
|
288,000
|
|
|
$
|
101.47
|
|
|
|
72,000
|
|
|
$
|
100.00
|
|
|
$
|
117.00
|
|
% of forecasted oil production
|
|
|
43.72
|
%
|
|
|
|
|
|
|
10.93
|
%
|
|
|
|
|
|
|
|
|
Operating Revenues and Realized Commodity Derivative
Gains. The following table illustrates the
primary components of operating revenues and realized commodity
derivative gains on a pro forma basis for the year ended
December 31, 2010 and the twelve months ended
September 30, 2011 and on a forecasted basis for the year
ending December 31, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
Pro Forma
|
|
|
Forecasted
|
|
|
|
Year Ended
|
|
|
Twelve Months
|
|
|
Year Ending
|
|
|
|
December 31,
|
|
|
Ended September 30,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
|
(in thousands)
|
|
|
Oil:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenues
|
|
$
|
16,286
|
|
|
$
|
30,640
|
|
|
$
|
61,216
|
|
Realized oil derivative instruments gain (loss)
|
|
|
(100
|
)
|
|
|
(879
|
)
|
|
|
1,862
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
16,186
|
|
|
$
|
29,761
|
|
|
$
|
63,078
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenues(1)
|
|
$
|
1,397
|
|
|
$
|
1,248
|
|
|
$
|
754
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
We had no natural gas derivative
contracts for the pro forma periods and assume that we will not
enter into any such contracts for the year ending
December 31, 2012. Realized natural gas sales price per Mcf
includes the sale of natural gas liquids.
|
63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
Pro Forma
|
|
|
Forecasted
|
|
|
|
Year Ended
|
|
|
Twelve Months
|
|
|
Year Ending
|
|
|
|
December 31,
|
|
|
Ended September 30,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
|
(in thousands)
|
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
17,683
|
|
|
$
|
31,888
|
|
|
$
|
61,970
|
|
Commodity derivative instruments gain (loss)
|
|
|
(100
|
)
|
|
|
(879
|
)
|
|
|
1,862
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue and realized commodity derivative instruments
gains
|
|
$
|
17,583
|
|
|
$
|
31,009
|
|
|
$
|
63,832
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures and Expenses
Capital Expenditures. Historically, we did not
distinguish between maintenance capital expenditures and growth
capital expenditures, but we believe that approximately
$1.0 million and $1.6 million of our total capital
expenditures for the year ended December 31, 2010 and the
twelve months ended September 30, 2011, respectively, would
have been maintenance capital expenditures. We believe that the
balance of our capital expenditures for those periods,
$18.7 million and $40.0 million, respectively, would
have been growth capital expenditures. Through these growth
capital expenditures, we have significantly increased our
production levels. As a result, we anticipate that our
maintenance capital expenditures will increase significantly
during the year ending December 31, 2012 as compared to the
year ended December 31, 2010 and the twelve months ended
September 30, 2011 in order to maintain our forecasted
production level of 1,852 Boe per day. For the forecast period,
we estimate that we will drill 9 gross (5 net) wells and
spend additional maintenance capital on workovers at an average
annual aggregate net cost of approximately $5.0 million.
Although we may make acquisitions during the year ending
December 31, 2012, our forecast period does not reflect any
acquisitions or other growth capital expenditures because we
cannot be certain that we will be able to identify attractive
properties or, if identified, that we will be able to negotiate
acceptable purchase terms.
Lease Operating Expenses. The following table
summarizes lease operating expenses on an aggregate basis and on
a per Boe basis for the year ended December 31, 2010, pro
forma, the twelve months ended September 30, 2011, pro
forma, and on a forecasted basis for the year ending
December 31, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
Pro Forma
|
|
Forecasted
|
|
|
Year Ended
|
|
Twelve Months
|
|
Year Ending
|
|
|
December 31,
|
|
Ended September 30,
|
|
December 31,
|
|
|
2010
|
|
2011
|
|
2012
|
|
Lease operating expenses (in thousands)
|
|
$
|
5,041
|
|
|
$
|
7,074
|
|
|
$
|
9,396
|
|
Lease operating expenses (per Boe)
|
|
$
|
20.14
|
|
|
$
|
18.94
|
|
|
$
|
13.86
|
|
We estimate that our lease operating expenses for the year
ending December 31, 2012 will be approximately
$9.4 million. On a pro forma basis, for the year ended
December 31, 2010 and the twelve months ended
September 30, 2011, lease operating expenses were
$5.0 million and $7.1 million, respectively. The
increase in forecasted lease operating expenses is primarily a
64
result of increased drilling activity and production. The
decrease in lease operating expenses per Boe is a result of the
projected increase in production. Lease operating expenses also
include ad valorem taxes, which are generally tied to the
valuation of the oil and natural gas properties. These
valuations are generally correlated to revenues, excluding the
effects of our commodity derivative contracts. As a result, we
forecast our ad valorem taxes as a percent of revenues,
excluding the effects of commodity derivative contracts.
Production Taxes. The following table
summarizes production taxes before the effects of our commodity
derivative contracts on a pro forma basis for the year ended
December 31, 2010, the twelve months ended
September 30, 2011 and on a forecasted basis for the year
ending December 31, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
Pro Forma
|
|
Forecasted
|
|
|
Year Ended
|
|
Twelve Months
|
|
Year Ending
|
|
|
December 31,
|
|
Ended September 30,
|
|
December 31,
|
|
|
2010
|
|
2011
|
|
2012
|
|
|
(in thousands)
|
|
Oil and natural gas revenues, excluding the effect of our
commodity derivative contracts
|
|
$
|
17,683
|
|
|
$
|
31,888
|
|
|
$
|
61,970
|
|
Production taxes
|
|
$
|
797
|
|
|
$
|
1,415
|
|
|
$
|
3,043
|
|
Production taxes as a percentage of revenue
|
|
|
4.51
|
%
|
|
|
4.43
|
%
|
|
|
4.91
|
%
|
Our production taxes are calculated as a percentage of our oil
and natural gas revenues, excluding the effects of our commodity
derivative contracts. In general, as prices and volumes
increase, our production taxes increase. As prices and volumes
decrease, our production taxes decrease. Additionally,
production tax rates vary by state, and as revenues by state
vary, our production taxes will increase or decrease. The State
of Oklahoma, where most of our properties are located, currently
imposes a production tax of 7.2% for oil and natural gas
properties, and an excise tax of 0.095%. A portion of our wells
in the State of Oklahoma currently receive a reduced production
tax rate due to the Enhanced Recovery Project Gross Production
Tax Exemption. The State of Colorado currently imposes a 1.0%
production tax for oil properties.
General and Administrative Expenses. In
connection with the closing of this offering, we will enter into
a services agreement with Mid-Con Energy Operating with respect
to all general and administrative expenses and costs it incurs
on our general partners and our behalf, including
$3.0 million of incremental annual expenses we expect to
incur as a result of becoming a publicly traded partnership.
General and administrative expenses related to being a publicly
traded partnership include expenses associated with annual and
quarterly reporting; tax return and
Schedule K-1
preparation and distribution expenses; Sarbanes-Oxley compliance
expenses; expenses associated with listing on the NASDAQ Global
Market; independent auditor fees; legal fees; investor relations
expenses; registrar and transfer agent fees; director and
officer liability insurance costs and director and officer
compensation. Under the services agreement, Mid-Con Energy
Operating will be reimbursed for all general and administrative
expenses allocated to us under the services agreement.
Depreciation, Depletion and Amortization
Expense. We estimate that our depreciation,
depletion and amortization expense for the year ending
December 31, 2012 will be approximately $15.0 million,
as compared to $3.3 million and $4.8 million on a pro
forma basis for the year ending December 31, 2010 and the
twelve months ended September 30, 2011, respectively. The
forecasted increase in the depletion of our oil and natural gas
properties is primarily based on the forecasted increase in our
production. Our capitalized costs are calculated using the
successful efforts method of accounting. For a detailed
description of the successful efforts method of
65
accounting, please read Managements Discussion and
Analysis of Financial Condition and Results of
OperationsCritical Accounting Policies and Estimates.
Cash Interest Expense. We estimate that at the
closing of this offering we will borrow approximately
$45.0 million in revolving debt under our new
$250.0 million credit facility. We estimate that the
borrowings will bear interest at a weighted average rate of
approximately 3.0%. Based on these assumptions, we estimate that
our cash interest expense for the year ending December 31,
2012 will be $1.4 million and on a pro forma basis for both
the year ended December 31, 2010 and the twelve months
ended September 30, 2011.
Our new credit facility will contain financial covenants that
require us to maintain a leverage ratio of not more than 4.0 to
1.0x and a current ratio of not less than 1.0 to 1.0x. Please
see Managements Discussion and Analysis of Financial
Condition and Results of OperationsLiquidity and Capital
ResourcesNew Credit Facility for additional detail
regarding the covenants and restrictive provisions to be
included in our new credit facility. Our new credit facility
will not require any cash expenditures on our part that would
affect our cash available for distribution other than cash
interest expense and unused facility fees.
Regulatory,
Industry and Economic Factors
Our forecast for the year ending December 31, 2012 is based
on the following significant assumptions related to regulatory,
industry and economic factors:
|
|
|
|
|
There will not be any new federal, state or local regulation of
portions of the energy industry in which we operate, or any
interpretation of existing regulations, that will be materially
adverse to our business;
|
|
|
|
There will not be any material nonperformance or credit-related
defaults by suppliers, customers or vendors, or shortage of
skilled labor;
|
|
|
|
All supplies and commodities necessary for production and
sufficient transportation will be readily available;
|
|
|
|
There will not be any major adverse change in commodity prices
or the energy industry in general;
|
|
|
|
There will not be any material accidents, releases,
weather-related incidents, unscheduled downtime or similar
unanticipated events, including any events that could lead to
force majeure under any of our marketing agreements;
|
|
|
|
There will not be any adverse change in the markets in which we
operate resulting from supply or production disruptions, reduced
demand for our product or significant changes in the market
prices for our product; and
|
|
|
|
Market, insurance, regulatory and overall economic conditions
will not change substantially.
|
Sensitivity
Analysis
Our ability to generate sufficient cash from operations to pay
cash distributions to our unitholders is a function of two
primary variables: (i) production volumes; and
(ii) commodity prices. In the tables below, we illustrate
the effect that changes in either of these variables, while
holding all other variables constant, would have on our ability
to generate sufficient cash from our operations to pay the
initial quarterly distribution on our outstanding common units
for the year ending December 31, 2012.
66
Production Volume Changes
The following table shows estimated Adjusted EBITDA under
production levels of 90%, 100% and 110% of the production level
we have forecasted for the year ending December 31, 2012.
The estimated Adjusted EBITDA amounts shown below are based on
the assumptions used in our forecast.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Forecasted
|
|
|
|
Net Production
|
|
|
|
90%
|
|
|
100%
|
|
|
110%
|
|
|
|
(in thousands, except per unit amounts)
|
|
|
Forecasted net production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
593
|
|
|
|
659
|
|
|
|
725
|
|
Natural gas (MMcf)
|
|
|
103
|
|
|
|
115
|
|
|
|
126
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
610
|
|
|
|
678
|
|
|
|
746
|
|
Oil (Bbl/d)
|
|
|
1,620
|
|
|
|
1,800
|
|
|
|
1,980
|
|
Natural gas (Mcf/d))
|
|
|
283
|
|
|
|
314
|
|
|
|
345
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Boe/d)
|
|
|
1,667
|
|
|
|
1,852
|
|
|
|
2,038
|
|
Forecasted prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX-WTI oil price (per Bbl)
|
|
$
|
96.00
|
|
|
$
|
96.00
|
|
|
$
|
96.00
|
|
Realized oil price (per Bbl) (excluding derivatives)
|
|
$
|
92.92
|
|
|
$
|
92.92
|
|
|
$
|
92.92
|
|
Realized oil price (per Bbl) (including derivatives)
|
|
$
|
96.06
|
|
|
$
|
95.75
|
|
|
$
|
95.49
|
|
NYMEX-Henry Hub natural gas price (per MMBtu)
|
|
$
|
3.86
|
|
|
$
|
3.86
|
|
|
$
|
3.86
|
|
Realized natural gas price (per Mcf)(1)(2)
|
|
$
|
6.56
|
|
|
$
|
6.56
|
|
|
$
|
6.56
|
|
67
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Forecasted
|
|
|
|
Net Production
|
|
|
|
90%
|
|
|
100%
|
|
|
110%
|
|
|
|
(in thousands, except per unit amounts)
|
|
|
Forecasted Adjusted EBITDA projection:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
55,773
|
|
|
$
|
61,970
|
|
|
$
|
68,166
|
|
Realized derivative gains (losses)
|
|
|
1,862
|
|
|
|
1,862
|
|
|
|
1,862
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue including realized derivative gains (losses)
|
|
$
|
57,635
|
|
|
$
|
63,832
|
|
|
$
|
70,028
|
|
Lease operating expenses(3)
|
|
|
8,457
|
|
|
|
9,396
|
|
|
|
10,336
|
|
Production taxes
|
|
|
2,738
|
|
|
|
3,043
|
|
|
|
3,347
|
|
General and administrative expenses
|
|
|
4,000
|
|
|
|
4,000
|
|
|
|
4,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Adjusted EBITDA
|
|
$
|
42,440
|
|
|
$
|
47,393
|
|
|
$
|
52,345
|
|
Minimum estimated Adjusted EBITDA(4)
|
|
|
40,550
|
|
|
|
40,550
|
|
|
|
40,550
|
|
Excess (shortfall) estimated cash available for distribution(4)
|
|
|
1,890
|
|
|
|
6,843
|
|
|
|
11,795
|
|
|
|
|
(1)
|
|
Realized natural gas sales price
per Mcf includes the sale of natural gas liquids.
|
|
(2)
|
|
We assume that we will not enter
into any natural gas derivative contracts for the year ending
December 31, 2012.
|
|
(3)
|
|
The calculation of lease operating
expenses includes ad valorem taxes.
|
|
|
|
(4)
|
|
We have calculated that the minimum
amount of estimated Adjusted EBITDA for the year ending
December 31, 2012 that will be necessary to generate cash
available to pay an aggregate annualized distribution on all of
our outstanding units over that period is approximately
$40.6 million. In the case where our production level is
90% of the production level we have forecasted for the year
ending December 31, 2012, we should have had an excess of
$1.9 million over the amount of cash available for
distribution necessary to pay such aggregate annualized
distribution.
|
Commodity Price Changes
The following table shows estimated Adjusted EBITDA under
various assumed NYMEX-WTI oil and NYMEX-Henry Hub natural gas
prices for the year ending December 31, 2012. For the year
ending December 31, 2012, we have assumed that commodity
derivative contracts will cover 360 MBoe, or approximately
55% of our estimated total oil production from proved reserves
for the year ending December 31, 2012, at a weighted
average floor price of $101.18 per Bbl of oil. In addition, the
estimated Adjusted EBITDA amounts shown below are based on
forecasted realized
68
commodity prices that take into account assumptions concerning
updated differentials based on new crude oil purchase contracts
that will be effective as of January 1, 2012.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per unit amounts)
|
|
|
NYMEX-WTI oil price (per Bbl):
|
|
$
|
76.00
|
|
|
$
|
86.00
|
|
|
$
|
96.00
|
|
|
$
|
106.00
|
|
|
$
|
116.00
|
|
NYMEX-Henry Hub natural gas price (per MMBtu):
|
|
$
|
2.86
|
|
|
$
|
3.36
|
|
|
$
|
3.86
|
|
|
$
|
4.36
|
|
|
$
|
4.86
|
|
Forecasted net production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
659
|
|
|
|
659
|
|
|
|
659
|
|
|
|
659
|
|
|
|
659
|
|
Natural gas (MMcf)
|
|
|
115
|
|
|
|
115
|
|
|
|
115
|
|
|
|
115
|
|
|
|
115
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
678
|
|
|
|
678
|
|
|
|
678
|
|
|
|
678
|
|
|
|
678
|
|
Oil (Bbl/d)
|
|
|
1,800
|
|
|
|
1,800
|
|
|
|
1,800
|
|
|
|
1,800
|
|
|
|
1,800
|
|
Natural gas (Mcf/d)
|
|
|
314
|
|
|
|
314
|
|
|
|
314
|
|
|
|
314
|
|
|
|
314
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Boe/d)
|
|
|
1,852
|
|
|
|
1,852
|
|
|
|
1,852
|
|
|
|
1,852
|
|
|
|
1,852
|
|
Forecasted prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX-WTI oil price (per Bbl)
|
|
$
|
76.00
|
|
|
$
|
86.00
|
|
|
$
|
96.00
|
|
|
$
|
106.00
|
|
|
$
|
116.00
|
|
Realized oil price (per Bbl) (excluding derivatives)
|
|
$
|
72.92
|
|
|
$
|
82.92
|
|
|
$
|
92.92
|
|
|
$
|
102.92
|
|
|
$
|
112.92
|
|
Realized oil price (per Bbl) (including derivatives)
|
|
$
|
86.68
|
|
|
$
|
91.21
|
|
|
$
|
95.75
|
|
|
$
|
100.94
|
|
|
$
|
106.57
|
|
NYMEX-Henry Hub natural gas price (per MMBtu)
|
|
$
|
2.86
|
|
|
$
|
3.36
|
|
|
$
|
3.86
|
|
|
$
|
4.36
|
|
|
$
|
4.86
|
|
Realized natural gas price (per Mcf)(1)(2)
|
|
$
|
5.56
|
|
|
$
|
6.06
|
|
|
$
|
6.56
|
|
|
$
|
7.06
|
|
|
$
|
7.56
|
|
Forecasted Adjusted EBITDA projection:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
48,679
|
|
|
$
|
55,324
|
|
|
$
|
61,970
|
|
|
$
|
68,615
|
|
|
$
|
75,261
|
|
Realized derivative gains (losses)
|
|
|
9,062
|
|
|
|
5,462
|
|
|
|
1,862
|
|
|
|
(1,306
|
)
|
|
|
(4,186
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue including realized derivative gains (losses)
|
|
|
57,741
|
|
|
|
60,786
|
|
|
|
63,832
|
|
|
|
67,309
|
|
|
|
71,075
|
|
Lease operating expenses(3)
|
|
|
9,396
|
|
|
|
9,396
|
|
|
|
9,396
|
|
|
|
9,396
|
|
|
|
9,396
|
|
Production taxes
|
|
|
2,390
|
|
|
|
2,716
|
|
|
|
3,043
|
|
|
|
3,369
|
|
|
|
3,695
|
|
General and administrative expenses
|
|
|
4,000
|
|
|
|
4,000
|
|
|
|
4,000
|
|
|
|
4,000
|
|
|
|
4,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Adjusted EBITDA
|
|
$
|
41,955
|
|
|
$
|
44,674
|
|
|
$
|
47,393
|
|
|
$
|
50,544
|
|
|
$
|
53,984
|
|
Minimum estimated Adjusted EBITDA
|
|
|
40,550
|
|
|
|
40,550
|
|
|
|
40,550
|
|
|
|
40,550
|
|
|
|
40,550
|
|
Excess (shortfall) estimated cash available for distribution(4)
|
|
|
1,405
|
|
|
|
4,124
|
|
|
|
6,843
|
|
|
|
9,994
|
|
|
|
13,434
|
|
|
|
|
(1)
|
|
Realized natural gas sales price
per Mcf includes the sale of natural gas liquids.
|
|
(2)
|
|
We assume that we will not enter
into any natural gas derivative contracts for the year ending
December 31, 2012.
|
|
(3)
|
|
The calculation of lease operating
expenses includes ad valorem taxes.
|
|
|
|
(4)
|
|
We have calculated that the minimum
amount of estimated Adjusted EBITDA for the year ending
December 31, 2012 that will be necessary to generate cash
available to pay an aggregate annualized distribution on all of
our outstanding units over that period is approximately
$40.6 million. In the case where the average daily
NYMEX-WTI price for oil for the year ending December 31,
2012 is $76.00 and the average daily NYMEX-Henry Hub price for
natural gas is $2.86 per MMBtu for the same period, we
would have had an excess of $1.4 million over the amount of
cash available for distribution necessary to pay such aggregate
annualized distribution. In the case where the average daily
NYMEX-WTI price for oil for the year ending December 31,
2012 is $86.00 and the average daily NYMEX-Henry Hub price for
natural gas is $3.36 per MMBtu for the same period, we
would have had an excess of $4.1 million over the amount of
cash available for distribution necessary to pay such aggregate
annualized distribution.
|
69
If NYMEX oil and natural gas prices decline, our estimated
Adjusted EBITDA would not decline proportionately for two
reasons: (1) the effects of our commodity derivative
contracts; and (2) production taxes, which are calculated
as a percentage of our oil and natural gas revenues, excluding
the effects of our commodity derivative contracts, and which
decrease as commodity prices decline. Furthermore, we have
assumed no decline in estimated production or oil and natural
gas operating costs during the year ending December 31,
2012. However, over the long-term, a sustained decline in oil
and natural gas prices would likely lead to a decline in
production and oil and natural gas operating costs, as well as a
reduction in our realized oil and natural gas prices. Therefore,
the foregoing table is not illustrative of all of the potential
effects of changes in commodity prices for periods subsequent to
December 31, 2012.
70
PROVISIONS
OF OUR PARTNERSHIP AGREEMENT RELATING TO
CASH DISTRIBUTIONS
Set forth below is a summary of the significant provisions of
our partnership agreement that relate to cash distributions. The
information presented in this section assumes that our general
partner will continue to make capital contributions to us in
order to maintain its 2.0% general partner interest.
Distributions
of Available Cash
General
Our partnership agreement requires that, within 45 days
after the end of each quarter, beginning with the quarter ending
December 31, 2011, we will distribute all of our available
cash to unitholders of record on the applicable record date. We
will prorate the initial quarterly distribution payable for the
period from the closing of this offering through
December 31, 2011, based on the actual length of that
period. We will distribute 98.0% of our available cash to our
common unitholders, pro rata, and 2.0% to our general partner.
Unlike many publicly traded limited partnerships, our general
partner is not entitled to any incentive distributions, and we
do not have any subordinated units.
Definition
of Available Cash
Available cash, for any quarter, consists of all cash and cash
equivalents on hand at the end of that quarter:
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|
|
less, the amount of cash reserves established by our
general partner at the date of determination of available cash
for the quarter to:
|
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|
|
|
|
provide for the proper conduct of our business (including
reserves for future capital expenditures, working capital and
operating expenses) subsequent to that quarter;
|
|
|
|
|
|
comply with applicable law, any of our loan agreements, security
agreements, mortgages debt instruments or other
agreements; or
|
|
|
|
provide funds for distributions to our unitholders (including
our general partner) for any one or more of the next four
quarters;
|
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|
|
|
|
plus, if our general partner so determines, all or a
portion of cash or cash equivalents on hand on the date of
determination of available cash for the quarter.
|
Distributions
of Cash Upon Liquidation
General
If we dissolve in accordance with the partnership agreement, we
will sell or otherwise dispose of our assets in a process called
liquidation. We will first apply the proceeds of liquidation to
the payment of our creditors and the liquidator in the order of
priority provided in our partnership agreement and by law.
Thereafter, we will distribute any remaining proceeds to our
unitholders and our general partner, in accordance with their
capital account balances, as adjusted to reflect any gain or
loss upon the sale or other disposition of our assets in
liquidation.
71
Manner of Adjustments for Gain
The manner of the adjustment for gain is set forth in the
partnership agreement. Upon our liquidation, we will allocate
any net gain (or unrealized gain attributable to assets
distributed in kind to our partners) in the following manner:
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|
|
first, to our general partner and the holders of units
who have negative balances in their capital accounts to the
extent of and in proportion to those negative balances; and
|
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|
|
second, 98.0% to the common unitholders, pro rata, and
2.0% to our general partner.
|
Manner of Adjustments for Losses
Upon our liquidation, we will generally allocate any loss to our
general partner and the unitholders in the following manner:
|
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|
|
|
first, 98.0% to the holders of common units, in
proportion to the positive balances in their capital accounts
and 2.0% to our general partner, until the capital accounts of
our unitholders have been reduced to zero; and
|
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|
|
thereafter, 100% to our general partner.
|
Adjustments
to Capital Accounts
Our partnership agreement requires that we make adjustments to
capital accounts upon the issuance of additional units. In this
regard, our partnership agreement specifies that we allocate any
unrealized and, for U.S. federal income tax purposes,
unrecognized gain or loss resulting from the adjustments to the
unitholders and our general partner in the same manner as we
allocate gain or loss upon liquidation.
72
SELECTED
HISTORICAL AND PRO FORMA FINANCIAL DATA
We were formed in July 2011 and do not have historical financial
operating results. Therefore, in this prospectus, we present the
historical financial statements of our predecessor, which
consist of the consolidated historical financial statements of
Mid-Con Energy Corporation through June 30, 2009 and the
combined historical financial statements of Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC, thereafter. The
following table presents selected historical financial data of
our predecessor and selected pro forma financial data of Mid-Con
Energy Partners, LP as of the dates and for the periods
indicated. The selected historical financial data as of
December 31, 2009 and 2010 and for the years ended
June 30, 2008 and 2009, the six months ended
December 31, 2009 and the year ended December 31, 2010
are derived from the audited historical financial statements of
our predecessor included elsewhere in this prospectus. The
selected historical financial data for the years ended
June 30, 2006 and 2007 are derived from audited historical
financial statements of our predecessor not included herein. The
selected historical financial data as of September 30, 2011
and for the nine months ended September 30, 2010 and 2011
are derived from the unaudited historical combined financial
statements of our predecessor included elsewhere in this
prospectus.
The selected unaudited pro forma financial data as of
September 30, 2011 and for the nine months ended
September 30, 2011 and the year ended December 31,
2010 are derived from the unaudited pro forma condensed
financial statements of Mid-Con Energy Partners, LP included
elsewhere in this prospectus. Our unaudited pro forma condensed
financial statements give pro forma effect to the following:
|
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|
|
the sale by Mid-Con Energy I, LLC and Mid-Con Energy II,
LLC of certain oil and natural gas properties representing less
than 1% of our proved reserves by value, as calculated using the
standardized measure, as of September 30, 2011, and certain
subsidiaries that do not own oil and natural gas reserves,
including Mid-Con Energy Operating, to the Mid-Con Affiliates
for aggregate consideration of $7.5 million;
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|
the merger of Mid-Con Energy I, LLC and Mid-Con Energy II,
LLC with our wholly owned subsidiary in exchange for aggregate
consideration of 12,240,000 common units and $121.2 million
in cash;
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|
|
the issuance to our general partner of 360,000 general partner
units, representing a 2.0% general partner interest in us in
exchange for a contribution from our general partner;
|
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|
|
|
the issuance and sale by us to the public of 5,400,000 common
units in this offering and the application of the net proceeds
as described in Use of Proceeds;
|
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|
|
|
our borrowing of approximately $45.0 million under our new
credit facility and the application of the proceeds as described
in Use of Proceeds; and
|
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|
|
our acquisition of additional working interests in the Cushing
Field from J&A Oil Company and Charles R. Olmstead
immediately prior to the closing of this offering.
|
The unaudited pro forma balance sheet data assume the events
listed above occurred as of September 30, 2011. The
unaudited pro forma statement of operations data for the nine
months ended September 30, 2011 and the year ended
December 31, 2010 assume the items listed above occurred as
of January 1, 2010. We have not given pro forma effect to
incremental general and administrative expenses of approximately
$3.0 million that we expect to incur annually as a result
of being a publicly traded partnership.
You should read the following table in conjunction with
Prospectus SummaryFormation Transactions and
Partnership Structure, Use of Proceeds,
Managements Discussion and Analysis of Financial
Condition and Results of Operations, the historical
combined financial statements of our predecessor and the
unaudited pro forma condensed financial statements of Mid-Con
Energy Partners, LP and the notes thereto included elsewhere in
this prospectus.
73
Among other things, those historical financial statements and
unaudited pro forma condensed financial statements include more
detailed information regarding the basis of presentation for the
following information.
The following table presents a non-GAAP financial measure,
Adjusted EBITDA, which we use in evaluating the financial
performance and liquidity of our business. This measure is not
calculated or presented in accordance with GAAP. We explain this
measure below and reconcile it to the most directly comparable
financial measures calculated and presented in accordance with
GAAP.
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|
|
|
|
|
|
|
|
|
|
|
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|
|
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|
|
|
|
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|
|
|
|
Mid-Con Energy I, LLC and
|
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|
Mid-Con Energy
|
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|
|
|
|
|
|
Mid-Con Energy II, LLC
|
|
|
Partners, LP
|
|
|
|
|
|
|
|
(combined)
|
|
|
Pro Forma
|
|
|
|
Mid-Con Energy Corporation
|
|
|
|
Six Months
|
|
|
Year
|
|
|
Nine Months
|
|
|
Year
|
|
|
Nine Months
|
|
|
|
(consolidated)
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Year Ended June 30,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
September 30,
|
|
Statement of Operations Data:
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
(in thousands)
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
5,569
|
|
|
$
|
6,944
|
|
|
$
|
13,667
|
|
|
$
|
10,246
|
|
|
|
$
|
5,729
|
|
|
$
|
16,853
|
|
|
$
|
11,390
|
|
|
$
|
25,068
|
|
|
$
|
16,286
|
|
|
$
|
25,040
|
|
Natural gas sales
|
|
|
51
|
|
|
|
64
|
|
|
|
618
|
|
|
|
2,172
|
|
|
|
|
743
|
|
|
|
1,418
|
|
|
|
1,104
|
|
|
|
974
|
|
|
|
1,397
|
|
|
|
978
|
|
Realized loss on derivatives, net
|
|
|
(165
|
)
|
|
|
558
|
|
|
|
(804
|
)
|
|
|
(669
|
)
|
|
|
|
(350
|
)
|
|
|
(90
|
)
|
|
|
(87
|
)
|
|
|
(799
|
)
|
|
|
(100
|
)
|
|
|
(875
|
)
|
Unrealized gain (loss) on derivatives, net
|
|
|
(294
|
)
|
|
|
45
|
|
|
|
(2,035
|
)
|
|
|
1,679
|
|
|
|
|
(147
|
)
|
|
|
(707
|
)
|
|
|
182
|
|
|
|
9,400
|
|
|
|
(707
|
)
|
|
|
9,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
5,161
|
|
|
|
7,611
|
|
|
|
11,446
|
|
|
|
13,428
|
|
|
|
|
5,975
|
|
|
|
17,474
|
|
|
|
12,589
|
|
|
|
34,643
|
|
|
|
16,876
|
|
|
|
34,543
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
2,252
|
|
|
|
3,429
|
|
|
|
5,005
|
|
|
|
5,369
|
|
|
|
|
2,431
|
|
|
|
6,237
|
|
|
|
4,654
|
|
|
|
5,951
|
|
|
|
5,041
|
|
|
|
5,600
|
|
Oil and gas production taxes
|
|
|
407
|
|
|
|
478
|
|
|
|
946
|
|
|
|
631
|
|
|
|
|
269
|
|
|
|
822
|
|
|
|
522
|
|
|
|
1,116
|
|
|
|
797
|
|
|
|
1,119
|
|
Dry holes and abandonments of unproved properties
|
|
|
539
|
|
|
|
220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,418
|
|
|
|
1,053
|
|
|
|
772
|
|
|
|
514
|
|
|
|
772
|
|
Geological and geophysical
|
|
|
146
|
|
|
|
342
|
|
|
|
1,296
|
|
|
|
507
|
|
|
|
|
|
|
|
|
394
|
|
|
|
253
|
|
|
|
171
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
931
|
|
|
|
924
|
|
|
|
1,599
|
|
|
|
2,293
|
|
|
|
|
2,552
|
|
|
|
5,851
|
|
|
|
4,743
|
|
|
|
4,318
|
|
|
|
3,327
|
|
|
|
4,128
|
|
Accretion of discount on asset retirement obligations
|
|
|
2
|
|
|
|
35
|
|
|
|
56
|
|
|
|
78
|
|
|
|
|
58
|
|
|
|
127
|
|
|
|
95
|
|
|
|
55
|
|
|
|
63
|
|
|
|
55
|
|
General and administrative
|
|
|
1,391
|
|
|
|
1,805
|
|
|
|
1,871
|
|
|
|
1,767
|
|
|
|
|
704
|
|
|
|
982
|
|
|
|
708
|
|
|
|
552
|
|
|
|
982
|
|
|
|
552
|
|
Impairment of proved oil and gas properties
|
|
|
178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,208
|
|
|
|
1,886
|
|
|
|
|
|
|
|
|
|
|
|
1,260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
5,846
|
|
|
|
7,233
|
|
|
|
10,773
|
|
|
|
10,645
|
|
|
|
|
15,222
|
|
|
|
17,717
|
|
|
|
12,028
|
|
|
|
12,935
|
|
|
|
11,984
|
|
|
|
12,226
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(685
|
)
|
|
|
378
|
|
|
|
673
|
|
|
|
2,783
|
|
|
|
|
(9,247
|
)
|
|
|
(243
|
)
|
|
|
561
|
|
|
|
21,708
|
|
|
|
4,892
|
|
|
|
22,317
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Con Energy I, LLC and
|
|
|
Mid-Con Energy
|
|
|
|
|
|
|
|
Mid-Con Energy II, LLC
|
|
|
Partners, LP
|
|
|
|
|
|
|
|
(combined)
|
|
|
Pro Forma
|
|
|
|
Mid-Con Energy Corporation
|
|
|
|
Six Months
|
|
|
Year
|
|
|
Nine Months
|
|
|
Year
|
|
|
Nine Months
|
|
|
|
(consolidated)
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Year Ended June 30,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
September 30,
|
|
Statement of Operations Data:
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
(in thousands)
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expenses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income and other
|
|
|
63
|
|
|
|
126
|
|
|
|
115
|
|
|
|
119
|
|
|
|
|
35
|
|
|
|
218
|
|
|
|
208
|
|
|
|
160
|
|
|
|
126
|
|
|
|
102
|
|
Interest expense
|
|
|
(24
|
)
|
|
|
(11
|
)
|
|
|
(3
|
)
|
|
|
(93
|
)
|
|
|
|
(2
|
)
|
|
|
(98
|
)
|
|
|
(59
|
)
|
|
|
(378
|
)
|
|
|
(1,350
|
)
|
|
|
(1,013
|
)
|
Gain on sale of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
354
|
|
|
|
354
|
|
|
|
1,559
|
|
|
|
|
|
|
|
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,671
|
)
|
|
|
|
|
|
|
(1,671
|
)
|
Other revenue and expenses, net
|
|
|
138
|
|
|
|
439
|
|
|
|
108
|
|
|
|
298
|
|
|
|
|
118
|
|
|
|
847
|
|
|
|
501
|
|
|
|
576
|
|
|
|
|
|
|
|
|
|
Income tax expensecurrent
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(625
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (expense) benefitdeferred
|
|
|
325
|
|
|
|
(197
|
)
|
|
|
(261
|
)
|
|
|
502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(183
|
)
|
|
$
|
735
|
|
|
$
|
632
|
|
|
$
|
2,984
|
|
|
|
$
|
(9,096
|
)
|
|
$
|
1,078
|
|
|
$
|
1,565
|
|
|
$
|
21,954
|
|
|
$
|
3,668
|
|
|
$
|
19,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
0.20
|
|
|
$
|
1.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of limited partner units outstanding
(basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,640
|
|
|
|
17,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
|
|
|
|
|
|
|
|
$
|
4,471
|
|
|
$
|
3,773
|
|
|
|
$
|
2,836
|
|
|
$
|
10,593
|
|
|
$
|
6,771
|
|
|
$
|
18,029
|
|
|
$
|
10,763
|
|
|
$
|
17,872
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
(282
|
)
|
|
$
|
2,052
|
|
|
$
|
4,221
|
|
|
$
|
10,935
|
|
|
|
$
|
965
|
|
|
$
|
11,798
|
|
|
$
|
10,269
|
|
|
$
|
14,554
|
|
|
|
|
|
|
|
|
|
Investing activities
|
|
|
(5,599
|
)
|
|
|
(11,143
|
)
|
|
|
(7,646
|
)
|
|
|
(12,448
|
)
|
|
|
|
(5,018
|
)
|
|
|
(22,726
|
)
|
|
|
(15,922
|
)
|
|
|
(24,881
|
)
|
|
|
|
|
|
|
|
|
Financing activities
|
|
|
4,918
|
|
|
|
9,980
|
|
|
|
147
|
|
|
|
4,841
|
|
|
|
|
(1,164
|
)
|
|
|
10,387
|
|
|
|
5,133
|
|
|
|
10,291
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Con
|
|
|
Mid-Con Energy I, LLC and
|
|
|
|
Energy
|
|
|
Mid-Con Energy II, LLC
|
|
|
|
Partners, LP
|
|
|
(combined)
|
|
|
|
Pro Forma
|
|
|
As of December 31,
|
|
|
|
As of September 30,
|
|
|
|
As of September 30,
|
Balance Sheet Data:
|
|
2009
|
|
2010
|
|
|
|
2011
|
|
|
|
2011
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
|
(unaudited)
|
|
|
(in thousands)
|
|
|
(restated)
|
|
(restated)
|
|
|
|
|
|
|
|
|
|
Working capital(1)
|
|
$
|
2,420
|
|
|
$
|
(1,256
|
)
|
|
|
|
|
|
$
|
6,819
|
|
|
|
|
|
|
$
|
5,236
|
|
Total assets
|
|
|
40,496
|
|
|
|
56,867
|
|
|
|
|
|
|
|
88,682
|
|
|
|
|
|
|
|
92,377
|
|
Total debt
|
|
|
337
|
|
|
|
5,513
|
|
|
|
|
|
|
|
15,210
|
|
|
|
|
|
|
|
45,000
|
|
Partners capital
|
|
|
36,779
|
|
|
|
43,072
|
|
|
|
|
|
|
|
69,955
|
|
|
|
|
|
|
|
43,860
|
|
|
|
|
(1)
|
|
For 2010, excludes
$5.3 million of current maturities under our
predecessors credit facilities. The maturity date for
these facilities was subsequently extended to December 2013.
|
75
MANAGEMENTS
DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following Managements Discussion and Analysis of
Financial Condition and Results of Operations should be read in
conjunction with the Selected Historical and Pro Forma
Financial Data and the accompanying financial statement
and related notes included elsewhere in this prospectus. Unless
otherwise indicated, all references to financial or operating
data on a pro forma basis give effect to the transactions
described under Prospectus SummaryFormation
Transactions and Partnership Structure and in the
unaudited pro forma condensed financial statements included
elsewhere in this prospectus.
Overview
We are a Delaware limited partnership formed in July 2011 to
own, operate, acquire, exploit and develop producing oil and
natural gas properties in North America, with a focus on the
Mid-Continent region of the United States. Our management team
has significant industry experience, especially with waterflood
projects and, as a result, our operations focus primarily on
enhancing the development of producing oil properties through
waterflooding. Through the continued development of our existing
properties and through future acquisitions, we will seek to
increase our reserves and production in order to maintain and,
over time, increase distributions to our unitholders. Also, in
order to enhance the stability of our cash flow for the benefit
of our unitholders, we will seek to hedge a significant portion
of our production volumes through various commodity derivative
contracts.
As of September 30, 2011, our total estimated proved
reserves were approximately 9.9 MMBoe, of which
approximately 98% were oil and 69% were proved developed, both
on a Boe basis. As of September 30, 2011, we operated 99%
of our properties and 92% were being produced under waterflood,
in each instance on a Boe basis. Our average net production for
the month ended September 30, 2011 was approximately 1,343
Boe per day and our total estimated proved reserves had a
reserve-to-production
ratio of approximately 20 years. Our management team
developed approximately 60% of our total reserves through new
waterflood projects.
How We
Evaluate Our Operations
We use a variety of financial and operational metrics to assess
the performance of our oil properties, including:
|
|
|
|
|
Oil and natural gas production volumes;
|
|
|
|
Realized prices on the sale of oil and natural gas, including
the effect of our commodity derivative contracts;
|
|
|
|
Lease operating expenses; and
|
|
|
|
Adjusted EBITDA.
|
Production Volumes
Production volumes directly impact our results of operations.
For more information about our production volumes, please read
Historical Financial and Operating Data.
76
The following table presents production volumes for our
properties for the years ended June 30, 2008 and 2009, for
the six months ended December 31, 2009, for the year ended
December 31, 2010, and for the nine months ended
September 30, 2011.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
|
|
|
Nine Months
|
|
|
|
|
|
|
|
|
|
Ended
|
|
|
Year Ended
|
|
|
Ended
|
|
|
|
Year Ended June 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
Oil (MBbls)
|
|
|
145
|
|
|
|
153
|
|
|
|
87
|
|
|
|
228
|
|
|
|
278
|
|
Natural Gas (MMcf)
|
|
|
86
|
|
|
|
341
|
|
|
|
140
|
|
|
|
191
|
|
|
|
126
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
159
|
|
|
|
210
|
|
|
|
110
|
|
|
|
260
|
|
|
|
299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Net Production (Boe/d)
|
|
|
437
|
|
|
|
575
|
|
|
|
602
|
|
|
|
710
|
|
|
|
1,094
|
|
Realized
Prices on the Sale of Oil
Factors Affecting the Sales Price of Oil. The
price of oil generally is determined by factors impacting global
and regional supply and demand dynamics, such as economic
conditions, production levels, weather cycles and other events.
Oil prices are also heavily influenced by product quality and
location relative to consuming and refining markets. The
NYMEX-WTI futures price is a widely used benchmark in the
pricing of domestic and imported oil in the United States. The
actual prices realized from the sale of oil differ from the
quoted NYMEX-WTI price as a result of quality and location
differentials.
Quality differentials to NYMEX-WTI prices result from the fact
that oil can differ in its molecular makeup, which plays an
important part in its refining and subsequent sale as petroleum
products. The two primary characteristics that account for
quality differentials are: (1) the oils American
Petroleum Institute, or API, gravity and (2) the oils
percentage of sulfur content by weight. In general, lighter oil
(with higher API gravity) produces a larger number of lighter
products, such as gasoline, which have higher resale value, and
therefore, normally sells at a higher price than heavier oil.
Oil with low sulfur content or sweet oil is less
expensive to refine and, as a result, normally sells at a higher
price than high sulfur-content oil or sour oil. The
oil produced from our properties is predominately light
sweet oil.
Location differentials to NYMEX-WTI prices result from variances
in transportation costs based on the produced oils
proximity to the major trading, transportation and refining
markets to which it is ultimately delivered. Oil that is
produced close to major trading, transportation and refining
markets, such as Cushing, Oklahoma, command a higher price
because of lower transportation costs as compared to oil that is
produced farther from such markets. Consequently, oil that is
produced close to major trading, transportation and refining
markets normally realizes a higher price (i.e., a lower
location differential to NYMEX-WTI).
Sales Contracts. We currently receive
approximately 87% of our total sales revenues from one party,
Sunoco Logistics, under two crude oil purchase agreements. We
recently entered into a new crude oil purchase contract with
Enterprise, which will be effective as of January 1, 2012. We
anticipate that, as a result of this new contract, sales to
Enterprise will account for a significant portion of our 2012
total sales revenues. We have amended our current purchase
contracts with Sunoco Logistics from time to time to add new
leases and to modify the pricing terms. Generally, amendments to
modify the pricing terms of our agreements with Sunoco Logistics
also extend the term of such agreements for six months. If new
amendments to our Sunoco Logistics agreements are not entered
into at the end of the term provided for in the most recent
amendment, the terms of the prior amendment continue on a
month-to-month
basis until either party terminates on thirty days notice.
We expect to make similar pricing and term amendments from
time-to-time under our new agreement with Enterprise.
The current purchase agreements with Sunoco Logistics and our
new agreement with Enterprise all provide a fixed NYMEX-WTI
differential for all production from an individual
77
producing lease. Settlement under all of these purchase
agreements will occur monthly, with payment being made on or
about the 15th of each month for oil delivered during the
previous month. The ultimate price per barrel paid to us by
Sunoco Logistics and Enterprise will be based on a daily average
settling price of the near month NYMEX-WTI light sweet crude oil
contract during the month in which the oil is actually
delivered, minus the applicable differential.
We will continue to compare the pricing under our crude oil
purchase contracts to offers from other purchasers to determine
the best price in the relevant market.
Commodity Derivative Contracts. To better
manage oil price fluctuations and achieve more predictable cash
flow, we intend to maintain a portfolio covering approximately
50% to 80% of our estimated oil production from proved reserves
over a
three-to-five
year period on a rolling basis. We may from time to time hedge
more or less than this approximate range. These instruments
limit our exposure to declines in prices, but also limit our
upside if prices increase. Because the prices at which we sell a
substantial majority of our oil production are determined by the
NYMEX-WTI futures price, our derivatives contract pricing
strategy is intended to manage and reduce our exposure to
NYMEX-WTI price fluctuations, and is not dependent upon or
influenced by the portion of our production we sell to any of
our customers.
For the years ending December 31, 2011, 2012 and 2013, we
have commodity derivative contracts covering approximately 37%,
53% and 30%, respectively, of our estimated oil production from
proved reserves as of September 30, 2011. All of our
derivative contracts for 2012 and 2013 are either swaps with
fixed settlements or collars. The weighted average minimum
prices on all of our derivative contracts for 2012 and 2013 are
$101.18 and $100.14, respectively. A collar is a
combination of a put option we purchase and a call option we
sell. The put option portion of a collar is also referred to as
a floor. A floor establishes a minimum average sale
price for future oil production. In 2012, we have collars with a
floor of $100.00 and swaps with fixed price settlements ranging
from $100.97 to $104.28 covering approximately 11% and 42%,
respectively, of our total proved estimated oil production. In
2013, we have collars with a floor of $100.00 and swaps with
fixed price settlements ranging from $96.00 to $105.80 covering
9% and 21%, respectively, of our total proved estimated oil
production. Please read Managements Discussion and
Analysis of Financial Condition and Results of
OperationsLiquidity and Capital ResourcesDerivative
Contracts.
The following table reflects, with respect to our existing
commodity derivative contracts, the volumes our production
covered by commodity derivative contracts and the average prices
at which the production will be hedged:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2011
|
|
2012
|
|
2013
|
|
Oil Derivative Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls/d)
|
|
|
554
|
|
|
|
789
|
|
|
|
460
|
|
Weighted Average NYMEX-WTI price per Bbl
|
|
$
|
91.22
|
|
|
|
$101.47
|
|
|
|
$100.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Put/Call Option Contracts (Collars):
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls/d)
|
|
|
|
|
|
|
197
|
|
|
|
197
|
|
Weighted Average NYMEX-WTI price per Bbl
|
|
|
|
|
|
|
$100 $117
|
|
|
|
$100 $111
|
|
Lease
Operating Expenses
Lease operating expenses are the costs incurred in the operation
of producing properties and workover costs. Expenses for
utilities, direct labor, water injection and disposal, and
materials and supplies comprise the most significant portion of
our lease operating expenses. Lease
78
operating expenses do not include general and administrative
costs, but do include ad valorem taxes. Certain items, such as
direct labor and materials and supplies, generally remain
relatively fixed across broad production volume ranges, but can
fluctuate depending on activities performed during a specific
period. For instance, repairs to our pumping equipment or
surface facilities result in increased lease operating expenses
during the time which they are performed.
A majority of our operating cost components are variable and
increase or decrease as the level of produced hydrocarbons and
water increases or decreases. For example, we incur power costs
in connection with various production related activities such as
pumping to recover oil, separation and treatment of water
produced in connection with our oil production, and re-injection
of water into the oil producing formation to maintain reservoir
pressure. As these costs are driven not only by volumes of oil
produced but also volumes of water produced, fields that have a
high percentage of water production relative to oil production,
also known as a high water cut, will experience higher power
costs for each barrel of oil produced. Since a majority of our
oil is produced from waterflooding, the amount of water produced
will increase for a given volume of oil production over the life
of these fields. In newly implemented waterflood projects, per
unit lifting costs increase early in the life of the project due
to production losses associated with the conversion of producing
wells to water injection and the additional cost of injecting
water. Once production response to injection occurs, the per
unit lease operating expenses will begin to decrease as absolute
costs remain relatively stable and production rates increase.
An example of decreasing per unit lease operating expenses is
our Highlands Unit, where operating costs increased on an
absolute basis during the twelve months ended September 30,
2011. During the same twelve month period, per unit lease
operating expenses for our Highlands Unit decreased from
approximately $30.02 per Boe to $7.88 per Boe as production
increased due to ongoing response to waterflooding and
development drilling. After a waterflood project has reached
peak production, the water cut will usually increase, resulting
in the production of each barrel of oil becoming more expensive
until, at some point, additional production becomes uneconomic.
We typically evaluate our lease operating expenses on a per Boe
basis. This allows us to monitor these costs in certain fields
and geographic areas to identify trends and to benchmark against
other producers. For mature waterflood projects, total lease
operating expenses may remain relatively stable, but due to
production declines, lease operating expenses will generally
increase on a per Boe basis. We believe that one of our areas of
core expertise lies in reducing per unit lease operating
expenses for mature high water cut waterfloods. We monitor our
operations to ensure that we are incurring operating costs at
the optimal level relative to our production. Accordingly, we
monitor our lease operating expenses and operating costs per
well to determine if any wells or properties should be shut in,
recompleted or sold.
Adjusted
EBITDA
We define Adjusted EBITDA as net income (loss):
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income tax expense (benefit), if any;
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interest expense;
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depreciation, depletion and amortization;
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accretion of discount on asset retirement obligations;
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unrealized losses on commodity derivative contracts;
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impairment expenses;
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79
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dry hole costs and abandonment of unproved properties;
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stock-based compensation; and
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loss on sale of assets;
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interest income;
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unrealized gains on commodity derivative contracts; and
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gain on sale of assets.
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Adjusted EBITDA is used as a supplemental financial measure by
our management and by external users of our financial
statements, such as industry analysts, investors, lenders,
rating agencies and others, to assess:
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the cash flow generated by our assets, without regard to
financing methods, capital structure or historical cost
basis; and
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our ability to incur and service debt and fund capital
expenditures.
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Adjusted EBITDA should not be considered an alternative to net
income, operating income, net cash provided by operating
activities or any other measure of financial performance or
liquidity presented in accordance with GAAP. Our Adjusted EBITDA
may not be comparable to similarly titled measures of another
company because all companies may not calculate Adjusted EBITDA
in the same manner. For further discussion of the non-GAAP
financial measure Adjusted EBITDA, please read Prospectus
SummaryNon-GAAP Financial Measures.
Outlook
Beginning in the second half of 2008, the United States and
other industrialized countries experienced a significant
economic slowdown, which led to a substantial decline in
worldwide energy demand. While oil prices have steadily
increased since the second quarter of 2009, the outlook and
timing for a worldwide economic recovery remains uncertain for
the foreseeable future. As a result, it is likely that commodity
prices will continue to be volatile. Sustained periods of low
prices for oil could materially and adversely affect our
financial position, our results of operations, the quantities of
oil reserves that we can economically produce and our access to
capital.
Our business faces the challenge of natural production declines.
As initial reservoir pressures are depleted, oil production from
a given well or formation decreases. Although our waterflood
operations tend to restore reservoir pressure and production,
once a waterflood is fully effected, production, once again,
begins to decline. Our future growth will depend on our ability
to continue to add reserves in excess of our production. We plan
to maintain our focus primarily on adding reserves through
improving the economics of producing oil from our existing
fields and, secondarily, through acquisitions of additional
proved reserves. We expect that acquisition opportunities may
come from the Mid-Con Affiliates and also from unrelated third
parties. Our ability to add reserves through exploitation
projects and acquisitions is dependent upon many factors,
including our ability to raise capital, obtain regulatory
approvals, procure contract drilling rigs and personnel, and
successfully identify and close acquisitions.
80
Historical
Financial and Operating Data
The following table sets forth selected historical combined
financial and operating data of our predecessor and unaudited
pro forma financial and operating data for the periods
presented. The following table should be read in conjunction
with Selected Historical and Pro Forma Financial
Data.
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Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
(combined)
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Mid-Con Energy Corporation
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Six Months
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Year
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Nine Months
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(consolidated)
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Ended
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Ended
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Ended
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Year Ended June 30,
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December 31,
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December 31,
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September 30,
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2008
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2009
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2009
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2010
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2010
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2011
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(unaudited)
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(restated)
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(restated)
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(restated)
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(restated)
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Revenues (in thousands):
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Oil sales
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$
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13,667
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$
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10,246
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$
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5,729
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$
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16,853
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$
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11,390
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$
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25,068
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Natural gas sales
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|
618
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2,172
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743
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1,418
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1,104
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974
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Realized gain (loss) on derivatives, net
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(804
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)
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(669
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)
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|
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(350
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)
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(90
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)
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(87
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)
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(799
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)
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Unrealized gain (loss) on derivatives, net
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(2,035
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)
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1,679
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(147
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)
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(707
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)
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182
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9,400
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Total Revenues
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$
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11,446
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$
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13,428
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$
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5,975
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$
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17,474
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$
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12,589
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$
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34,643
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Expenses (in thousands):
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Lease operating expense
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$
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5,005
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$
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5,369
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$
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2,431
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$
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6,237
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$
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4,654
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$
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5,951
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Oil and gas production taxes
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|
946
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631
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269
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822
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522
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1,116
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Dry holes and abandonments of unproved properties
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1,418
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1,053
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772
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Depreciation, depletion and amortization(1)
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1,465
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2,103
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2,357
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5,204
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4,076
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3,979
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General and administrative
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1,871
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1,767
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704
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982
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|
708
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|
552
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Impairment of proved oil and gas properties
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9,208
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|
1,886
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|
|
|
|
|
|
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Interest expense
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|
|
3
|
|
|
|
93
|
|
|
|
|
2
|
|
|
|
98
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|
|
|
59
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|
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|
378
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Production:
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Oil (MBbls)
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|
145
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|
153
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|
87
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|
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|
228
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|
|
|
159
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|
|
278
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Natural gas (MMcf)
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|
86
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|
341
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|
140
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|
191
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|
148
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|
126
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Total (MBoe)
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|
159
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|
210
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|
110
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|
|
|
260
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|
184
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|
299
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Average net production (Boe/d)
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|
437
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|
575
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|
|
602
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|
|
|
710
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|
|
|
674
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|
|
|
1,094
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|
Average sales price:
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Oil (per Bbl):
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Sales price
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$
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94.20
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|
$
|
66.87
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|
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$
|
66.11
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|
|
$
|
74.07
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|
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$
|
71.53
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|
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$
|
90.31
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Effect of realized commodity derivative instruments
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|
$
|
(5.54
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)
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|
$
|
(4.37
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)
|
|
|
$
|
(4.04
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)
|
|
$
|
0.40
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|
|
$
|
(0.55
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)
|
|
$
|
(2.88
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)
|
Realized price
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$
|
88.66
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|
|
$
|
62.50
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|
|
|
$
|
62.06
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|
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$
|
73.67
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|
|
$
|
70.99
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|
|
$
|
87.44
|
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Natural gas (per Mcf):
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Sales price(2)
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|
$
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7.17
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|
|
$
|
6.37
|
|
|
|
$
|
5.33
|
|
|
$
|
7.44
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|
|
$
|
7.44
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|
|
$
|
7.72
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Average unit costs per Boe:
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|
|
|
|
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|
|
|
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Lease operating expenses
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|
$
|
31.39
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|
|
$
|
25.56
|
|
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|
$
|
22.11
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|
|
$
|
24.05
|
|
|
$
|
25.30
|
|
|
$
|
19.93
|
|
Oil and gas production taxes
|
|
$
|
5.93
|
|
|
$
|
3.00
|
|
|
|
$
|
2.45
|
|
|
$
|
3.17
|
|
|
$
|
2.84
|
|
|
$
|
3.74
|
|
General and administrative expenses
|
|
$
|
11.73
|
|
|
$
|
8.41
|
|
|
|
$
|
6.40
|
|
|
$
|
3.79
|
|
|
$
|
3.85
|
|
|
$
|
1.85
|
|
Depreciation, depletion and amortization
|
|
$
|
9.21
|
|
|
$
|
10.01
|
|
|
|
$
|
21.43
|
|
|
$
|
20.07
|
|
|
$
|
22.16
|
|
|
$
|
13.33
|
|
|
|
|
(1)
|
|
Depreciation, depletion, and
amortization expenses for this table only represent the
depletion expenses for the producing properties.
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(2)
|
|
Natural gas sales price per Mcf
includes the sale of natural gas liquids.
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81
Results
of Operations
The historical financial statements have been restated to
correct errors discovered in the calculation of depreciation,
depletion, and amortization and impairment of proved properties
for all periods prior to September 30, 2011, as well as the
expensing of certain geological and geophysical costs by Mid-Con
Energy I, LLC for the six months ended December 31, 2009.
Factors Impacting the Comparability of Our Financial
Results
The comparability of our future results of operations to our
historical results of operations and the comparability of our
historical results of operations among the periods presented may
be impacted by:
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|
|
|
|
The drilling of 35 wells in 2010 and 43 wells in 2011
on our properties in Oklahoma;
|
|
|
|
|
|
Our sale to the Mid-Con Affiliates on June 30, 2011 of
certain properties representing less than 1% of our proved
reserves by value, as calculated using the standardized measure,
as of September 30, 2011, and certain subsidiaries that do
not own oil and natural gas reserves, including Mid-Con Energy
Operating, to the Mid-Con Affiliates for aggregate consideration
of $7.5 million;
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|
|
|
|
|
Our acquisition of the War Party I and II Units for a
purchase price of $7.2 million on June 30, 2011, which
together represent approximately 9% of our total estimated
proved reserves on a Boe basis as of September 30, 2011;
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|
|
|
|
|
The acquisition of interests in various properties located in
Oklahoma for an aggregate purchase price of approximately
$6.5 million throughout the year in 2010;
|
|
|
|
The unitization of the Ardmore and Twin Forks Units in January
2009 and the Highlands Unit in June 2008; and
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|
|
|
The reorganization of Mid-Con Energy Corporation into two
limited liability companies in June 2009, which eliminated our
corporate tax expense, and in connection therewith, the change
in our fiscal year end from June 30 to December 31.
|
Nine Months Ended September 30, 2011 Compared to Nine
Months Ended September 30, 2010
Sales Revenues. Revenues from oil and natural
gas sales for the nine months ended September 30, 2011 were
approximately $26.0 million as compared to
$12.5 million for the nine months ended September 30,
2010. The increase in revenues was primarily due to an increase
in daily oil production and higher sales prices during the nine
months ended September 30, 2011.
Our production volumes for the nine months ended
September 30, 2011 were 299 MBoe, or 1,094 Boe per
day. In comparison, our production volumes for the nine months
ended September 30, 2010 were 184 MBoe, or 674 Boe per
day. The increase in production volumes was primarily due to
ongoing waterflood response and the drilling programs in our
Oklahoma waterflood units. Our average sales price per barrel
for oil, excluding commodity derivative contracts, for the nine
months ended September 30, 2011 was $90.31, compared with
$71.53 for the nine months ended September 30, 2010.
Effects of Commodity Derivative Contracts. Due
to changes in commodity prices, we recorded a net gain from our
commodity hedging program for the nine months ended
September 30, 2011 of approximately $8.6 million,
which was composed of a realized loss of $0.8 million and
an unrealized gain of $9.4 million. For the nine months
ended September 30, 2010, we recorded a net gain from our
commodity hedging program of approximately $0.1 million,
which was composed of a realized loss of $0.1 million and
an unrealized gain of $0.2 million.
Lease Operating Expenses. Our lease operating
expenses were $6.0 million for the nine months ended
September 30, 2011, or $19.93 per Boe, compared to
$4.7 million for the nine
82
months ended September 30, 2010, or $25.30 per Boe. The
increase in total lease operating expenses during the nine
months ended September 30, 2011 was primarily due to the
increase in production and the increase in the number of wells
producing. The decrease in lease operating expenses per Boe was
due to the increased production for the nine months ended
September 30, 2011. Ad valorem taxes are also reflected in
lease operating expenses. Ad valorem taxes are levied on our
properties in Colorado and are calculated as a percentage of our
oil and natural gas revenues, excluding the effects of our
commodity derivative contracts, and a percentage of production
equipment value.
Production Taxes. Our production taxes were
$1.1 million for the nine months ended September 30,
2011, or $3.74 per Boe for an effective tax rate of 4.3%,
compared to $0.5 million for the nine months ended
September 30, 2010, or $2.84 per Boe for an effective tax
rate of 4.2%. The increase in production taxes during the nine
months ended September 30, 2011 was primarily due to the
increase in the realized average oil sales price. Production
taxes are calculated as a percentage of our oil and natural gas
revenues, excluding the effects of our commodity derivative
contracts. Although the State of Oklahoma, where most of our
properties are located, currently imposes a production tax of
7.2% for oil and natural gas properties and an excise tax of
0.095%, a portion of our wells in Oklahoma currently receive a
reduced rate due to the Enhanced Recovery Project Gross
Production Tax Exemption.
Depreciation, Depletion and Amortization
Expenses. Our depreciation, depletion and
amortization expenses for the nine months ended
September 30, 2011 were $4.0 million, or $13.33 per
Boe produced, compared to $4.1 million, or $22.16 per Boe
produced, for the nine months ended September 30, 2010. The
decrease in the depreciation, depletion and amortization
expenses on an overall and on a per Boe produced basis was
primarily due to the substantial increase in proved developed
reserves estimated at September 30, 2011.
Impairment of Oil and Natural Gas
Properties. There was no impairment charge for
both the nine months ended September 30, 2011 and 2010.
General and Administrative Expenses. Our
general and administrative expenses were approximately
$0.6 million for the nine months ended September 30,
2011, or $1.85 per Boe produced compared to $0.7 million
for the nine months ended September 30, 2010 or $3.85 per
Boe produced. The decrease in general and administrative
expenses for the nine months ended September 30, 2011 was
primarily due to increased affiliate subsidiary activity
resulting in the subsidiaries receiving a greater portion of the
general and administrative expenses.
Interest Expense. Our interest expense for the
nine months ended September 30, 2011 was $0.4 million,
compared to $59,000 for the nine months ended September 30,
2010. The increase was due to increased borrowings on our credit
facilities for capital expenditures and acquisitions.
Year Ended December 31, 2010 Compared to Six Months
Ended December 31, 2009
Sales Revenues. Revenues from oil and natural
gas sales for the year ended December 31, 2010 were
approximately $18.3 million as compared to
$6.5 million for the six months ended December 31,
2009. The increase in revenues was primarily due to an increase
in oil production and an increase in the average oil and natural
gas price during the twelve months ended December 31, 2010.
Our production volumes for the twelve months ended
December 31, 2010 were 260 MBoe, or 710 Boe per
day. In comparison, our production volumes for the six months
ended December 31, 2009 were 110 MBoe, or 602 Boe per
day. The increase in production volumes was primarily due to the
drilling programs in our waterflood units and the acquisitions
of interests in various properties located in Oklahoma. Our
average sales price per barrel for oil, excluding commodity
derivative contracts, for the year ended December 31, 2010
was $74.07, compared with $66.11 for the six months ended
December 31, 2009.
83
Effects of Commodity Derivative Contracts. Due
to changes in commodity prices, we recorded a net loss from our
commodity hedging program for the year ended December 31,
2010 of approximately $0.8 million, which is composed of a
realized loss of $0.1 million and an unrealized loss of
$0.7 million. For the six months ended December 31,
2009, we recorded a net loss from the commodity hedging program
of approximately $0.5 million, which is composed of a
realized loss of $0.4 million and an unrealized loss of
$0.1 million.
Lease Operating Expenses. Our lease operating
expenses were $6.2 million for the year ended
December 31, 2010, or $24.05 per Boe, compared to
$2.4 million for the six months ended December 31,
2009, or $22.11 per Boe. The increase in lease operating
expenses, on both a total and per Boe basis, was primarily due
to the increase in production and the increase in the number of
wells drilled and used for injection during the twelve months
ended December 31, 2010. Ad valorem taxes are also
reflected in lease operating expenses.
Production Taxes. Our production taxes were
$0.8 million for the year ended December 31, 2010, or
$3.17 per Boe for an effective tax rate of 4.5%, compared to
$0.3 million for the six months ended December 31,
2009, or $2.45 per Boe for an effective tax rate of 4.2%. The
increase in production taxes during the year ended
December 31, 2010 was primarily due to the increase in the
realized average oil sales price. The increase in the effective
tax rate was due to increased production from certain of our
Oklahoma properties that do not qualify for reduced tax rates.
Depreciation, Depletion and Amortization
Expenses. Our depreciation, depletion and
amortization expenses for the year ended December 31, 2010
were $5.2 million, or $20.07 per Boe produced, compared to
$2.4 million, or $21.43 per Boe produced, for the six
months ended December 31, 2009. The decrease per Boe
produced was primarily due to an increase in proved developed
reserves during the year ended December 31, 2010.
Impairment of Oil and Natural Gas
Properties. An impairment of $1.9 million
was required during the year ended December 31, 2010 due to
a decline in reserve estimates for certain producing properties.
An impairment expense of $9.2 million was also recorded for
the six months ended December 31, 2009 due to a decline in
reserve estimates for certain producing properties.
General and Administrative Expenses. Our
general and administrative expenses were approximately
$1.0 million for the year ended December 31, 2010, or
$3.79 per Boe produced, compared to $0.7 million of general
and administrative expenses for the six months ended
December 31, 2009, or $6.40 per Boe produced. The decrease
in general and administrative expenses per Boe in the year ended
December 31, 2010 was primarily due to increased affiliate
subsidiary activity resulting in the subsidiaries receiving a
greater allocation of the overall general and administrative
expenses.
Interest Expense. Our interest expense for the
year ended December 31, 2010 was $98,000 compared to $2,000
for the six months ended December 31, 2009. The increase is
attributable to an increase in borrowings from our credit
facilities due to capital expenditures and acquisitions.
Six Months Ended December 31, 2009 Compared to Year
Ended June 30, 2009
Sales Revenues. Revenues from oil and natural
gas sales for the six months ended December 31, 2009 were
approximately $6.5 million as compared to
$12.4 million for the twelve months ended June 30,
2009.
Our production volumes for the six months ended
December 31, 2009 were 110 MBoe, or 602 Boe per day.
In comparison, our production volumes for the year ended
June 30, 2009 were 210 MBoe, or 575 Boe per day.
The increase in production in Boe per day was due to an increase
in oil production partially offset by a decline in natural gas
production. Our average sales price per barrel for oil,
excluding commodity derivative contracts, for the six months
ended December 31, 2009 was $66.11 compared with $66.87 for
the year ended June 30, 2009.
84
Effects of Commodity Derivative Contracts. Due
to changes in commodity prices, we recorded a net loss from the
commodity hedging program for the six months ended
December 31, 2009 of approximately $0.5 million, which
was composed of a realized loss of $0.4 million and an
unrealized loss of $0.1 million. For the year ended
June 30, 2009, we recorded realized net gain from the
commodity hedging program of approximately $1.0 million,
which was composed of $0.7 million of realized loss and an
unrealized gain of $1.7 million.
Lease Operating Expenses. Our lease operating
expenses were $2.4 million, or $22.11 per Boe produced for
the six months ended December 31, 2009 compared to
approximately $5.4 million, or $25.56 per Boe produced for
the year ended June 30, 2009. The decrease in lease
operating expenses per Boe was attributable to an increase in
production.
Production Taxes. Our production taxes were
$0.3 million for the six months ended December 31,
2009, or $2.45 per Boe for an effective tax rate of 4.2%,
compared to $0.6 million for the year ended June 30,
2009, or $3.00 per Boe for an effective tax rate of 5.1%. The
decrease in production taxes on a per unit basis during the year
ended December 31, 2009 was primarily due to a decrease in
the effective tax rate. The decrease in the effective tax rate
was due to increased production from certain of our Oklahoma
properties that qualify for reduced tax rates.
Depreciation, Depletion and Amortization
Expenses. Our depreciation, depletion and
amortization expenses for the six months ended December 31,
2009 were $2.4 million, or $21.43 per Boe produced, as
compared to $2.1 million, or $10.01 per Boe produced, for
the year ended, June 30, 2009. The increase per Boe
produced for the six months ended December 31, 2009 was
primarily due to a decrease in reserve estimates on a total
basis for some of our non-performing properties.
Impairment of Oil and Natural Gas
Properties. An impairment of $9.2 million
was required during the six months ended December 31, 2009
due to a decline in reserve estimates for certain producing
properties. There were no impairment charges for the year ended
June 30, 2009.
General and Administrative Expenses. Our
general and administrative expenses were approximately
$0.7 million for the six months ended December 31,
2009, or $6.40 per Boe produced, compared to $1.8 million
of general and administrative expenses for the year ended
June 30, 2009 or $8.41 per Boe produced. The decrease in
general and administrative expenses per Boe produced was
primarily due to an increase in production.
Interest Expense. Our interest expense for the
six months ended December 31, 2009 was $2,000 compared to
$93,000 for the year ended June 30, 2009. The decrease is
attributable to reduced debt resulting from a capital
contribution during the six months ended December 31, 2009.
Year
Ended June 30, 2009 Compared to Year Ended June 30,
2008
Sales Revenues. Revenues from oil and natural
gas sales for the year ended June 30, 2009 were
approximately $12.4 million compared to $14.3 million
for the year ended June 30, 2008. The decrease in revenue
was attributable to the sharp decline in oil prices beginning
October 2008, offset by an increase in natural gas sales of
approximately $1.6 million for the year ended June 30,
2009.
Our production volumes for the year ended June 30, 2009
were 210 MBoe, or 575 Boe per day. In comparison, the
production volumes for the year ended June 30, 2008 were
159 MBoe, or 437 Boe per day. The increase in overall
volumes was primarily due to the response from our Battle
Springs waterflood unit in Southern Oklahoma and the increase of
gas production due to the drilling of gas wells in Oklahoma. Our
average sales price per barrel of oil, excluding commodity
derivative contracts, for the year ended June 30, 2009 was
$66.87, compared with $94.20 for the year ended June 30,
2008.
85
Effects of Commodity Derivative Contracts. Due
to changes in commodity prices, we recorded a net gain from the
commodity hedging program for the year ended June 30, 2009
of approximately $1.0 million, which was composed of a
realized loss of $0.7 million and an unrealized gain of
$1.7 million. For the year ended June 30, 2008, we
recorded a net loss from the commodity hedging program of
approximately $2.8 million, which was composed of a
realized loss of approximately $0.8 million and an
unrealized loss of approximately $2.0 million.
Lease Operating Expenses. Our lease operating
expenses were $5.4 million for the year ended June 30,
2009, or $25.56 per Boe, compared to $5.0 million for the
year ended June 30, 2008, or $31.39 per Boe. The decrease
in lease operating expenses per Boe during the year ended
June 30, 2009 was primarily due to an increase in
production.
Production Taxes. Our production taxes were
$0.6 million for the year ended June 30, 2009, or
$3.00 per Boe for an effective tax rate of 5.1%, compared to
$0.9 million for the year ended June 30, 2008, or
$5.93 per Boe for an effective tax rate of 6.6%. The decrease in
production taxes on a per unit basis during the year ended
June 30, 2009 was due to a decrease in the realized average
oil sales price and a decrease in the effective tax rate. The
decrease in the effective tax rate was due to increased
production from certain of our Oklahoma properties that qualify
for reduced tax rates.
Depreciation, Depletion and Amortization
Expenses. Our depreciation, depletion and
amortization expenses increased to approximately
$2.1 million, or $10.01 per Boe produced for the year ended
June 30, 2009 compared to approximately $1.5 million,
or $9.21 per Boe produced for the year ended June 30, 2008.
The increase is due to an increase in production.
Impairment of Oil and Natural Gas
Properties. There were no impairment charges in
the years ended June 30, 2009 and 2008, respectively.
General and Administrative Expenses. Our
general and administrative expenses decreased to approximately
$1.8 million, or $8.41 per Boe produced, in the year ended
June 30, 2009 from approximately $1.9 million, or
$11.73 per Boe produced, in the year ended June 30, 2008.
Interest Expense. Our interest expense for the
year ended June 30, 2009 was approximately $93,000 compared
to approximately $3,000 for the year ended June 30, 2008.
The increase was due to increased borrowings on our credit
facilities for capital expenditures and acquisitions.
Liquidity
and Capital Resources
Historically, our primary sources of liquidity and capital
resources have been proceeds from capital contributions from
Yorktown, bank borrowings, and cash flow from operations. Our
primary uses of capital have been for the acquisition,
development and drilling of waterflood units.
After the consummation of this offering, as a publicly traded
partnership, we expect that our primary sources of liquidity and
capital resources will be cash flow generated by operating
activities and borrowings under our new credit facility that we
will enter into concurrently with the closing of this offering.
We also expect to be able to issue additional equity and debt
securities from time to time as market conditions allow. Our
partnership agreement requires that we distribute all of our
available cash (as defined in the partnership agreement) to our
unitholders and the general partner. In making cash
distributions, our general partner will attempt to avoid large
variations in the amount we distribute from quarter to quarter.
In order to facilitate this, our partnership agreement will
permit our general partner to establish cash reserves to be used
to pay distributions for any one or more of the next four
quarters.
In addition, our partnership agreement permits us to borrow
funds to make distributions to our unitholders. We may borrow to
make distributions to our unitholders, for example, in
circumstances where we believe that the distribution level is
sustainable over the long-term, but
86
short-term factors have caused available cash from operations to
be insufficient to sustain our level of distributions. For
example, we plan to hedge a significant portion of our
production. We generally will be required to settle our
commodity hedge derivatives within five days of the end of the
month. As is typical in the oil and gas industry, we do not
generally receive the proceeds from the sale of our hedged
production until 20 to 60 days following the end of the
month. As a result, when commodity prices increase above the
fixed price in the derivative contracts, we will be required to
pay the derivative counterparty the difference between the fixed
price in the derivative contract and the market price before we
receive the proceeds from the sale of the hedged production. If
this occurs, we may borrow to fund our distributions.
Cash
Flow
Net cash provided by operating activities was approximately
$11.8 million, $10.9 million, $4.2 million,
$14.6 million, $10.3 million and $0.1 million for
the twelve months ended December 31, 2010, June 30,
2009 and June 30, 2008 and for the nine months ended
September 30, 2011 and September 30, 2010 and for the
six months ended December 31, 2009, respectively. Our
revenues increased significantly for the year ended
December 31, 2010 and for the nine month period ended
September 30, 2011 compared to prior periods, primarily due
to increased production, favorable commodity pricing, our
successful exploitation of our proved reserves, our ability to
reduce our per unit operating expenses and our successful
acquisition activity and, therefore, our net cash provided by
operating activities increased during the same period. Cash
provided by operating activities is impacted by the prices
received for oil and natural gas and levels of production
volumes. Our production volumes in the future will in large part
be dependent upon the results of past waterflood development
activities and results of future capital expenditures. Our
future levels of capital expenditures may vary due to many
factors, including development and drilling results, oil and
natural gas prices, industry conditions, prices and availability
of goods and services and the extent to which proved properties
are acquired.
Net cash used in investing activities was approximately
$22.7 million, $12.4 million, $7.6 million,
$24.9 million, $15.9 million and $5.0 million for
the twelve months ended December 31, 2010, June 30,
2009, June 30, 2008 and for the nine months ended
September 30, 2011 and September 30, 2010 and for the
six months ended December 31, 2009, respectively. The
increased amount of cash used in investing activities for the
year ended December 31, 2010 and nine months ended
September 30, 2011 compared to corresponding twelve and
nine month prior periods was primarily due to the increased
waterflood development activities in Southern Oklahoma,
including the in-field drilling in these units and acquisition
of interest in oil properties.
Net cash provided by (used in) financing activities was
approximately $10.4 million, $4.8 million,
$0.1 million, $10.3 million, $5.1 million and
($1.2 million) for the twelve months ended
December 31, 2010, June 30, 2009 and June 30,
2008 and for the nine months ended September 30, 2011 and
September 30, 2010 and for the six months ended
December 31, 2009, respectively. For the year ended
December 31, 2010 and the nine months ended
September 30, 2011, cash flow from financing activities was
provided from borrowings under our credit facilities. For the
year ended December 31, 2010, the cash provided by
financing activities primarily related to $10.0 million of
capital contributions, $5.3 million from borrowings and was
used to fund a $4.7 million distribution to certain
members. For the six months ended December 31, 2009, net
cash provided by financing activities was used to fund a
$1.5 million distribution to our members. For the twelve
months ended June 30, 2009 the cash provided by financing
activities primarily related to $5.0 million of capital
contributions.
Working
Capital
Our working capital totaled $6.8 million,
($1.3 million), and $2.4 million at September 30,
2011, December 31, 2010, and December 31, 2009,
respectively. Our cash balances at September 30, 2011,
December 31, 2010, and December 31, 2009 were
$0.2 million, $0.2 million, and $0.8 million,
respectively. The negative working capital at December 31,
2010 was directly
87
related to accrued expenses for our drilling program and the
accrued unrealized loss on our commodity derivative contracts.
In addition, the working capital amount at December 31,
2010 excludes $5.3 million of current maturities under our
existing credit facilities. The maturity date for these
facilities was subsequently extended to December 2013; they will
be repaid in full with proceeds from this offering.
Capital
Expenditures
Maintenance capital expenditures are capital expenditures that
we expect to make on an ongoing basis to maintain our waterflood
operations over the long-term. Our maintenance capital
expenditures are intended to maintain the appropriate injection,
reservoir pressure and resulting production response. While our
maintenance capital expenditures will be focused on maintaining
our existing production, they could also create production
increases as well. We estimate that maintenance capital
expenditures will average approximately $5.0 million per
year through the next five years.
Growth capital expenditures are capital expenditures that we
expect to make to either develop new waterfloods or add primary
production through newly initiated development programs. The
primary purpose of growth capital expenditures is to acquire,
develop and produce assets that will allow us to increase our
production levels and asset base in a manner that is expected to
be accretive to our unitholders and, as a result, increase our
distributions per unit. Growth capital expenditures on existing
properties may include projects such as drilling new injection
wells or producing wells on our existing waterflood projects
which are at an early stage of development. Growth capital
expenditures may also include acquisitions of additional oil and
gas properties, including new producing wells that are either in
the primary stage of production or in the secondary stage of
production but which we believe have upside potential. Although
we intend to make acquisitions in the future, including
potential acquisitions of producing properties from the Mid-Con
Affiliates, we currently have no budgeted growth capital
expenditures related to acquisitions, as we cannot be certain
that we will be able to identify attractive properties or, if
identified, that we will be able to negotiate acceptable
purchase contracts.
We generally plan to use cash flow from operations to fund our
maintenance capital expenditures. We plan primarily to use
external financing sources, including borrowings under our new
credit facility and the issuance of debt and equity securities,
to make growth capital expenditures. Because our proved reserves
and production are expected to decline over time, we will need
to continue the development of our existing reserves
and/or make
acquisitions to maintain and grow our distributions to
unitholders over time.
If cash flow from operations does not meet our expectations, we
may reduce our level of capital expenditures, reduce
distributions to our unitholders,
and/or fund
a portion of our capital expenditures using borrowings under our
credit facility, issuances of debt and equity securities or from
other sources, such as asset sales. We cannot be certain that
budgeted capital will be available on acceptable terms or at
all. The covenants in our credit facility could limit our
ability to incur additional indebtedness. If we are unable to
obtain funds when needed or on acceptable terms, we may not be
able to make growth capital expenditures or even fund the
capital expenditures necessary to maintain our production or
proved reserves.
The amount and timing of our capital expenditures are largely
discretionary and within our control. If oil and natural gas
prices decline below levels we deem acceptable, we may defer a
portion of our planned capital expenditures until later periods.
Accordingly, we routinely monitor and adjust our capital
expenditures in response to changes in oil and natural gas
prices, drilling and acquisition costs, industry conditions and
internally generated cash flow. Matters outside of our control
that could affect the timing of our expenditures include
obtaining required permits and approvals in a timely manner and
the availability of rigs and labor crews. Based on our current
oil and natural gas price expectations, we anticipate that our
cash flow from operations and available borrowing capacity under
our new credit facility will exceed our planned capital
88
expenditures and other cash requirements for the twelve months
ending December 31, 2012. However, future cash flow is
subject to a number of variables, including the level of our oil
and natural gas production and the prices we receive for our oil
and natural gas production. We cannot be certain that our
operations and other capital resources will provide cash in
amounts that are sufficient to maintain our planned levels of
capital expenditures.
New
Credit Facility
Concurrently with the closing of this offering, we, as
guarantor, our wholly owned subsidiary, Mid-Con Energy
Properties, as borrower, and any other future subsidiaries of
Mid-Con Energy Properties, as guarantors, will enter into a new
senior secured revolving credit facility. The new credit
facility will be a five-year, $250.0 million revolving
credit facility with an expected initial borrowing base of
$75.0 million.
Our new credit facility will be reserve-based, and thus we will
be permitted to borrow under our new credit facility in an
amount up to the borrowing base, which is primarily based on the
estimated value of our oil and and natural gas properties and
our commodity derivative contracts as determined semi-annually,
and at times more frequently, by our lenders in their sole
discretion. Our borrowing base will be subject to
redetermination based on an engineering report with respect to
our estimated oil and natural gas reserves, which will take into
account the prevailing oil and natural gas prices at such time,
as adjusted for the impact of our commodity derivative
contracts, and other factors. Unanimous approval by the lenders
will be required for any increase to the borrowing base. In the
future, we may be unable to access sufficient capital under our
new credit facility as a result of (i) a decrease in our
borrowing base due to a subsequent borrowing base
redetermination or (ii) an unwillingness or inability on
the part of our lenders to meet their funding obligations.
A future decline in commodity prices could result in a
redetermination that lowers our borrowing base in the future
and, in such case, we could be required to repay any
indebtedness in excess of the borrowing base, or we could be
required to pledge other oil and natural gas properties as
additional collateral. We do not anticipate having any
substantial unpledged properties, and we may not have the
financial resources in the future to make any mandatory
principal prepayments required under our new credit facility.
Additionally, we will not be able to pay distributions to our
unitholders in any such quarter in the event there exists a
borrowing base deficiency or an event of default either before
or after giving effect to such distribution or we are not in pro
forma compliance with the credit facility after giving effect to
such distribution.
Borrowings under the new credit facility will be secured by
liens on not less than 80% of the value of our oil and natural
gas properties, as calculated using the standardized measure,
and all of our equity interests in Mid-Con Energy Properties and
any future guarantor subsidiaries and all of our other assets
including personal property. Additionally, borrowings under the
new credit facility will bear interest, at our option, at either
(i) the greater of the prime rate of the administrative
agent, the federal funds effective rate plus 0.50%, and the one
month adjusted LIBOR plus 1.0%, all of which would be subject to
a margin that varies from 0.75% to 1.75% per annum according to
the borrowing base usage (which is the ratio of outstanding
borrowings and letters of credit to the borrowing base then in
effect), or (ii) the applicable LIBOR plus a margin that
varies from 1.75% to 2.75% per annum according to the borrowing
base usage. The unused portion of the borrowing base will be
subject to a commitment fee that varies from 0.375% to 0.50% per
annum according to the borrowing base usage.
Our new credit facility will require maintenance of a ratio of
Consolidated Funded Indebtedness to Consolidated EBITDAX (as
each term is defined in the new credit facility), which we refer
to as the leverage ratio, of not more than 4.0 to 1.0x, and a
ratio of consolidated current assets to consolidated current
liabilities, which we refer to as the current ratio, of not less
than 1.0 to 1.0x.
89
Additionally, the new credit facility will contain various
covenants and restrictive provisions which limit our ability to
incur additional debt, guarantees or liens; consolidate, merge
or transfer or dispose of any of our material assets; make
certain investments, acquisitions or other restricted payments;
modify certain material agreements; engage in certain types of
transactions with affiliates; incur commodity hedges exceeding a
certain percentage of our production; and prepay certain
indebtedness. For example, we will not be permitted to owe or be
liable for indebtedness except for indebtedness (a) under
the credit facility, (b) under hedging contracts permitted
by the credit facility, (c) existing at the closing of the
credit facility and listed on a schedule, (d) for the
deferred purchase price of property or services incurred in the
ordinary course of business which are not yet due or are being
contested in good faith and for which adequate reserves have
been established, (e) secured by liens allowed by the
credit facility in an amount not to exceed $2 million,
(f) sureties or bonds provided for the purpose of assuring
payment of contingent liabilities in connection with the
operation of oil and gas properties, and (g) not otherwise
permitted under the credit facility in an amount not to exceed
$2 million.
Also, we will not be permitted to be liable under hedging
contracts entered into for speculative purposes. Likewise, we
will not be permitted to be liable for commodity hedges (other
than floor or put options) at any time of more than 85% of our
total proved reserves, with proved developed non-producing and
proved undeveloped reserves combined not accounting for more
than 25% of the calculated total proved reserves (such amounts
computed on a semi-annual basis and calculated on a
product-by-product
basis), provided that the aggregate amount of all such commodity
hedging transactions (other than floor or put options) shall not
exceed 90% of actual production. Also, we may be liable under
commodity hedges in connection with acquisitions subject to the
parameters provided above; provided that (i) a purchase and
sale agreement has been signed, (ii) there is at least 10%
availability under the then current borrowing base, and
(iii) any commodity hedges in excess of those otherwise
allowed are terminated if the proposed acquisition is not
consummated within five business days of the earlier to occur of
(A) the ninetieth day after the effective date of the
purchase and sale agreement and (B) the date any loan party
believes that the proposed acquisition will not be consummated.
Furthermore, any hedge counterparty must be a lender or an
affiliate of a lender at the time the hedge is put in place or a
non-lender counterparty acceptable to the administrative agent;
provided that subject to the limitations above we may enter into
a put with a non-lender counterparty if at the time such put is
entered into such counterparty has an investment grade credit
rating, provided further that any downgrade below the specified
minimums will result in the exclusion of such put from the
borrowing base calculation. Puts in existence on the closing
date with BOKF, NA as the counterparty will be permitted.
Interest rate hedging will be permitted with a counterparty who
is a lender or an affiliate or with a non-lender counterparty
acceptable to the administrative agent. With respect to interest
rate hedges converting interest rates from fixed to floating,
the notional amount of such hedging agreements (when aggregated
with all our other hedging agreements then in effect effectively
converting interest rates from fixed to floating) may not exceed
75% of the then outstanding principal amount of our indebtedness
which bears interest at a fixed rate. With respect to interest
rate hedges converting interest rates from floating to fixed,
the notional amount of such hedging agreements (when aggregated
with all our other hedging agreements then in effect effectively
converting interest rates from floating to fixed) may not exceed
75% of the then outstanding principal amount of our indebtedness
which bears interest at a floating rate.
Furthermore, we will not be permitted to transfer any of our
material assets or any interest therein except for
(a) worthless or obsolete equipment or equipment replaced
by equipment of equal suitability and value, (b) inventory
sold in the ordinary course of business at normal trade terms,
(c) farmouts and related assignments of undeveloped acreage
in the ordinary course of business, (d) sales of proved
reserves to non-affiliates for fair value between borrowing base
determination dates, up to 5% of the borrowing base,
(e) oil and gas properties to which no proved reserves are
attributed or which are not included in the most recent
engineering report,
90
and (f) up to $5 million of other property in any
twelve month period, so long as the credit facility is not in
default.
Events of default under the credit facility shall include, but
not be limited to, failure to make payments when due; breach of
covenants (some after applicable cure periods); default under
any other material debt instrument; our general partner ceases
to be our general partner; change of control; bankruptcy or
other insolvency event; and certain material adverse effects on
our business.
If we fail to perform our obligations under these and other
covenants, the revolving credit commitments could be terminated
and any outstanding indebtedness under the new credit facility,
together with accrued interest, could be declared immediately
due and payable.
Derivative
Contracts
For the years ending December 31, 2011, 2012 and 2013, we
have commodity derivative contracts covering approximately 37%,
53% and 30%, respectively, of our estimated oil production from
proved reserves as of September 30, 2011.
The following table summarizes, for the periods indicated, our
oil swaps and put/call options, or collars, through
December 31, 2013. These transactions are settled based
upon the NYMEX-WTI price of oil.
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Weighted
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Term
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Type of Derivative
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Average ($/Bbl)
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Bbls/d
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2011
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Swaps
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$
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91.22
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554
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2012
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Swaps
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$
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101.47
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789
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2012
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Put/Call (Collars)
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$
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100 $117
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197
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2013
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Swaps
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$
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100.20
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460
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2013
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Put/Call (Collars)
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$
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100 $111
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197
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We intend to enter into commodity derivative contracts at times
and on terms designed to maintain, over the long-term, a
portfolio covering approximately 50% to 80% of our estimated oil
production from proved reserves over a
three-to-five
year period at any given point in time. We intend to enter into
additional commodity derivative contracts in connection with
material increases in our estimated production and at times when
we believe market conditions or other circumstances suggest that
it is prudent to do so as opposed to entering into commodity
derivative contracts at predetermined times or on prescribed
terms. Additionally, we may take advantage of opportunities to
modify our commodity derivative portfolio to change the
percentage of our hedged production volumes or the duration of
our hedge contracts when circumstances suggest that it is
prudent to do so. These instruments limit our exposure to
declines in prices, but also limit the benefits if prices
increase. We do not specifically designate commodity derivative
contracts as cash flow hedges; therefore, the
mark-to-market
adjustment reflecting the change in the unrealized gains or
losses on these contracts is recorded in current period
earnings. When prices for oil are volatile, a significant
portion of the effect of our hedging activities consists of
non-cash income or expenses due to changes in the fair value of
our commodity derivative contracts. Realized gains or losses
only arise from payments made or received on monthly settlements
or if a commodity derivative contract is terminated prior to its
expiration.
91
Contractual
Obligations
A summary of our contractual obligations as of
September 30, 2011 is provided in the following table.
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Obligations Due in Period
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(in thousands)
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Contractual Obligation
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2011
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2012
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2013
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2014
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2015
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|
|
Thereafter
|
|
|
Total
|
|
|
Long-term debt
|
|
$
|
|
|
|
$
|
|
|
|
$
|
15,210
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
15,210
|
|
Interest on long-term debt(1)
|
|
$
|
152
|
|
|
$
|
608
|
|
|
$
|
608
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,368
|
|
Office lease
|
|
$
|
45
|
|
|
$
|
89
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
134
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations
|
|
$
|
197
|
|
|
$
|
697
|
|
|
$
|
15,818
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
16,712
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Based upon an interest rate of 4.0%
under the credit facilities at September 30, 2011.
|
Quantitative
and Qualitative Disclosure about Market Risk
We are exposed to market risk, including the effects of adverse
changes in commodity prices and interest rates as described
below. The primary objective of the following information is to
provide quantitative and qualitative information about our
potential exposure to market risks. The term market
risk refers to the risk of loss arising from adverse
changes in oil and natural gas prices and interest rates. The
disclosures are not meant to be precise indicators of expected
future losses, but rather indicators of reasonably possible
losses. All of our market risk sensitive instruments were
entered into for purposes other than speculative trading.
Commodity
Price Risk
Our major market risk exposure is in the pricing that we receive
for our oil production. Realized pricing is primarily driven by
the spot market prices applicable to the prevailing price for
oil. Pricing for oil has been volatile and unpredictable for
several years, and this volatility is expected to continue in
the future. The prices we receive for our oil production depend
on many factors outside of our control, such as the strength of
the global economy.
To reduce the impact of fluctuations in oil prices on our
revenues, or to protect the economics of property acquisitions,
we periodically enter into commodity derivative contracts with
respect to a significant portion of our projected oil production
through various transactions that fix the future prices
received. These hedging activities are intended to manage our
exposure to oil price fluctuations. We do not enter into
derivative contracts for speculative trading purposes.
Swaps
In a typical commodity swap agreement we receive the difference
between a fixed price per unit of production and a price based
on an agreed upon published third-party index, if the index
price is lower than the fixed price. If the index price is
higher than the fixed price, we pay the difference. By entering
into swap agreements, we effectively fix the price that we will
receive in the future for the hedged production. Our swaps are
settled in cash on a monthly basis.
For a summary of the oil swaps and swap prices, related basis
swap prices and resulting adjusted swap prices in place as of
September 30, 2011, please read Liquidity and
Capital Resources Derivative Contracts.
Put/Call
Options
A combination of a put option we purchase and a call option we
sell is often referred to as a put/call or a
collar. In a typical collar transaction, if the
reference price, based on NYMEX quoted prices, is below the
floor price, we receive an amount equal to this difference
multiplied by the specified volume. If the reference price
exceeds the floor price and is less than the ceiling
92
price, no payment is required by either party. If the reference
price exceeds the ceiling price, we must pay an amount equal to
this difference multiplied by the specified volume.
For a summary of the oil collars in place as of
September 30, 2011, please read Liquidity and
Capital ResourcesDerivative Contracts.
Interest
Rate Risk
At September 30, 2011 we had $15.2 million of debt
outstanding under our existing credit facilities, with an
effective interest rate of 4.0%. Assuming no change in the
amount outstanding, the impact on interest expense of a 10%
increase or decrease in the average interest rate would be
approximately $60,000 on an annual basis. At the closing of this
offering, we intend to enter into a new revolving credit
facility, which will allow us to borrow up to
$75.0 million, at an interest rate ranging from LIBOR plus
1.75% to LIBOR plus 2.75% or the prime rate plus 0.75% to the
prime rate plus 1.75% depending on the amount borrowed. The
prime rate will be the United States prime rate as announced
from time-to-time by the Royal Bank of Canada. We plan to
initially borrow $45.0 million at a rate of LIBOR plus 2.25%, or
approximately 2.5%, based on the current one-month LIBOR rate.
Counterparty
and Customer Credit Risk
Our oil derivative contracts expose us to credit risk in the
event of nonperformance by counterparties. While we do not
require our counterparties to our derivative contracts to post
collateral, it is our policy to enter into derivative contracts
only with counterparties that are major, creditworthy financial
institutions deemed by management as competent and competitive
market makers. We evaluate the credit standing of such
counterparties by reviewing their credit rating. The
counterparties to our derivative contracts currently in place
are lenders under our credit facility and have investment grade
ratings. We expect to enter into future derivative contracts
with these or other lenders under our new credit facility whom
we expect will also carry investment grade ratings.
We are also subject to credit risk due to the concentration of
our revenues attributable to one significant customer, Sunoco
Logistics for our 2011 production and a small number of
significant customers for our 2012 production. The inability or
failure of Sunoco Logistics, Enterprise or any other significant
customer to meet its obligations to us or its insolvency or
liquidation may adversely affect our financial results. However,
Sunoco Logistics has a positive payment history, and Sunoco
Logistics and Enterprise each have investment grade credit
ratings. Accordingly, we believe that the credit quality of both
Sunoco Logistics and Enterprise is high.
Critical
Accounting Policies and Estimates
Oil
and Natural Gas Quantities
Our estimates of proved reserves are based on the quantities of
oil and natural gas that engineering and geological analyses
demonstrated, with reasonable certainty, to be recoverable from
established reservoirs in the future under current operating and
economic parameters. The estimates of our proved reserves as of
December 31, 2010 and September 30, 2011 included in
this prospectus are based on reserve reports prepared by our
reservoir engineering staff and audited by Cawley,
Gillespie & Associates, Inc. The accuracy of our
reserve estimates is a function of many factors, including the
quality and quantity of available data, the interpretation of
that data, the accuracy of various economic assumptions, and the
judgments of the individuals preparing the estimates.
Our proved reserve estimates are also a function of many
assumptions, all of which could deviate significantly from
actual results. For example, when the price of oil and natural
gas increases, the economic life of our properties is extended,
thus increasing estimated proved reserve quantities and making
certain projects economically viable. Likewise, if oil and
natural
93
gas prices decrease, the properties economic life is reduced and
certain projects may become uneconomic, reducing estimated
proved reserved quantities. Oil and natural gas price volatility
adds to the uncertainty of our reserve quantity estimates. As
such, reserve estimates may materially vary from the ultimate
quantities of oil, natural gas and natural gas liquids
eventually recovered.
In January 2010, the Financial Accounting Standards Board
(FASB) issued Accounting Standards Update
(ASU)
2010-03 to
align the oil and natural gas reserve estimation and disclosure
requirements of Extractive IndustriesOil and Gas Topic of
the Accounting Standards Codification with the requirements in
the SECs final rule, Modernization of the Oil and Gas
Reporting Requirements. We implemented ASU
2010-03 as
of December 31, 2010. Key items in the new rules include
changes to the pricing used to estimate reserves whereby an
unweighted average of the
first-day-of-the-month
price for each month within the applicable twelve-month period
is used rather than a single day spot price, the use of new
technology for determining reserves, the ability to include
nontraditional resources in reserves and permitting disclosure
of probable and possible reserves.
Successful Efforts Method of Accounting
We account for oil and natural gas properties in accordance with
the successful efforts method. In accordance with this method,
all leasehold and development costs of proved properties are
capitalized and amortized on a
unit-of-production
basis over the remaining life of the proved reserves and proved
developed reserves, respectively.
We evaluate the impairment of our proved oil and natural gas
properties on a
field-by-field
basis whenever events or changes in circumstances indicate that
the carrying value may not be recoverable. The carrying values
of proved properties are reduced to fair value when the expected
undiscounted future cash flow is less than net book value. The
fair values of proved properties are measured using valuation
techniques consistent with the income approach, converting
future cash flow to a single discounted amount. Significant
inputs used to determine the fair values of proved properties
include estimates of: (i) reserves; (ii) future
operating and developmental costs; (iii) future commodity
prices; and (iv) a market-based weighted average cost of
capital rate. The underlying commodity prices embedded in our
estimated cash flow is the product of a process that begins with
NYMEX forward curve pricing, adjusted for estimated location and
quality differentials, as well as other factors that management
believes will impact realizable prices. Costs of retired, sold
or abandoned properties that constitute a part of an
amortization base are charged or credited, net of proceeds, to
accumulated depreciation and depletion unless doing so
significantly affects the
unit-of-production
amortization rate, in which case a gain or loss is recognized
currently. Gains or losses from the disposal of other properties
are recognized currently. Expenditures for maintenance and
repairs necessary to maintain properties in operating condition
are expensed as incurred. Estimated dismantlement and
abandonment costs are capitalized, net of salvage, at their
estimated net present value and amortized on a
unit-of-production
basis over the remaining life of the related proved developed
reserves.
Costs related to unproved properties include costs incurred to
acquire unproved reserves. Because these reserves do not meet
the definition of proved reserves, the related costs are not
classified as proved properties. Unproved leasehold costs are
capitalized and amortized on a composite basis if individually
insignificant, based on past success, experience and average
lease-term lives. Individually significant leases are
reclassified to proved properties if successful and expensed on
a lease by lease basis if unsuccessful or the lease term
expires. Unamortized leasehold costs related to successful
exploratory drilling are reclassified to proved properties and
depleted on a
unit-of-production
basis. We will assess unproved properties for impairment
quarterly on the basis of our experience in similar situations
and other factors such as the primary lease terms of the
properties, the average holding period of unproved properties
are measured using valuation techniques consistent with the
income approach, converting future
94
cash flow to a single discounted amount. Significant inputs used
to determine the fair values of unproved properties include
estimates of: (i) reserves; (ii) future operating and
development costs; (iii) future commodity prices; and
(iv) a market-based weighted average cost of capital rate.
The market-based weighted average cost of capital rate is
subjected to additional project-specific risking factors.
Impairment of Oil and Natural Gas Properties
For the year ended December 31, 2010 and the six months
ended December 31, 2009 we recorded a non-cash impairment
charge of approximately $1.9 million and $9.2 million,
respectively, primarily associated with proved oil and natural
gas properties related to unfavorable market conditions. For the
year ended December 31, 2010, approximately
$0.6 million of the impairment charge was associated with
properties that were sold to the Mid-Con Affiliates. For the
year ended December 31, 2009, approximately
$4.1 million and $3.3 million of the impairment charge
was associated with properties that were sold to the Mid-Con
Affiliates and to an unaffiliated third party, respectively. The
carrying values of the impaired proved properties were reduced
to fair value, estimated using inputs characteristic of a
Level 3 fair-value measurement. The charges are included in
impairment of oil and natural gas properties in our combined
statement of operations. We recorded no impairment charge for
proved oil and natural gas properties for the years ended
June 30, 2009 and June 30, 2008.
Asset Retirement Obligations
The initial estimated asset retirement obligation associated
with oil and natural gas properties is recognized as a
liability, with a corresponding increase in the carrying value
of oil and natural gas properties. Amortization expense is
recognized over the estimated productive life of the related
assets. If the fair value of the estimated asset retirement
obligation changes, an adjustment is recorded to both the
liability and the carrying value of the property. Revisions in
estimated liabilities can result from revisions of estimated
inflation rates, escalating retirement costs and changes in the
estimated timing of settling asset retirement obligations.
Revenue Recognition
Oil and natural gas revenues are recorded when title passes to
the customer, net of royalties, discounts and allowances, as
applicable.
Derivative Contracts and Hedging Activities
Current accounting rules require that all derivative contracts,
other than those that meet specific exclusions, be recorded at
fair value. Quoted market prices are the best evidence of fair
value. If quotations are not available, managements best
estimate of fair value is based on the quoted market price of
derivatives with similar characteristics or on other valuation
techniques.
Our derivative contracts are exchange-traded transactions.
Valuation is determined by reference to readily available public
data.
We recognize all of our derivative contracts as either assets or
liabilities at fair value. The accounting for changes in the
fair value (i.e., gains or losses) of a derivative contract
depends on whether it has been designated and qualifies as part
of a hedging relationship, and further, on the type of hedging
relationship. For those derivative contracts that are designated
and qualify as hedging instruments, we designated the hedging
instrument, based on the exposure being hedged, as either a fair
value hedge or a cash flow hedge. For derivative contracts not
designated as hedging instruments, the gain or loss is
recognized in current earnings during the period of change. None
of our derivatives was designated as a hedging instrument during
the nine months ended September 30, 2011, the year ended
December 31, 2010, the six months ended December 31,
2009, or the year ended June 30, 2009 and 2008,
respectively.
95
Recently
Issued Accounting Pronouncements
In December 2010, the Financial Accounting Standards Board (the
FASB) issued Accounting Standards Update (ASU)
2010-29,
Business Combinations (Topic 805): Disclosure
of Supplementary Pro Forma Information for Business
Combinations, which updates the amended guidance in
Accounting Standards Codification (ASC) Topic
805-10-50.
This update was issued in order to address diversity in practice
about the interpretation of the pro forma revenue and earnings
disclosure requirements for business combinations.
The update requires a public entity to disclose pro forma
information for business combinations that occurred in the
current reporting period. The disclosures include pro forma
revenue and earnings of the combined entity for the current
reporting period as though the acquisition date for all business
combinations that occurred during the year had been as of the
beginning of the annual reporting period. If comparative
financial statements are presented, the pro forma revenue and
earnings of the combined entity for the comparable prior
reporting period should be reported as though the acquisition
date for all business combinations that occurred during the
current year had been as of the beginning of the comparable
prior annual reporting period.
In practice, some preparers have presented the pro forma
information in their comparative financial statements as if the
business combination that occurred in the current reporting
period had occurred as of the beginning of each of the current
and prior annual reporting periods. Other preparers have
disclosed the pro forma information as if the business
combination occurred at the beginning of the prior annual
reporting period only, and carried forward the related
adjustments, if applicable, through the current reporting
period. We plan to adopt the updated rules in relation to all
future business combinations.
Internal
Controls and Procedures
Prior to the completion of this offering, we were a private
company with limited accounting personnel and other supervisory
resources to adequately execute our accounting processes and
address our internal control over financial reporting.
Subsequent to completion of the review of our interim combined
financial information as of September 30, 2011 and for the
nine month period then ended, our independent registered public
accountants identified and communicated material weaknesses
related to ineffective internal controls to ensure that
misstatements of more than a significant magnitude were detected
during the routine financial statement closing process which
resulted in errors in the calculation of depreciation, depletion
and amortization and impairment of proved oil and gas properties
and in the recording of certain geological and geophysical
costs. These errors caused us to make several adjustments to our
financial statements, resulting in a restatement of many of our
financial statements for the periods presented in this
registration statement. A material weakness is a control
deficiency, or a combination of control deficiencies, in
internal control over financial reporting, such that there is
reasonable possibility that a material misstatement of our
annual or interim financial statements will not be prevented or
detected on a timely basis. A control deficiency exists when the
design or operation of a control does not allow management or
employees, in the normal course of performing their assigned
functions, to prevent or detect misstatements on a timely basis.
We have taken steps, including hiring additional accounting
personnel and purchasing new accounting software, that we
believe will assist us in resolving these deficiencies. Upon the
completion of this offering, we will not have completed all of
these steps and fully remediated these material weaknesses, and
we will have had only limited operating experience with the
improvements we have made to date. We will continue our efforts
to ensure that the new accounting and control procedures that we
have put in place to address the issues set forth above are
functioning properly. However, we will not complete this process
until after this offering is completed. We cannot predict the
outcome of this process at this time.
We are not currently required to comply with the SECs
rules implementing Section 404 of the Sarbanes-Oxley Act of
2002, and are therefore not required to make a formal assessment
of
96
the effectiveness of our internal control over financial
reporting for that purpose. Upon becoming a publicly traded
partnership, we will be required to comply with the SECs
rules implementing Sections 302 and 404 of the
Sarbanes-Oxley Act of 2002, which will require our management to
certify financial and other information in our quarterly and
annual reports and provide an annual management report on the
effectiveness of our internal controls over financial reporting.
Though we will be required to disclose changes made to our
internal controls and procedures on a quarterly basis, we will
not be required to make our first annual assessment of our
internal controls over financial reporting pursuant to
Section 404 until the year following our first annual
report. To comply with the requirements of being a publicly
traded partnership, we will need to implement additional
internal controls, reporting systems and procedures and hire
additional accounting, finance and legal staff.
Inflation
Inflation in the United States has been relatively low in recent
years and did not have a material impact on our results of
operations for the years ended December 31, 2008, 2009 and
2010. Although the impact of inflation has been insignificant in
recent years, it is still a factor in the U.S. economy, and
we tend to experience inflationary pressure on the cost of
oilfield services and equipment, as increasing oil prices
increase drilling activity in our areas of operations.
Off-Balance
Sheet Arrangements
Currently, we do not have any off-balance sheet arrangements.
97
BUSINESS
AND PROPERTIES
Overview
We are a Delaware limited partnership formed in July 2011 to
own, operate, acquire, exploit and develop producing oil and
natural gas properties in North America, with a focus on the
Mid-Continent region of the United States. Our management team
has significant industry experience, especially with waterflood
projects and, as a result, our operations focus primarily on
enhancing the development of producing oil properties through
waterflooding. Through the continued development of our existing
properties and through future acquisitions, we will seek to
increase our reserves and production in order to maintain and,
over time, increase distributions to our unitholders. Also, in
order to enhance the stability of our cash flow for the benefit
of our unitholders, we will seek to hedge a significant portion
of our production volumes through various commodity derivative
contracts.
As of September 30, 2011, our total estimated proved
reserves were 9.9 MMBoe, of which approximately 98% were
oil and approximately 69% were proved developed, both on a Boe
basis. As of September 30, 2011, we operated 99% of our
properties and 92% were being produced under waterflood, in each
instance on a Boe basis. Our average net production for the
month ended September 30, 2011 was approximately 1,343 Boe
per day and our total estimated proved reserves had a
reserve-to-production
ratio of approximately 20 years. Our management team
developed approximately 60% of our total reserves through new
waterflood projects.
Our properties are located in the Mid-Continent region of the
United States and primarily consist of mature, legacy onshore
oil reservoirs with long-lived, relatively predictable
production profiles and low production decline rates. Our core
areas of operation are located in Southern Oklahoma,
Northeastern Oklahoma and parts of Oklahoma and Colorado within
the Hugoton Basin. As of September 30, 2011, approximately
91% of the properties associated with our estimated reserves, on
a Boe basis, have been producing continuously since 1982 or
earlier. Through the application of waterflooding, we believe
these mature properties have attractive upside potential.
Waterflooding, a form of secondary oil recovery, works by
repressuring a reservoir through water injection and pushing or
sweeping oil to producing wellbores. Based on the
production estimates from our September 30, 2011 reserve
report, the average estimated decline rate for our proved
developed producing reserves is approximately 8.5% for 2012 and,
on a compounded average decline basis, approximately 11% for the
subsequent five years and approximately 10% thereafter.
The following table summarizes information by core area
regarding our pro forma estimated oil and natural gas reserves
as of September 30, 2011 and our average net production for
the month ended September 30, 2011.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
Estimated
|
|
|
for the Month Ended
|
|
|
|
|
|
|
|
|
|
Net Proved Reserves
|
|
|
September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
as of September 30, 2011
|
|
|
2011
|
|
|
Average
|
|
|
Gross Active Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve-to-
|
|
|
Oil and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% Proved
|
|
|
Boe/d
|
|
|
Boe/d
|
|
|
Production
|
|
|
Natural
|
|
|
Injection
|
|
|
|
(MBoe)
|
|
|
% Operated
|
|
|
% Oil
|
|
|
Developed
|
|
|
Gross
|
|
|
Net
|
|
|
Ratio(1)
|
|
|
Gas Wells
|
|
|
Wells
|
|
|
Southern Oklahoma
|
|
|
5,385
|
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
66
|
%
|
|
|
2,139
|
|
|
|
784
|
|
|
|
19
|
|
|
|
65
|
|
|
|
42
|
|
Northeastern Oklahoma
|
|
|
3,129
|
|
|
|
100
|
%
|
|
|
99
|
%
|
|
|
68
|
%
|
|
|
572
|
|
|
|
329
|
|
|
|
26
|
|
|
|
154
|
|
|
|
59
|
|
Hugoton Basin
|
|
|
1,045
|
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
75
|
%
|
|
|
263
|
|
|
|
160
|
|
|
|
18
|
|
|
|
43
|
|
|
|
18
|
|
Other
|
|
|
349
|
|
|
|
61
|
%
|
|
|
60
|
%
|
|
|
100
|
%
|
|
|
222
|
|
|
|
70
|
|
|
|
14
|
|
|
|
13
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
9,908
|
|
|
|
99
|
%
|
|
|
98
|
%
|
|
|
69
|
%
|
|
|
3,196
|
|
|
|
1,343
|
|
|
|
20
|
|
|
|
275
|
|
|
|
123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The average
reserve-to-production
ratio is calculated by dividing estimated net proved reserves as
of September 30, 2011 by average net production for the
month ended September 30, 2011.
|
98
The following chart summarizes our pro forma total average net
Boe production volumes on a monthly basis, and illustrates the
100% increase in our production volumes over the twelve months
ended September 30, 2011. We achieved approximately 75% of
this production increase primarily through ongoing waterflood
response from existing development activities and approximately
25% of this production increase from workovers and acquisitions.
Our
Hedging Strategy
Our hedging strategy seeks to reduce the impact to our cash flow
from commodity price volatility. We intend to enter into
commodity derivative contracts at times and on terms designed to
maintain, over the long-term, a portfolio covering approximately
50% to 80% of our estimated oil production from proved reserves
over a
three-to-five
year period at any given point in time. For the years ending
December 31, 2011, 2012 and 2013, we have commodity
derivative contracts covering approximately 37%, 53% and 30%,
respectively, of our estimated oil production from proved
reserves as of September 30, 2011. All of our derivative
contracts for 2012 and 2013 are either swaps with fixed
settlements or collars. The weighted average minimum prices on
all of our derivative contracts for 2012 and 2013 are $101.18
and $100.14, respectively. A collar is a combination
of a put option we purchase and a call option we sell. The put
option portion of a collar is also referred to as a
floor. A floor establishes a minimum average sale
price for future oil production. In 2012, we have collars with a
floor of $100.00 and swaps with fixed price settlements ranging
from $100.97 to $104.28 covering approximately 11% and 42%,
respectively, of our total proved estimated oil production. In
2013, we have collars with a floor of $100.00 and swaps with
fixed price settlements ranging from $96.00 to $105.80 covering
9% and 21%, respectively, of our total proved estimated oil
production.
We intend to enter into additional commodity derivative
contracts in connection with material increases in our estimated
production and at times when we believe market conditions or
other circumstances suggest that it is prudent to do so as
opposed to entering into commodity
99
derivative contracts at predetermined times or on prescribed
terms. Additionally, we may take advantage of opportunities to
modify our commodity derivative portfolio to change the
percentage of our hedged production volumes or the duration of
our hedge contracts when circumstances suggest that it is
prudent to do so.
By removing a significant portion of price volatility associated
with our estimated future oil production, we have mitigated, but
not eliminated, the potential effects of changing oil prices on
our cash flow from operations for those periods. For a further
description of our commodity derivative contracts, please read
Managements Discussion and Analysis of Financial
Condition and Results of OperationsLiquidity and Capital
ResourcesDerivative Contracts.
Our
Business Strategies
Our primary business objective is to generate stable cash flow,
which will allow us to make quarterly cash distributions to our
unitholders at the initial quarterly distribution rate and, over
time, to increase our quarterly cash distributions. To achieve
our objective, we intend to execute the following business
strategies:
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Continue exploitation of our existing properties to
maximize production. We plan to continue
exploiting our proved reserves to maximize production, primarily
through waterflood projects and through various oil recovery
methods, including workovers, conventional hydraulic fracturing,
re-stimulations, recompletions, infill drilling and other
optimization activities. Using these techniques, we
significantly increased our average net pro forma production
over the twelve months ended September 30, 2011. We expect
to continue these activities in order to maximize our production.
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Pursue acquisitions of long-lived, low-risk producing
properties with upside potential. We will
seek to acquire onshore properties with long-lived reserves, low
production decline rates and low-risk development potential. We
also will seek to acquire properties within mature oil fields
with opportunities for incremental improvements in oil recovery
through waterfloods and other recovery techniques, which we
believe will offer us additional potential to increase reserves,
production and cash flow.
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Capitalize on our relationship with the Mid-Con Affiliates
for favorable acquisition opportunities. We
expect that the Mid-Con Affiliates will invest capital and
technical staff resources to acquire and develop properties with
existing waterfloods and to identify, acquire, form and develop
new waterflood projects on those properties. Through this
relationship with the Mid-Con Affiliates, we plan to avoid much
of the capital, engineering and geological risks associated with
the early development of any of these properties we may acquire.
While they are not obligated to sell any properties to us and
may have difficulties acquiring and developing them, we expect
that the Mid-Con Affiliates will offer to sell properties to us
from time to time. We believe that the opportunity to acquire
properties from the Mid-Con Affiliates provides us with a
strategic advantage over those of our competitors who must bear
a greater share of development risks themselves.
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Maintain operational control and a focus on
cost-effectiveness in all our operations. As
of September 30, 2011, we operated 99% of our properties,
as calculated on a Boe basis, through our affiliate, Mid-Con
Energy Operating. We plan to continue exercising this level of
operational control over our existing properties and favor
acquisitions of operated properties in order to manage the
timing and levels of our capital expenditures, development
activities and operating costs.
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Reduce the impact of commodity price volatility on our
cash flow through a disciplined commodity hedging
strategy. We will seek to reduce the impact
of commodity price volatility on our cash flow by maintaining a
portfolio covering approximately 50% to 80% of our estimated oil
production from proved reserves over a
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three-to-five
year period. As opposed to entering into commodity derivative
contracts at predetermined times or on prescribed terms, we
intend to enter into commodity derivative contracts in
connection with material increases in our estimated production
and at times when we believe market conditions or other
circumstances suggest that it is prudent to do so. Additionally,
we may take advantage of opportunities to modify our commodity
derivative portfolio to change the percentage of our hedged
production volumes or the duration of our hedge contracts when
circumstances suggest that it is prudent to do so.
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Maintain a balanced capital structure to allow for
financial flexibility to execute our business
strategies. We intend to maintain a balanced
capital structure that will afford us the financial flexibility
to execute our business strategies. We believe our borrowing
capacity under our new credit facility, our access to capital
markets and internally generated cash flow will provide us with
the liquidity and financial flexibility to exploit organic
growth opportunities and allow us to pursue additional
acquisitions of producing properties.
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Utilize compensation programs that align the interests of
our management team with our unitholders. We
will tie the compensation of our executives and directors
directly to achieving our strategic, operating and financial
goals and to adopt compensation programs that place a
significant part of the pay of each of our executives at
risk in the form of an annual short-term incentive award
and long-term, equity-based incentive grants. The amount of the
annual short-term incentive award paid will depend on our
performance against financial and operating objectives as well
as the executive meeting key leadership and development
standards. A portion of the compensation of the executives will
also be in the form of equity awards that tie their compensation
directly to creating unitholder value over the long-term. We
believe this combination of annual short-term incentive awards
and long-term equity awards aligns the incentives of our
management with our unitholders.
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Our
Competitive Strengths
We believe that the following competitive strengths will allow
us to successfully execute our business strategies and achieve
our objective of generating and growing cash available for
distribution:
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An asset portfolio largely consisting of properties with
existing waterflood projects that have relatively predictable
production profiles, that provide growth potential through
ongoing response to waterflooding and that have modest capital
requirements. Our properties consist of
interests in mature fields located in Oklahoma and Colorado that
have well-understood geologic features, relatively predictable
production profiles and modest capital requirements, which we
believe make them well-suited for waterflood development and for
our objective of generating stable cash flow. Over 90% of our
properties are being waterflooded and over 90% have been
producing continuously since 1982 or earlier. Based on
production estimates from our September 30, 2011 reserve
report, the average estimated decline rate for our existing
proved developed producing reserves is approximately 8.5% for
2012 and, on a compounded average decline basis, approximately
11% for the subsequent five years and approximately 10%
thereafter. Further, we believe that a substantial majority of
the capital required for growth from our existing properties has
been spent prior to this offering. As a result, these properties
have relatively predictable production profiles and production
growth potential with modest capital requirements.
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The ability to further exploit existing mature properties
by utilizing our waterflood expertise. Our
management team has actively operated most of our properties
since 2005, and has a history of exploiting proved reserves to
maximize production,
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101
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primarily through waterflood projects. Over the last six years,
we identified, initiated, acquired, formed and developed over
24% of all new waterflood projects in the State of Oklahoma,
while the next most active competitor formed only 6% of all new
waterfloods. Furthermore, our experience in the Mid-Continent
allows us to exploit synergies developed by applying knowledge
of field, reservoir and play characteristics across the region.
We believe that our expertise in secondary recovery techniques
will increase the level of production from certain of our
properties, particularly from existing waterflood projects,
which, over time, may increase our cash flow.
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Acquisition opportunities that are consistent with our
criteria of predictable production profiles with upside
potential that may arise as a result of our relationship with
the Mid-Con Affiliates. We expect the Mid-Con
Affiliates to invest capital and technical staff resources to
acquire and develop properties with existing projects and to
identify, acquire, form and develop new waterflood projects on
their properties. While they are not obligated to sell any
properties to us and may have difficulties acquiring and
developing them, we expect that the Mid-Con Affiliates will
offer to sell properties to us from time to time. Through this
relationship with the Mid-Con Affiliates, we plan to avoid much
of the capital, engineering and geological risks associated with
the early development of any of these properties we may acquire.
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Access to the collective expertise of Yorktowns
employees and their extensive network of industry relationships
through our relationship with
Yorktown. Yorktown is a private investment
firm focused on investments in the energy sector with more than
$3.0 billion in assets under management. Following the
consummation of this offering, Yorktown will own an approximate
49.9% limited partner interest in us, making it our largest
unitholder, and will own a 50% interest in our affiliate Mid-Con
Energy Operating. With their extensive investment experience in
the oil and natural gas industry and their extensive network of
industry relationships, we believe that Yorktowns
employees are well positioned to assist us in identifying and
evaluating acquisition opportunities and in making strategic
decisions.
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The ability to better manage our operating costs, capital
expenditures and development schedule because of our high level
of operational control. As of
September 30, 2011, we operated 99% of our properties, as
calculated on a Boe basis. Following this offering, we expect to
continue exercising this level of operational control over our
properties, including any properties we acquire through future
acquisitions, which will allow us to better manage our operating
costs and capital expenditures. We believe that this substantial
operational control of our producing properties will also allow
us to maximize the value of our properties, help us to stabilize
cash flow and better control the timing and costs of our
operations.
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An enhanced ability to pursue acquisition opportunities
arising from our competitive cost of capital and balanced
capital structure. Unlike our corporate
competitors, we are not subject to federal income taxation at
the entity level. This attribute should provide us with a lower
cost of capital compared to those competitors, thereby enhancing
our ability to compete for future acquisitions of oil and, when
advantageous, natural gas properties. We also believe our low
level of indebtedness and our ability to issue additional common
units and other partnership interests in connection with these
acquisitions will improve our financial flexibility. Further, we
expect to have an available borrowing capacity of approximately
$30.0 million under our new credit facility after giving
effect to approximately $45.0 million borrowed thereunder
in connection with this offering, which will provide us with
another potential means of financing acquisition opportunities.
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The range and depth of our technical and operational
expertise will allow us to expand both geographically and
operationally to achieve our goals. During
the
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102
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past eight years, we have assembled a senior team of geologists,
engineers, landmen, accountants and operational personnel that
have been successful in developing a significant number of new
waterflood projects. Collectively, our management and employees
have prior waterflood experience in over 150 waterflood projects
located in more than ten states. We have a team of more than 60
employees, with senior leadership in all production disciplines,
and we have recruited a select group of younger professionals
that are being trained in our waterflood specialty. With this
expertise and depth, we believe this team has the ability to
generate new waterflood projects that may become future
acquisition opportunities for us. Beyond our core strength of
waterflood development, we believe that our range and depth of
expertise will allow us to expand both geographically and
operationally. Although our projects to date have been focused
on waterfloods in the Mid-Continent region, we believe our
management and operational employees have significant oil and
gas experience in many other regions of the United States. We
believe that our wealth of experience may enable us to pursue
other types of exploitation opportunities, such as infill
drilling projects, that could significantly contribute to our
strategy of generating stable cash flow and, over time,
increasing our quarterly cash distributions.
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Our
Principal Business Relationships
Our Relationship with the Mid-Con Affiliates
In June 2011, management and Yorktown formed two limited
liability companies, which we refer to as the Mid-Con
Affiliates, to acquire and develop oil and natural gas
properties that are either undeveloped or that may require
significant capital investment and development efforts before
they meet our criteria for ownership. As these development
projects mature, we expect to have the opportunity to acquire
certain of these properties from the Mid-Con Affiliates. Through
this relationship with the Mid-Con Affiliates, we plan to avoid
much of the capital, engineering and geological risks associated
with the early development of any of these properties we may
acquire. However, the Mid-Con Affiliates may not be successful
in indentifying or consummating acquisitions or in successfully
developing the new properties they acquire. Further, the Mid-Con
Affiliates are not obligated to sell any properties to us and
they are not prohibited from competing with us to acquire oil
and natural gas properties. For a summary of the process by
which such mutually agreeable prices will be determined, please
see Certain Relationships and Related Party
TransactionsReview, Approval or Ratification of
Transactions with Related Persons.
Our Relationship with Yorktown
We have a valuable relationship with Yorktown, a private
investment firm founded in 1991 and focused on investments in
the energy sector. Since 2004, Yorktown has made several equity
investments in our predecessor. Immediately following the
consummation of this offering, Yorktown will own an approximate
49.9% limited partner interest in us, making it our largest
unitholder, and will own a 50% interest in our affiliate Mid-Con
Energy Operating. Also, Peter A. Leidel, a principal of
Yorktown, will serve on our board of directors.
Yorktown currently has more than $3.0 billion in assets
under management and Yorktowns employees have extensive
investment experience in the oil and natural gas industry.
Yorktowns employees review a large number of potential
acquisitions and are involved in decisions relating to the
acquisition and disposition of oil and natural gas assets by the
various portfolio companies in which Yorktown owns interests.
With their extensive investment experience in the oil and
natural gas industry and their extensive network of industry
relationships, we believe that Yorktowns employees are
well positioned to assist us in identifying and evaluating
acquisition opportunities and in making strategic decisions.
Yorktown is not obligated to sell any properties to us and they
are not prohibited from competing with us to acquire oil and
natural gas properties. Investment funds managed by Yorktown
manage numerous other portfolio companies
103
that are engaged in the oil and natural gas industry and, as a
result, Yorktown may present acquisition opportunities to other
Yorktown portfolio companies that compete with us.
Oil
Recovery Overview
When an oil field is first produced, the oil typically is
recovered as a result of expansion of reservoir fluids which are
naturally pressured within the producing formation. The only
natural force present to move the oil through the reservoir rock
to the wellbore is the pressure differential between the higher
pressure in the rock formation and the lower pressure in the
producing wellbore. Various types of pumps are often used to
reduce pressure in the wellbore, thereby increasing the pressure
differential. At the same time, there are many factors that act
to impede the flow of oil, depending on the nature of the
formation and fluid properties, such as pressure, permeability,
viscosity and water saturation. This stage of production,
referred to as primary recovery, recovers only a
small fraction of the oil originally in place in a producing
formation, typically ranging from 10% to 25%.
After the primary recovery phase many, but not all, oil fields
respond positively to secondary recovery techniques
in which external fluids are injected into a reservoir to
increase reservoir pressure and to displace oil towards the
wellbore. Secondary recovery techniques often result in
increases in production and reserves above primary recovery.
Waterflooding, a form of secondary recovery, works by
repressuring a reservoir through water injection and
sweeping or pushing oil to producing wellbores.
Conventional hydraulic fracturing techniques are often employed
to increase a wells productivity in waterflooding. Through
waterflooding, water injection replaces the loss of reservoir
pressure caused by the primary production of oil and gas, which
is often referred to as pressure depletion or
reservoir voidage. The degree to which reservoir
voidage has been replaced through water injection is known as
reservoir fill up or, simply as fill up.
A reservoir which has had all of the produced fluids replaced by
injection is at 100% fill up. In general, peak oil production
from a waterflood typically occurs at 100% fill up. Estimating
the percentage of fill up which has occurred, or when a
reservoir is 100% filled up, is subject to a wide variety of
engineering and geologic uncertainties. As a result of the water
used in a waterflood, produced fluids contain both water and
oil, with the relative amount of water increasing over time.
Surface equipment is used to separate the oil from the water,
with the oil going to pipelines or holding tanks for sale and
the water being recycled to the injection facilities. In
general, in the Mid-Continent region, a secondary recovery
project may produce an additional 10% to 20% of the oil
originally in place in a reservoir.
A third stage of oil recovery is called tertiary
recovery. In addition to maintaining reservoir pressure,
this type of recovery seeks to alter the properties of the oil
in ways that facilitate additional production. The three major
types of tertiary recovery are chemical flooding, thermal
recovery (such as a steamflood) and miscible displacement
involving carbon dioxide
(CO2),
hydrocarbon or nitrogen injection. We are currently field
testing new technologies in chemical flooding on some of our
properties. If successful, this testing may lead to reserve and
production increases in the future. Any future tertiary
development programs and subsequent capital expenditures would
be contingent upon commercial viability established by
successful pilot testing. At this time there are no estimated
reserves or production associated with tertiary recovery
projects assigned to our properties. We will continue to review
future opportunities for growth through the use of various
tertiary recovery techniques.
Our
Properties
Our properties are located in the Mid-Continent region of the
United States in three core areas: Southern Oklahoma,
Northeastern Oklahoma and parts of Oklahoma and Colorado within
the Hugoton Basin. These core areas are each composed of
multiple units that are in close proximity to one another,
produce from the same or geologically similar reservoirs and use
similar waterflood methods. Focusing on these core areas allow
us to apply our cumulative
104
technical and operational knowledge to ongoing property
development and to better predict future rates of recovery. For
a discussion of the properties in our core areas, please see
Summary of Oil Properties and Projects.
Our properties consist of mature, legacy onshore oil reservoirs,
approximately 92% of the reserves of which are being produced
under waterflooding, on a Boe basis. Our properties include
multiple waterflood projects with varying degrees of maturity.
We have staggered the waterflooding of these properties so that
production increases from more recently developed waterfloods
offsets declines from mature waterflood areas, leading to more
stable cash flow and production.
We use words such as mature or legacy to
describe our properties as having established operating,
reservoir and production characteristics. The production and
corresponding decline rates attributable to properties of this
typein contrast with more recently drilled
propertiescan generally be forecasted with a greater
degree of accuracy. Our ability to predict future performance is
further enhanced by the familiarity that we have with most of
our properties. We have observed the performance of many of our
properties over many years, in many cases from the inception of
waterflooding. This long-term observation allows for greater
understanding of production and reservoir characteristics,
making future performance more predictable.
We own a 62% average working interest across 275 gross
producing (176 net) wells, 123 gross injection (73 net)
wells and operate 99% of our properties by value, as calculated
using the standardized measure. Approximately 98% of our revenue
is derived from the proceeds of oil production. Based on the
standardized measure, our value-weighted average working
interest on these properties was approximately 66% based on our
September 30, 2011 reserve report. Our estimated proved
reserves as of September 30, 2011 were 9.9 MMBoe, of
which approximately 98% were oil and approximately 69% were
proved developed, both on a Boe basis. For the month ended
September 30, 2011, we produced an average of 1,343 Boe per
day. Based on production estimates from our September 30,
2011 reserve report, the average estimated decline rate for our
existing proved developed producing reserves is approximately
8.5% for 2012, approximately 11% for the subsequent five years
and, on a compounded average decline basis, approximately 10%
thereafter.
The following table shows the pro forma estimated net proved oil
reserves or principal fields, based on a reserve report prepared
by our internal reserve engineers and audited by Cawley,
Gillespie & Associates, Inc., our independent
petroleum engineers, as of September 30, 2011, and certain
unaudited information regarding production and sales of oil and
natural gas with respect to such properties.
105
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Pro Forma
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Pro Forma Average Net
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Estimated Net Proved Reserves
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Production
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as of September 30,
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for the Month Ended
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2011(2)
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September 30,
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% of
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%
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2011(1)
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Total
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Proved
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Net
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% of
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Proved
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Developed
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%
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Undiscounted
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Standardized
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% of
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(Boe/d)
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Total
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MBoe
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Reserves
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% Oil
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Reserves
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Depletion(3)
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Cap. Ex.
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Measure(4)(5)
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Total
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(in millions)
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(in millions)
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Southern Oklahoma Fields/Units:
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Highlands(6)
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238
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18
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%
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2,632
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27
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%
|
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100
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%
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|
|
75
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%
|
|
|
35
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%
|
|
$
|
10
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|
|
$
|
108
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|
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35
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%
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Battle Springs(6)
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386
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|
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|
29
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%
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|
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1,158
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|
|
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12
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%
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100
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%
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82
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%
|
|
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49
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%
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$
|
4
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|
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$
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51
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16
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%
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Twin Forks(6)
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61
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5
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%
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673
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|
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7
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%
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100
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%
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|
|
66
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%
|
|
|
46
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%
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$
|
3
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$
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24
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|
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|
8
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%
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Ardmore West(6)
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35
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3
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%
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744
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8
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%
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100
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%
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|
|
2
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%
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|
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41
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%
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|
$
|
5
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|
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$
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23
|
|
|
|
7
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%
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Southeast Hewitt
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53
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4
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%
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142
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1
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%
|
|
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100
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%
|
|
|
100
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%
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|
66
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%
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$
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0
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$
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6
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|
|
2
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%
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Other Southern Oklahoma Fields/Units
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11
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<1
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%
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36
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0
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%
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99
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%
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|
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100
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%
|
|
|
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$
|
0
|
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<$
|
1
|
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|
|
0
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%
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Total Southern Oklahoma Fields / Units
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784
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59
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%
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5,385
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55
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%
|
|
|
100
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%
|
|
|
66
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%
|
|
|
|
|
|
$
|
22
|
|
|
$
|
212
|
|
|
|
68
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeastern Oklahoma Fields / Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cleveland
|
|
|
205
|
|
|
|
15
|
%
|
|
|
2,025
|
|
|
|
20
|
%
|
|
|
99
|
%
|
|
|
65
|
%
|
|
|
79
|
%(7)
|
|
$
|
5
|
|
|
$
|
43
|
|
|
|
14
|
%
|
Cushing
|
|
|
81
|
|
|
|
6
|
%
|
|
|
704
|
|
|
|
7
|
%
|
|
|
99
|
%
|
|
|
81
|
%
|
|
|
79
|
%(7)
|
|
|
2
|
|
|
$
|
16
|
|
|
|
5
|
%
|
Skiatook(6)
|
|
|
32
|
|
|
|
2
|
%
|
|
|
361
|
|
|
|
4
|
%
|
|
|
100
|
%
|
|
|
51
|
%
|
|
|
73
|
%
|
|
$
|
1
|
|
|
$
|
6
|
|
|
|
2
|
%
|
Other Northeastern Oklahoma Fields/Units
|
|
|
11
|
|
|
|
<1
|
%
|
|
|
39
|
|
|
|
0
|
%
|
|
|
98
|
%
|
|
|
100
|
%
|
|
|
|
|
|
$
|
0
|
|
|
$
|
1
|
|
|
|
0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Northeastern Oklahoma Fields / Units
|
|
|
329
|
|
|
|
24
|
%
|
|
|
3,129
|
|
|
|
31
|
%
|
|
|
99
|
%
|
|
|
68
|
%
|
|
|
|
|
|
$
|
8
|
|
|
$
|
66
|
|
|
|
21
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hugoton Fields / Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
War Party II
|
|
|
69
|
|
|
|
5
|
%
|
|
|
520
|
|
|
|
5
|
%
|
|
|
99
|
%
|
|
|
85
|
%
|
|
|
66
|
%
|
|
$
|
1
|
|
|
$
|
11
|
|
|
|
3
|
%
|
War Party I
|
|
|
49
|
|
|
|
4
|
%
|
|
|
367
|
|
|
|
4
|
%
|
|
|
100
|
%
|
|
|
69
|
%
|
|
|
87
|
%
|
|
$
|
2
|
|
|
$
|
8
|
|
|
|
3
|
%
|
Harker Ranch(6)
|
|
|
42
|
|
|
|
3
|
%
|
|
|
158
|
|
|
|
2
|
%
|
|
|
100
|
%
|
|
|
54
|
%
|
|
|
85
|
%
|
|
$
|
2
|
|
|
$
|
5
|
|
|
|
2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Hugoton Fields / Unit
|
|
|
160
|
|
|
|
12
|
%
|
|
|
1,045
|
|
|
|
11
|
%
|
|
|
100
|
%
|
|
|
75
|
%
|
|
|
|
|
|
$
|
5
|
|
|
$
|
24
|
|
|
|
8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Fields / Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decker(6)
|
|
|
27
|
|
|
|
2
|
%
|
|
|
209
|
|
|
|
2
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
68
|
%
|
|
$
|
0
|
|
|
$
|
8
|
|
|
|
2
|
%
|
Miscellaneous
|
|
|
43
|
|
|
|
3
|
%
|
|
|
140
|
|
|
|
1
|
%
|
|
|
0
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
$
|
2
|
|
|
|
1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other Fields / Units
|
|
|
70
|
|
|
|
5
|
%
|
|
|
349
|
|
|
|
3
|
%
|
|
|
60
|
%
|
|
|
100
|
%
|
|
|
|
|
|
$
|
0
|
|
|
$
|
10
|
|
|
|
3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Fields
|
|
|
1,343
|
|
|
|
100
|
%
|
|
|
9,908
|
|
|
|
100
|
%
|
|
|
98
|
%
|
|
|
69
|
%
|
|
|
|
|
|
$
|
35
|
|
|
$
|
312
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Excludes production from certain
properties, which represent less than 1% of our proved reserves
by value, as calculated using the standardized measure, as of
September 30, 2011, that were sold to the Mid-Con
Affiliates on June 30, 2011.
|
|
|
|
(2)
|
|
Includes the working interests to
be acquired from J&A Oil Company and Charles R. Olmstead
immediately prior to the closing of this offering.
|
|
(3)
|
|
Depletion is defined as cumulative
production divided by the sum of total proved reserves plus
cumulative production, all on a Boe basis. Future increases in
proved reserves for the properties listed above could result
from upward performance revisions, additional drilling,
recompletions, workovers or the formation of one or more
waterflood units. Any increase in proved reserves for a
particular property could result in a decrease in the depletion
percentage shown. Also, in the case of a new waterflood unit, we
cannot include those properties as proved reserves until we have
acquired sufficient leases to undertake a project, successfully
unitized the project area and met SEC guidelines for booking
proved secondary reserves. As a result of both of these factors,
we believe that the depletion percentages shown above may not
accurately reflect the remaining quantity of oil or natural gas
that we expect to extract from a particular property or the
value of that property.
|
106
|
|
|
(4)
|
|
Standardized measure is calculated
in accordance with Statement of Financial Accounting Standards
No. 69 Disclosures About Oil and Gas Producing
Activities, as codified in ASC Topic 932, Extractive
ActivitiesOil and Gas. Because we are a limited
partnership, we are generally not subject to federal or state
income taxes and thus make no provision for federal or state
income taxes in the calculation of our standardized measure. For
a description of our commodity derivative contracts, please read
Managements Discussion and Analysis of Financial
Condition and Results of OperationsLiquidity and Capital
ResourcesDerivative Contracts.
|
|
|
|
(5)
|
|
Our estimated net proved reserves
and standardized measure were computed by applying average
trailing
12-month
index prices (calculated as the unweighted arithmetic average of
the
first-day-of-the-month
price for each month within the applicable
12-month
period), held constant throughout the life of the properties.
These prices were adjusted by lease for quality, transportation
fees, location differentials, marketing bonuses or deductions
and other factors affecting the price received at the wellhead.
The average trailing
12-month
index prices were $94.50 per Bbl for oil and $4.17 per MMBtu for
natural gas for the 12 months ended September 30, 2011.
|
|
|
|
(6)
|
|
Denotes a waterflood project or
unit that we identified, acquired, formed and developed.
|
|
(7)
|
|
Cumulative production for these
properties has been estimated due to lack of complete historical
production information.
|
Summary of Oil Properties and Projects
Our principal fields detailed below represent approximately 98%
of our total estimated net proved reserves as of
September 30, 2011, 95% of our average daily net production
for the month ended September 30, 2011 and 99% of our
standardized measure as of September 30, 2011. Please read
Risk Factors and Managements Discussion
and Analysis of Financial Condition and Results of
Operations in evaluating the material presented below. The
following is a summary of each of our properties within our core
areas. All of the following descriptions are based on our
September 30, 2011 reserve report.
Southern Oklahoma
Highlands Unit. The Highlands Unit is in the
SE Joiner City Field, an oil-weighted field located in Love
County, Oklahoma. Since its discovery in 1980, the Highlands
Unit has produced approximately 3,021 MBoe. Production from
the Highlands Unit is from the Deese formation at an average
depth of approximately 8,000 feet. The Highlands Unit was
formed and is operated by our affiliate, Mid-Con Energy
Operating, and is being produced under waterflood. Injection
began during October 2008, and production response to injection
started in April 2009. We own 23 gross (13 net) producing
and 18 gross injection (10 net) wells in this unit with an
average working interest of 57%. As of September 30, 2011,
our properties in this unit were producing 657 Boe per day
gross, 238 Boe per day net, and contained 2,632 MBoe of
estimated net proved reserves. The current rate of 657 Boe per
day gross is approximately 42% of the future peak rate as
estimated in our September 30, 2011 reserve report, and has
increased from 91 Boe per day gross for the month of January
2010. As a result of ongoing response to waterflooding, proved
producing and proved developed reserves represent 44% and 75%,
respectively, as of September 30, 2011, of the total proved
reserves, compared to 5% and 49%, respectively, as of
January 1, 2010. Reservoir
fill-up is
estimated to be 27%.
Battle Springs Unit. The Battle Springs Unit
is in the SE Joiner City Field, an oil-weighted field located in
Love County, Oklahoma. Since its discovery in 1982, the Battle
Springs Unit has produced approximately 2,702 MBoe.
Production from the Battle Springs Unit is from the Deese
formation at an average depth of approximately 8,850 feet.
The Battle Springs Unit was formed and is operated by our
affiliate, Mid-Con Energy Operating, and is being produced under
waterflood. Injection began during September 2006, and
production response to injection started in December 2006. We
own 18 gross (9 net) producing and 14 gross injection
(7 net) wells in this unit with an average working interest of
51%. As of September 30, 2011, our properties in this unit
were producing 954 Boe per day gross, 386 Boe per day net, and
contained 1,158 MBoe of estimated net proved reserves. The
current rate of 954 Boe per day gross is approximately 93% of
the future peak rate as estimated in our September 30, 2011
reserve report, and has increased from 354 Boe per day gross for
the month of January 2010. As a result of ongoing response to
waterflooding, proved producing and proved developed reserves
represent 82% and 82%, respectively, as of September 30,
2011, of the total proved reserves, compared to 42% and 58%,
respectively, as of January 1, 2010. Reservoir
fill-up is
estimated to be 27%.
107
Ardmore West Unit. The Ardmore West Unit is in
the Ardmore West Field, an oil-weighted field located in Carter
County, Oklahoma. Since its discovery in 1969, the Ardmore West
Unit has produced approximately 685 MBoe. Production from
the Ardmore West Unit is from the Deese formation at an average
depth of approximately 7,200 feet. The Ardmore West Unit is
a waterflood currently being developed which was formed in July
2010 and is operated by our affiliate, Mid-Con Energy Operating.
We own 4 gross (4 net) producing and 1 gross (1 net)
injection wells in this unit with an average working interest of
96%. As of September 30, 2011, our properties in this unit
were producing 46 Boe per day gross, 35 Boe per day net, and
contained 744 MBoe of estimated net proved reserves. The
current rate of 46 Boe per day gross is approximately 13% of the
future peak rate as estimated in our September 30, 2011
reserve report, and has increased from 2 Boe per day gross for
the month of January 2010. Proved producing and proved developed
reserves represent 2% and 2%, respectively, as of
September 30, 2011, of the total proved reserves. Reservoir
fill-up is
0% as injection commenced during September 2011.
Twin Forks Unit. The Twin Forks Unit is in the
SE Joiner City Field, an oil-weighted field located in Carter
County, Oklahoma. Since its discovery in 1979, the Twin Forks
Unit has produced approximately 1,130 MBoe. Production from
the Twin Forks Unit is from the Deese formation at an average
depth of approximately 7,000 feet. The Twin Forks Unit was
formed and is operated by our affiliate, Mid-Con Energy
Operating, and is being produced under waterflood. Injection
began during September 2009, and production response to
injection started in October 2010. We own 6 gross (4 net)
producing and 3 gross (2 net) injection wells in this unit
with an average working interest of 64%. As of
September 30, 2011, our properties in this unit were
producing 149 Boe per day gross, 61 Boe per day net, and
contained 673 MBoe of estimated net proved reserves. The
current rate of 149 Boe per day gross is approximately 46% of
the future peak rate as estimated in our September 30, 2011
reserve report, and has increased from 36 Boe per day gross for
the month of January 2010. As a result of ongoing response to
waterflooding, proved producing and proved developed reserves
represent 39% and 66%, respectively, as of September 30,
2011, of the total proved reserves, compared to 14% and 14%,
respectively, as of January 1, 2010. Reservoir
fill-up is
estimated to be 17%.
Southeast Hewitt Unit. The Southeast Hewitt
Unit is in the SE Wilson Field, an oil-weighted field located in
Carter County, Oklahoma. Since its discovery in 1979, the
Southeast Hewitt Unit has produced approximately
1,605 MBoe. Production from the Southeast Hewitt Unit is
from the Deese formation at an average depth of approximately
6,000 feet. The Southeast Hewitt Unit is operated by our
affiliate, Mid-Con Energy Operating, and is being produced under
waterflood. Injection began during June 1997, and production
response to injection started in November 1997. Mid-Con
Energy I, LLC acquired a working interest in the SE Hewitt
Unit in November 2004, and Mid-Con Energy Operating became the
operator of the unit in May 2010. We own 9 gross (2 net)
producing and 6 gross (1 net) injection wells in this unit
with an average working interest of 22%. As of
September 30, 2011, our properties in this unit were
producing 304 Boe per day gross, 53 Boe per day net, and
contained 142 MBoe of estimated net proved reserves. The
Southeast Hewitt Unit is a mature waterflood which reached its
peak production rate during 2010. We will continue our efforts
to maximize production and reserves from the Southeast Hewitt
Unit. Reservoir
fill-up is
estimated to be 98%.
Northeastern Oklahoma
Cleveland Field. The Cleveland Field is an
oil-weighted field located in Pawnee County, Oklahoma. Since its
discovery in 1904, the entire Cleveland Field has produced
approximately 47 MMBoe, with our leases having produced
approximately 9,541 MBoe. Production from the Cleveland Field is
primarily from the multiple Pennsylvanian age sands at depths
from 1,000 to 2,400 feet. Approximately 1,720
gross acres in the Cleveland Field is being operated by our
affiliate,
Mid-Con
Energy Operating. Approximately 840 of the total 1,720
gross acres have been acquired in the last eighteen months.
We have been actively developing our Cleveland Field leases
through drilling, recompletions and workovers, resulting in an
approximate doubling of net production within
108
the last twelve months. The majority of Mid-Con Energy
Operating operated leases are produced under waterflood. We
operate 63 gross (60 net) producing wells and 19 gross
(18 net) injection wells in this field with an average
working interest of 97%. As of September 30, 2011, our
properties in this field were producing 253 Boe per day gross,
205 Boe per day net, and contained 2,025 MBoe of estimated
net proved reserves. Waterflooding in the Cleveland Field was
initiated in most areas by about 1960, although waterflood pilot
testing began on some leases prior to 1960. We believe that
reservoir fill up probably has occurred within the Bartlesville
reservoir on these properties. However, the historical injection
and production records necessary to determine fill up status are
not available. The Cleveland Field is flooded on a lease basis
and not as a unit, with the date of production response to
injection varying from lease to lease. We will continue our
efforts to maximize production and reserves from the Cleveland
Field through workovers, recompletions, water flood expansion
and infill drilling.
Cushing Field. The Cushing Field, one of the
largest oil fields (by total historical production volume) in
the United States is an oil-weighted field located in Creek
County, Oklahoma. Since its discovery in 1912, the entire
Cushing Field has produced in excess of 500 MMBoe, with our
leases having produced approximately 8,825 MBoe. Production from
the Cushing Field is primarily from multiple Pennsylvanian age
sands at depths from 1,200 to 2,500 feet. Our affiliate,
Mid-Con Energy Operating, operates approximately
3,360 acres in the Cushing Field, the majority of which are
being produced under waterflood. We are currently engaged in a
workover program on this property to develop additional zones in
existing wellbores and to return wells to production. We operate
72 gross (26 net) producing wells and 35 gross (13
net) injection wells in this field with an average working
interest of 38%. As of September 30, 2011, our properties
in this field were producing 255 Boe per day gross, 81 Boe per
day net, and contained 704 MBoe of estimated net proved
reserves. Waterflooding in the Cushing field was initiated in
some areas by about 1955, although waterflood pilot testing
began on some leases as early as 1949. We believe that reservoir
fill up probably has occurred within the main reservoir(s) on
these properties. However, the historical injection and
production records necessary to determine fill up status are not
available. The Cushing field is flooded on a lease basis and not
as units, with waterflood responses varying from lease to lease.
The Cushing Field is a mature waterflood area which has already
reached its peak production rate. We will continue our efforts
to maximize production and reserves from the Cushing Field
through workovers and recompletions.
Skiatook Project. The Skiatook Waterflood
Project is in the Skiatook Field, an oil-weighted field located
in Osage County, Oklahoma. Since its discovery in 1919, the
Skiatook Field has produced approximately 1,174 MBoe.
Production from the Skiatook Project is primarily from the
Bartlesville and Burgess formations at an average depth of
approximately 1,600 feet. The Skiatook Project was
developed by and is operated by our affiliate, Mid-Con Energy
Operating, and is being produced under waterflood. Injection
began during December 2006, and production response to injection
started in January 2008. We own 14 gross (14 net) producing
and 5 gross (5 net) injection wells in this field with a
working interest of 100%. As of September 30, 2011, our
properties in this field were producing 38 Boe per day gross, 32
Boe per day net, and contained 361 MBoe of estimated net
proved reserves. The current rate of 38 Boe per day gross is
approximately 73% of the future peak rate as estimated in our
September 30, 2011 reserve report, and has increased from
27 Boe per day gross for the month of January 2010. As a result
of ongoing response to waterflooding, proved producing and
proved developed reserves represent 51% and 51%, respectively,
as of September 30, 2011, of the total proved reserves,
compared to 16% and 16%, respectively, as of January 1,
2010. Reservoir
fill-up is
estimated to be 8%.
Hugoton Basin
War Party I and II Units. The War Party I
and II Units are in the SE Guymon Field, an oil-weighted
field located in Texas County, Oklahoma. The War Party I and II
Units were formed as waterflood units in 2001 and 2002,
respectively. War Party I and II Units have collectively
109
produced approximately 5,402 MBoe since discovery. Production
from the War Party I and II Units is from the Cherokee
formation at an average depth of approximately 5,800 feet.
The War Party I and II Units are operated by our affiliate,
Mid-Con Energy Operating, and both are being produced under
waterflood. Injection began during November 2001 and July 2002
for War Party Unit I and War Party Unit II, respectively, and
production response to injection started in February 2002 and
March 2003 for War Party Unit I and War Party Unit II,
respectively. We own 39 gross (26 net) producing wells and
15 gross (10 net) injection wells in both units with an
average working interest in War Party I of 86% and in War
Party II of 54%. As of September 30, 2011, our
properties in these units were producing 212 Boe per day gross,
118 Boe per day net, and contained 887 MBoe of estimated
net proved reserves. These are mature waterflood properties
which have already reached peak production rates and where
injection commenced several years prior to our acquisition. We
believe that reservoir fill up probably has occurred within the
main reservoir(s) on these properties. However, the historical
injection and production records necessary to determine fill up
status are not available. We are currently working to maximize
production and reserves from these units through workovers and
by returning idle wells to production.
Harker Ranch Unit. The Harker Ranch Unit is in
the Harker Ranch Field, an oil-weighted field located in
Cheyenne County, Colorado. Since its discovery in 1989, the
Harker Ranch Unit has produced over 1,062 MBoe. Production
from the Harker Ranch Field is from the Morrow formation at an
average depth of approximately 5,200 feet. The Harker Ranch
Unit was formed and is operated by our affiliate, Mid-Con Energy
Operating, and is being produced under waterflood. Injection
began during September 2006, and production response to
injection started in May 2008. We own 4 gross (4 net)
producing and 2 gross (2 net) injection wells in this unit
with a working interest of 100%. As of September 30, 2011,
our properties in this unit were producing 51 Boe per day gross,
42 Boe per day net, and contained 158 MBoe of estimated net
proved reserves. The current rate of 51 Boe per day gross is
approximately 72% of the future peak rate as estimated in our
September 30, 2011 reserve report, and has increased from
27 Boe per day gross for the month of January 2010. As a result
of ongoing response to waterflooding, proved producing and
proved developed reserves represent 54% and 54%, respectively,
as of September 30, 2011, of the total proved reserves,
compared to 9% and 9%, respectively, as of January 1, 2010.
Reservoir
fill-up is
estimated to be 60%.
Other Properties
Decker Unit. The Decker Unit is in the NW
Little Field, an oil-weighted field located in Seminole County,
Oklahoma. Since its discovery in 1954, the Decker Unit has
produced approximately 569 MBoe. Production from the Decker
Unit is from the Earlsboro formation at an average depth of
approximately 3,600 feet. The Decker Unit was formed and is
operated by our affiliate, Mid-Con Energy Operating, and is
being produced under waterflood. Injection began during December
2008, and production response to injection started in September
2009. We own 8 gross (8 net) producing and 4 gross (4
net) injection wells in this unit with an average working
interest of 98%. As of September 30, 2011, our properties
in this unit were producing 35 Boe per day gross, 27 Boe per day
net, and contained 209 MBoe of estimated net proved
reserves. The current rate of 35 Boe per day gross is
approximately 46% of the future peak rate as estimated in our
September 30, 2011 reserve report, and has increased from
18 Boe per day gross for the month of January 2010. As a result
of ongoing response to waterflooding, proved producing and
proved developed reserves represent 22% and 100%, respectively,
as of September 30, 2011, of the total proved reserves,
compared to 4% and 4%, respectively, as of January 1, 2010.
Reservoir
fill-up is
estimated to be 60%.
The balance of the Companys properties, located throughout
the State of Oklahoma, consist of a mix of operated and
non-operated properties, none of which are under waterflood. As
of September 30, 2011, our other properties contained
215 MBoe of estimated net proved reserves and generated
average net production of 65 Boe per day for the month ended
September 30, 2011.
110
Oil and
Natural Gas Reserves and Production
Internal Controls Relating to Reserve Estimates
Our proved reserves are estimated at the well or unit level and
compiled for reporting purposes by our reservoir engineering
staff. Reserves are reviewed internally by our senior management
on a quarterly basis. Following the consummation of this
offering, we anticipate that the audit committee of our board of
directors will conduct a similar review on a quarterly basis. We
expect to have our reserve estimates audited by our independent
third-party reserve engineers, Cawley, Gillespie &
Associates, Inc., at least annually.
Our staff works closely with Cawley, Gillespie &
Associates, Inc., our independent petroleum engineers, to ensure
the integrity, accuracy and timeliness of data that is furnished
to them for their reserve audit process. To facilitate their
audit of our reserves, we provide Cawley, Gillespie &
Associates, Inc. with any information they may request,
including all of our reserve information as well as geologic
maps, well logs, production tests, material balance
calculations, well performance data, operating procedures, lease
operating expenses, product pricing, production taxes and
relevant economic criteria. We also make all of our pertinent
personnel available to Cawley, Gillespie & Associates,
Inc. to respond to any questions they may have.
Technology Used to Establish Proved Reserves
Under the SEC rules, proved reserves are those quantities of oil
and natural gas that by analysis of geoscience and engineering
data can be estimated with reasonable certainty to be
economically producible from a given date forward from known
reservoirs, and under existing economic conditions, operating
methods and government regulations. The term reasonable
certainty implies a high degree of confidence that the
quantities of oil and natural gas actually recovered will equal
or exceed the estimate. Reasonable certainty can be established
using techniques that have been proven effective by actual
production from projects in the same reservoir or an analogous
reservoir or by other evidence using reliable technology that
establishes reasonable certainty. Reliable technology is a
grouping of one or more technologies (including computational
methods) that have been field tested and have been demonstrated
to provide reasonably certain results with consistency and
repeatability in the formation being evaluated or in an
analogous formation.
To establish reasonable certainty with respect to our estimated
proved reserves, our internal reserve engineers and Cawley,
Gillespie & Associates, Inc. employed technologies
that have been demonstrated to yield results with consistency
and repeatability. The technologies and economic data used in
the estimation of our proved reserves include, but are not
limited to, electrical logs, radioactivity logs, core analyses,
geologic maps and available downhole and production data,
injection data, seismic data and well test data. Reserves
attributable to producing properties with sufficient production
history were estimated using appropriate decline curves or other
performance relationships. Reserves attributable to producing
properties with limited production history and for undeveloped
locations were estimated using performance from analogous
properties in the surrounding area and geologic data to assess
the reservoir continuity. These properties were considered to be
analogous based on production performance from the same
formation and similar completion techniques.
Qualifications of Responsible Technical Persons
Internal Mid-Con Energy Operating
Person. Robbin W. Jones, P.E., Vice President and
Chief Engineer of our general partner, is the technical person
primarily responsible for overseeing the preparation of our
reserves estimates. Mr. Jones has over 30 years of
industry experience with positions of increasing responsibility
in management, production, reservoir engineering and reserve
evaluations with companies such as Enserch Exploration,
Caruthers Producing, Diamond Energy Operating Company, Equinox
Oil Company and Schlumberger Data & Consulting
Services. In 1981, he received a Bachelor of Science degree in
Petroleum Engineering from the
111
University of Tulsa. He is a Registered Professional Engineer in
the States of Louisiana and Texas and a member of the Society of
Petroleum Engineers.
Cawley, Gillespie & Associates,
Inc. Cawley, Gillespie & Associates,
Inc. is an independent oil and natural gas consulting firm. No
director, officer, or key employee of Cawley,
Gillespie & Associates, Inc. has any financial
ownership in our predecessor, the Mid-Con Affiliates, Mid-Con
Energy Operating, Yorktown or any of their respective
affiliates. Cawley, Gillespie & Associates,
Inc.s compensation for the required investigations and
preparation of its report is not contingent upon the results
obtained and reported. Cawley, Gillespie & Associates,
Inc. has not performed other work for our predecessor, the
Mid-Con Affiliates or Mid-Con Energy Operating. Cawley,
Gillespie & Associates, Inc. has performed
services for certain of Yorktowns portfolio companies. The
engineering audit presented in the Cawley, Gillespie &
Associates, Inc. report was overseen by Bob Ravnaas, P.E.,
Executive Vice President. Mr. Ravnaas is an experienced
reservoir engineer having been a practicing petroleum engineer
since of 1981. He has more than 28 years of experience in
reserves evaluation. Mr. Ravnaas received a BS with special
honors in Chemical Engineering from the University of Colorado
at Boulder in 1979, and a M.S. in Petroleum Engineering from the
University of Texas at Austin in 1981. He is a Registered
Professional Engineer in the State of Texas, a member of the
Society of Petroleum Engineers, the Society of Petroleum
Evaluation Engineers, the American Association of Petroleum
Geologists and the Society of Petrophysicists and Well Log
Analysts.
Estimated Proved Reserves
The following table presents our estimated net proved oil and
natural gas reserves and the standardized measure amounts
associated with our estimated proved reserves attributable to
our properties as of December 31, 2010, and as of
September 30, 2011, in each case, based on reserve reports
prepared by our reservoir engineering staff and audited by
Cawley, Gillespie & Associates, Inc.
|
|
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|
|
|
|
|
|
Pro Forma as of
|
|
Pro Forma as of
|
|
|
December 31,
|
|
September 30,
|
|
|
2010(2)
|
|
2011(3)
|
|
Reserve Data(1):
|
|
|
|
|
|
|
|
|
Estimated proved reserves (MBoe)
|
|
|
7,116
|
|
|
|
9,908
|
|
Estimated proved developed reserves (MBoe)
|
|
|
3,710
|
|
|
|
6,801
|
|
Estimated proved undeveloped reserves (MBoe)
|
|
|
3,406
|
|
|
|
3,107
|
|
Standardized Measure (in millions)(4)
|
|
$
|
182.1
|
|
|
$
|
312.0
|
|
|
|
|
(1)
|
|
Our estimated net proved reserves
and related standardized measure were determined using index
prices for oil and natural gas, without giving effect to
commodity derivative contracts, held constant throughout the
life of the properties. The unweighted arithmetic average
first-day-of-the-month
prices for the prior twelve months were $79.43 per Bbl for oil
and $4.37 per MMBtu for natural gas at December 31, 2010
and $94.50 per Bbl for oil and $4.17 per MMBtu for natural gas
at September 30, 2011. These prices were adjusted by lease
for quality, transportation fees, location differentials,
marketing bonuses or deductions and other factors affecting the
price received at the wellhead. For the year ended
December 31, 2010, the relevant average realized prices for
oil and natural gas were $74.15 per Bbl and $7.58 per Mcf,
respectively, on a pro forma basis. For the nine months ended
September 30, 2011, the relevant average realized prices
for oil and natural gas were $90.22 per Bbl and $7.83 per Mcf,
respectively, on a pro forma basis. Realized natural gas sales
price per Mcf includes the sale of natural gas liquids for both
the years ended December 31, 2010 and the nine months ended
September 30, 2011.
|
|
|
|
(2)
|
|
Excludes certain properties which
represented less than 1% of our proved reserves by value, as
calculated using the standardized measure, as of
September 30, 2011 that were sold to the Mid-Con Affiliates
on June 30, 2011.
|
|
|
|
(3)
|
|
Includes the working interests to
be acquired from J&A Oil Company and Charles R. Olmstead
immediately prior to the closing of this offering.
|
|
(4)
|
|
Standardized measure is calculated
in accordance with Statement of Financial Accounting Standards
No. 69 Disclosures About Oil and Gas Producing Activities,
as codified in ASC Topic 932, Extractive ActivitiesOil
and Gas. Because we are a limited partnership, we are
generally not subject to federal or state income taxes and thus
make no provision for federal or state income taxes in the
calculation of our standardized measure. For a description of
our
|
112
|
|
|
|
|
commodity derivative contracts,
please read Managements Discussion and Analysis of
Financial Condition and Results of OperationsLiquidity and
Capital ResourcesDerivative Contracts.
|
The data in the table above represent estimates only. Oil and
gas reserve engineering is inherently a subjective process of
estimating underground accumulations of oil that cannot be
measured exactly. The accuracy of any reserve estimate is a
function of the quality of available data and engineering and
geological interpretation and judgment. Accordingly, reserve
estimates may vary from the quantities of oil that are
ultimately recovered. For a discussion of risks associated with
internal reserve estimates, please read Risk
FactorsRisks Related to Our BusinessOur estimated
proved reserves and future production rates are based on many
assumptions that may prove to be inaccurate. Any material
inaccuracies in these reserve estimates or underlying
assumptions will materially affect the quantities and present
value of our estimated reserves.
Future prices received for production and costs may vary,
perhaps significantly, from the prices and costs assumed for
purposes of these estimates. The standardized measure amounts
shown above should not be construed as the current market value
of our estimated oil reserves. The 10% discount factor used to
calculate standardized measure, which is required by Financial
Accounting Standard Board pronouncements, is not necessarily the
most appropriate discount rate. The present value, no matter
what discount rate is used, is materially affected by
assumptions as to timing of future production, which may prove
to be inaccurate.
Development of Proved Undeveloped Reserves
The following table represents a summary of activity within our
proved undeveloped reserve category for the year ended
December 31, 2010:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
Gas
|
|
Total
|
|
|
(MBbl)
|
|
(MMcf)
|
|
(MBoe)
|
|
Proved undeveloped reserves-beginning of year
|
|
|
3,686
|
|
|
|
|
|
|
|
3,686
|
|
Transferred to proved developed through drilling
|
|
|
(333
|
)
|
|
|
|
|
|
|
(333
|
)
|
Increase (decrease) due to evaluation reassessments and drilling
results, net
|
|
|
(234
|
)
|
|
|
|
|
|
|
(234
|
)
|
Acquisition of reserves
|
|
|
287
|
|
|
|
|
|
|
|
287
|
|
Reduction of proved developed reserves aged five or more years
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves-end of year
|
|
|
3,406
|
|
|
|
|
|
|
|
3,406
|
|
None of our proved undeveloped reserves at September 30,
2011 are scheduled to be developed on a date more than five
years from the date the reserves were initially booked as proved
undeveloped. Historically, our capital expenditures were
substantially funded from investment capital, bank debt and cash
flow from operations. Consistent with the typical waterflood
response time range of six to eighteen months from initial
development, the transfer of proved undeveloped reserves to the
proved developed category through drilling is attributable to
development costs incurred in prior years. During 2010, our
capital expenditures for development drilling were approximately
$12.9 million. Based on our current expectations of our
cash flow, we believe that we can fund the development of our
proved undeveloped reserves associated with our waterflood
operations from our cash flow from operations and, if needed,
borrowings from our new credit facility. For a more detailed
discussion of our pro forma liquidity position, please read
Managements Discussion and Analysis of Financial
Condition and Results of OperationsLiquidity and Capital
Resources. For more information about our
predecessors historical costs associated with the
development of proved undeveloped reserves, please read
Note 11 to the Historical Consolidated Financial Statements
of our predecessor as of and for the year ended
December 31, 2010.
113
Production, Revenues and Price History
The following table sets forth information regarding combined
net production of oil and certain price and cost information
based on historical information for each of the periods
presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Con Energy I, LLC and
|
|
|
Mid-Con Energy
|
|
Mid-Con Energy II, LLC
|
|
|
Corporation
|
|
(combined)
|
|
|
(consolidated)
|
|
Six
|
|
|
|
|
|
|
|
|
Year
|
|
Year
|
|
Months
|
|
Year
|
|
Nine Months
|
|
|
Ended
|
|
Ended
|
|
Ended
|
|
Ended
|
|
Ended
|
|
|
June 30,
|
|
June 30,
|
|
December 31,
|
|
December 31,
|
|
September 30,
|
|
|
2008
|
|
2009
|
|
2009
|
|
2010
|
|
2010
|
|
2011
|
|
Production and operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
145
|
|
|
|
153
|
|
|
|
87
|
|
|
|
228
|
|
|
|
159
|
|
|
|
278
|
|
Natural gas (MMcf)
|
|
|
86
|
|
|
|
341
|
|
|
|
140
|
|
|
|
191
|
|
|
|
148
|
|
|
|
126
|
|
Total (MBoe)
|
|
|
159
|
|
|
|
210
|
|
|
|
110
|
|
|
|
260
|
|
|
|
184
|
|
|
|
299
|
|
Average net production (Boe/d)
|
|
|
437
|
|
|
|
575
|
|
|
|
602
|
|
|
|
710
|
|
|
|
674
|
|
|
|
1,094
|
|
Average sales price:(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
94.20
|
|
|
$
|
66.87
|
|
|
$
|
66.11
|
|
|
$
|
74.07
|
|
|
$
|
71.53
|
|
|
$
|
90.31
|
|
Natural gas (per Mcf)
|
|
$
|
7.17
|
|
|
$
|
6.37
|
|
|
$
|
5.33
|
|
|
$
|
7.44
|
|
|
$
|
7.44
|
|
|
$
|
7.72
|
|
Average price per Boe
|
|
$
|
89.59
|
|
|
$
|
59.13
|
|
|
$
|
58.84
|
|
|
$
|
70.46
|
|
|
$
|
67.92
|
|
|
$
|
87.21
|
|
Average unit costs per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production expenses
|
|
$
|
31.39
|
|
|
$
|
25.56
|
|
|
$
|
22.11
|
|
|
$
|
24.05
|
|
|
$
|
25.30
|
|
|
$
|
19.93
|
|
Production taxes
|
|
$
|
5.93
|
|
|
$
|
3.00
|
|
|
$
|
2.45
|
|
|
$
|
3.17
|
|
|
$
|
2.84
|
|
|
$
|
3.74
|
|
General and administrative and other
|
|
$
|
11.73
|
|
|
$
|
8.41
|
|
|
$
|
6.40
|
|
|
$
|
3.79
|
|
|
$
|
3.85
|
|
|
$
|
1.85
|
|
Depreciation, depletion and amortization
|
|
$
|
9.21
|
|
|
$
|
10.01
|
|
|
$
|
21.43
|
|
|
$
|
20.07
|
|
|
$
|
22.16
|
|
|
$
|
13.33
|
|
|
|
|
(1)
|
|
Prices do not include the effects
of derivative cash settlements.
|
Development Activities
Since January 2010, we have undertaken an extensive program,
consisting of drilling approximately 78 gross (47 net)
development wells, mostly in our Southern Oklahoma core area.
Approximately half of these development wells are injection
wells, and the remainder are producing wells. The program has
successfully increased injection and production. We expect that
this program will be substantially completed by
December 31, 2011, and should result in modest future
capital expenditure requirements.
In our Northeastern Oklahoma core area, since early 2010, we
have been engaged in an active acquisition and corresponding
exploitation program in our Cleveland Field. We have acquired a
number of leases adjacent to our legacy properties that have
been operated since 1985. These acquisitions have resulted in an
approximately 70% increase in our acreage position in the field.
Our exploitation program has consisted of returning wells to
production on acquired leases, recompleting shallower horizons
and expanding waterflood operations to include previously
unflooded reservoirs.
Effective June 1, 2011, we acquired two waterflood units,
War Party I and II Units, in our Hugoton Basin core area.
We recently engaged in a workover program to return a number of
114
inactive wells in these units to production, to optimize
producing well rates and to increase injection. This program was
substantially completed on October 31, 2011.
The following table sets forth information with respect to
development activities during the periods indicated. The
information should not be considered indicative of future
performance, nor should a correlation be assumed between the
number of productive wells drilled, quantities of reserves found
or economic value.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
4
|
|
|
|
2
|
|
|
|
7
|
|
|
|
2
|
|
|
|
21
|
|
|
|
13
|
|
Injection
|
|
|
2
|
|
|
|
2
|
|
|
|
1
|
|
|
|
1
|
|
|
|
10
|
|
|
|
5
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
2
|
|
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
4
|
|
|
|
2
|
|
|
|
7
|
|
|
|
2
|
|
|
|
21
|
|
|
|
13
|
|
Injection
|
|
|
2
|
|
|
|
2
|
|
|
|
1
|
|
|
|
1
|
|
|
|
10
|
|
|
|
5
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
6
|
|
|
|
4
|
|
|
|
8
|
|
|
|
3
|
|
|
|
35
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We are currently conducting multiple development activities,
including the drilling of 1 gross (1 net) production
wells. Because we focus primarily on secondary recovery, our
drilling activity is not indicative of our development activity
as is typical with oil and gas exploration and primary
production companies. Additionally, in our Southern Oklahoma
core area, we are in the process of drilling approximately
80 gross (43 net) wells, with 64 gross (34 net) gross
drilled as of the date of this offering, with a focus on
improving the infrastructure of the waterfloods in Carter and
Love Counties, Oklahoma. Also, we are in the process of
completing approximately 50 gross (34 net) workovers in the
Northeastern Oklahoma core area, consisting of approximately
25 gross (24 net) workovers in the Cleveland Field and
approximately 25 gross (10 net) workovers in the Cushing
Field.
Productive Wells
The following table sets forth information at September 30,
2011 relating to the productive wells in which we, on a pro
forma basis, owned a working interest as of that date.
Productive wells consist of producing wells and wells capable of
production, including natural gas wells awaiting pipeline
connections to commence deliveries and oil wells awaiting
connection to production facilities. Gross wells are the total
number of producing wells in which we own an interest, and net
wells are the sum of our fractional working interests owned in
gross wells.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Injection
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Operated
|
|
|
269
|
|
|
|
174
|
|
|
|
1
|
|
|
|
1
|
|
|
|
123
|
|
|
|
73
|
|
Non-operated
|
|
|
1
|
|
|
|
|
|
|
|
4
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
270
|
|
|
|
174
|
|
|
|
5
|
|
|
|
2
|
|
|
|
123
|
|
|
|
73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
115
Developed Acreage
The following table sets forth information as of
September 30, 2011 relating to our pro forma leasehold
acreage. Acreage related to royalty, overriding royalty and
other similar interests is excluded from this table. As of
September 30, 2011 substantially all of our leasehold
acreage was held by production.
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage
|
|
|
|
Gross
|
|
|
Net
|
|
|
Southern Oklahoma
|
|
|
8,664
|
|
|
|
4,889
|
|
Northeastern Oklahoma
|
|
|
6,119
|
|
|
|
3,776
|
|
Hugoton Basin
|
|
|
5,952
|
|
|
|
4,373
|
|
Other
|
|
|
1,281
|
|
|
|
763
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
22,016
|
|
|
|
13,800
|
|
|
|
|
|
|
|
|
|
|
Delivery Commitments
We will have no delivery commitments with respect to our
production upon the closing of this offering.
Operations
General
We operated approximately 99% of our properties, as calculated
on a Boe basis as of September 30, 2011, through our
affiliate, Mid-Con Energy Operating. All of our non-operated
wells are managed by third-party operators who are typically
independent oil and natural gas companies. We design and manage
the development, recompletion or workover for all of the wells
we operate and supervise operation and maintenance activities.
We do not own the drilling rigs or other oil field services
equipment used for drilling or maintaining wells on the
properties we operate.
We engage numerous independent contractors in each of our core
areas to provide all of the equipment and personnel associated
with our drilling and maintenance activities, including well
servicing, trucking and water hauling, bulldozing, and various
downhole services (e.g., logging, cementing, perforating and
acidizing). These services are short-term in duration (often
being completed in less than a day) and are typically governed
by a one-page service order that states only the parties
names, a brief description of the services and the price.
We also engage several independent contractors to provide
hydraulic fracturing services. These services are usually
completed in four to six hours utilizing lower pressures and
volumes of fluid than are typically employed in connection with
multi-stage hydraulic fracturing jobs performed in connection
with unconventional oil and gas shale plays. These services are
not normally governed by long-term services contracts, but
instead are generally performed under one-time service orders,
which state the parties names and the price. These service
orders sometimes contain additional terms addressing, for
example, taxes, payment due dates, warranties and limitations of
the contractors liability to damages arising from the
contractors gross negligence or willful misconduct.
Pursuant to a services agreement to be entered into in
connection with the closing of this offering, our affiliate,
Mid-Con Energy Operating, will provide certain services to us,
including management, administrative and operational services,
which include marketing, geological and engineering services.
Geological and Engineering Services
Mid-Con Energy Operating employs production and reservoir
engineers, geologists and land specialists, as well as field
production supervisors. Through the services agreement, we have
the direct operational support of a staff of 23 petroleum
professionals with significant technical expertise. We believe
that this technical expertise, which includes extensive
experience utilizing
116
secondary recovery methods, particularly waterfloods,
differentiates us from, and provides us with a competitive
advantage over, many of our competitors. Please read
Certain Relationships and Related Party
TransactionsAgreements with Affiliates in Connection with
the TransactionsServices Agreement.
Administrative Services
Mid-Con Energy Operating will also provide us with management,
administrative and operational services under the services
agreement. We will reimburse Mid-Con Energy Operating, on a cost
basis, for the allocable expenses it incurs in performing these
services. Mid-Con Energy Operating will have substantial
discretion to determine in good faith which expenses to incur on
our behalf and what portion to allocate to us. For a detailed
description of the administrative services provided by Mid-Con
Energy Operating pursuant to the services agreement, please read
Certain Relationships and Related Party
TransactionsAgreements with Affiliates in Connection with
the TransactionsServices Agreement.
Oil and Natural Gas Leases
The typical oil lease agreement covering our properties provides
for the payment of royalties to the mineral owner for all
hydrocarbons produced from any well drilled on the lease
premises. The lessor royalties and other leasehold burdens on
our properties range from less than 10% to 33%, resulting in a
net revenue interest to us ranging from 67% to 87.5%, or 83.8%
on average, on a 100% working interest basis. Based on the
standardized measure, our value-weighted average net revenue
interest on our properties was approximately 81.9%, on a 100%
working interest basis, based on our September 30, 2011
reserve report. Most of our leases are held by production and do
not require lease rental payments.
Marketing and Major Customers
For the year ended December 31, 2010, and for the nine
months ended September 30, 2011, purchases by Sunoco
Logistics accounted for approximately 76% and 87%, respectively,
of our total sales revenues. We recently entered into a new
crude oil purchase contract with Enterprise, which will be
effective as of January 1, 2012. We anticipate that, as a result
of this new contract, sales to Enterprise will account for a
significant portion of our 2012 sales revenues. Our production
is and will continue to be marketed by our affiliate, Mid-Con
Energy Operating, under these crude oil purchase contracts. By
selling a substantial majority of our current production to
Sunoco Logistics and our future production to Sunoco Logistics
and Enterprise under these contracts, we believe that we have
obtained and will continue to receive more favorable pricing
than would otherwise be available to us if smaller amounts had
been sold to several purchasers based on posted prices.
The loss of Sunoco Logistics, Enterprise or any of our other
customers could temporarily delay production and sale of our oil
and natural gas. If we were to lose any of our significant
customers, we believe that under current market conditions, we
could identify substitute customers to purchase the impacted
production volumes. However, if Sunoco Logistics or Enterprise
dramatically decreased or ceased purchasing oil from us, we may
have difficulty finding substitute customers to purchase our
production volumes at comparable rates. For a discussion of
risks associated with our relationship with our significant
customers, please read Risk FactorsRisks Related to
our BusinessWe are primarily dependent upon a small number
of customers for our production sales and we may experience a
temporary decline in revenues and production if we lose any of
those customers.
Hedging Activities
We intend to enter into commodity derivative contracts with
unaffiliated third parties to achieve more predictable cash flow
and to reduce our exposure to short-term fluctuations in oil and
natural gas prices. Our current commodity derivative contracts
are primarily fixed price
117
swaps (with collars) with NYMEX prices and option agreements.
For a more detailed discussion of our hedging activities, please
read Managements Discussion and Analysis of
Financial Condition and Results of OperationsLiquidity and
Capital Resources and Managements Discussion
and Analysis of Financial Condition and Results of
OperationsQuantitative and Qualitative Disclosure About
Market Risk.
Competition
We operate in a highly competitive environment for acquiring
properties and securing trained personnel. Many of our
competitors possess and employ financial resources substantially
greater than ours, which can be particularly important in the
areas in which we operate. Some of our competitors may also
possess greater technical and personnel resources than us. As a
result, our competitors may be able to pay more for productive
oil properties and exploratory prospects, as well as evaluate,
bid for and purchase a greater number of properties and
prospects than our financial or personnel resources permit. Our
ability to acquire additional properties and to acquire and
develop reserves will depend on our ability to evaluate and
select suitable properties and to consummate transactions in a
highly competitive environment. In addition, there is
substantial competition for capital available for investment in
the oil and natural gas industry.
We are also affected by competition for drilling rigs,
completion rigs and the availability of related equipment and
services. In recent years, the United States onshore oil and
natural gas industry has experienced shortages of drilling and
completion rigs, equipment, pipe and personnel, which have
delayed development drilling and other exploitation activities
and caused significant increases in the prices for this
equipment and personnel. We are unable to predict when, or if,
such shortages may occur or how they would affect our
development and exploitation programs.
Title to Properties
Prior to completing an acquisition of producing oil properties,
we perform title reviews on significant leases, and depending on
the materiality of properties, we may obtain a title opinion or
review previously obtained title opinions. As a result, title
examinations have been obtained on a significant portion of our
properties. After an acquisition, we review the assignments from
the seller for scriveners and other errors and execute and
record corrective assignments as necessary.
We initially conduct only a review of the titles to our
properties on which we do not have proved reserves. Prior to the
commencement of drilling operations on those properties, we
conduct a thorough title examination and perform curative work
with respect to significant defects. To the extent title
opinions or other investigations reflect title defects on those
properties, we are typically responsible for curing any title
defects at our expense. We generally will not commence drilling
operations on a property until we have cured any material title
defects on such property.
We believe that we have satisfactory title to all of our
material properties. Although title to these properties is
subject to encumbrances in some cases, such as customary
interests generally retained in connection with the acquisition
of real property, customary royalty interests and contract terms
and restrictions, liens under operating agreements, liens
related to environmental liabilities associated with historical
operations, liens for current taxes and other burdens,
easements, restrictions and minor encumbrances customary in the
oil and natural gas industry, we believe that none of these
liens, restrictions, easements, burdens and encumbrances will
materially detract from the value of these properties or from
our interest in these properties or materially interfere with
our use of these properties in the operation of our business. In
addition, we believe that we have obtained sufficient
rights-of-way
grants and permits from public authorities and private parties
for us to operate our business in all material respects as
described in this prospectus.
Hydraulic Fracturing
Hydraulic fracturing has been a routine part of the completion
process for the majority of the wells on our producing
properties in Oklahoma and Colorado for several decades. Most of
our properties are dependent on our ability to hydraulically
fracture the producing formations. We
118
are currently conducting hydraulic fracturing activities in our
Northeastern Oklahoma and Southern Oklahoma core areas. All of
our leasehold acreage is currently held by production from
existing wells. Therefore, fracturing is not currently required
to maintain this acreage but it will be required in the future
to develop the majority of our proved behind pipe and proved
undeveloped reserves associated with this acreage. Nearly all of
our proved behind pipe and proved undeveloped reserves
associated with future drilling and recompletion projects, or
33% of our total estimated proved reserves as of
September 30, 2011, will be subject to hydraulic
fracturing. Although the cost of each well will vary, on average
approximately 12.5% of the total cost of drilling and completing
a well is associated with hydraulic fracturing activities. These
costs are treated in the same way that all other costs of
drilling and completing our wells are treated and are built into
and funded through our normal capital expenditure budget. Of our
$5.0 million of estimated maintenance capital expenditures
for the year ended December 31, 2012, approximately
$0.7 million is expected to be attributable to hydraulic
fracturing.
Almost all of our hydraulic fracturing operations are conducted
on vertical wells. The fracture treatments on these wells are
much smaller and utilize much less water than what is typically
used on most of the shale gas wells that are being drilled
throughout the United States. For example, a typical
hydraulic fracture stimulation on a Marcellus shale well is
pumped in five or more stages, utilizing a total of
4 million gallons of water and 1.5 million pounds of
sand. In comparison, for our wells, a large hydraulic fracture
stimulation on one of our new wells would be pumped in three
stages utilizing a total of 50,000 gallons of water and
60,000 pounds of sand. Typical hydraulic fracture
stimulation for a recompletion of one of our existing wells
would be pumped in one stage, utilizing about
20,000 gallons of water and 15,000 pounds of sand.
We follow applicable industry standard practices and legal
requirements for groundwater protection in our operations,
subject to close supervision by state and federal regulators,
which conduct many inspections during operations that include
hydraulic fracturing. These protective measures include setting
surface casing below the deepest known depth of all subsurface
potable water, a depth sufficient to protect fresh water zones
as determined by regulatory agencies, and cementing the well
casing to create a permanent isolating barrier between the
casing pipe and surrounding geological formations. This aspect
of well design essentially eliminates a pathway for underground
migration of the fracturing fluid to contact any fresh or
potable water aquifers during the hydraulic fracturing
operations. For recompletions of existing wells, the production
casing is pressure tested prior to perforating the new
completion interval. Chemical additives used in hydraulic
fracturing are described in our hydraulic fracturing
contractors material safety data sheets which describe
their proper use and safe handling procedures. Fracturing
contractor employees are trained in the safe handling of all
fracturing fluids, chemical additives and materials and are
required to wear appropriate protective clothing, eye and foot
wear. Other protective measures include extensive safety
briefings prior to conducting fracturing operations, testing of
pumping equipment and surface lines to pressures exceeding
expected maximum fracture treating pressures prior to conducting
fracturing operations, detailed fracture treating process
checklists used by our fracturing contractors, and guidelines
for the disposal of excess fracturing fluids.
Fracture treating rates and pressures are monitored
instantaneously and in real time at the surface during our
hydraulic fracturing operations. Pressure is monitored on
surface pumping equipment and associated treating lines, the
treating string and, where applicable, the immediate annulus to
the treating string. Hydraulic fracturing operations would be
shut down if an abrupt change occurred in the treating pressure
or annular pressure.
Regulations applicable to our operating areas do not currently
require, and we do not currently evaluate, the environmental
impact of typical additives used in fracturing fluid. We note,
however, that approximately 98% of the hydraulic fracturing
fluids we use are made up of water and sand.
We minimize the use of water and dispose of it in a way that
essentially eliminates the impact to nearby surface water by
disposing excess water and water that is produced back from
119
the wells into approved disposal or injection wells. We
currently do not intentionally discharge water to the surface.
To our knowledge, there have not been any incidents, citations
or suits related to environmental concerns from our fracturing
operations.
If a surface spill or a leak were to occur, it would be
controlled, contained and remediated in accordance with the
applicable requirements of state oil and gas commissions, as
well as any Spill Prevention, Control and Countermeasures (SPCC)
plans we maintain in accordance with EPA requirements. This
would include any action up to and including total abandonment
of the wellbore.
Since hydraulic fracturing activities are part of our
operations, they are covered by our insurance against claims
made for bodily injury, property damage and clean up costs
stemming from a sudden and accidental pollution event. We may
not have coverage if we are unaware of the pollution event and
unable to report the occurrence to our insurance
company within the time frame required under our insurance
policy. We have no coverage for gradual, long-term pollution
events.
For information regarding existing and proposed governmental
regulations regarding hydraulic fracturing and related
environmental matters, please read Environmental
Matters and RegulationWater Discharges. For related
risks to our unitholders, please read Risk
FactorsRisks Related to Our BusinessFederal and
State legislative and regulatory initiatives relating to
hydraulic fracturing could result in increased costs and
additional operating restrictions or delays.
We maintain insurance coverage against potential losses that we
believe is customary in the industry. We currently maintain
general liability insurance and commercial umbrella liability
insurance with limits of $1 million and $5 million per
occurrence, respectively, and $2 million and
$5 million in the aggregate, respectively. There is a
$1,000 per claim deductible for only our property damage
liability and our containment and pollution coverage included as
part of our general liability insurance and a $10,000 retention
for our commercial umbrella liability insurance. Our general
liability insurance covers us for, among other things, legal and
contractual liabilities arising out of property damage and
bodily injury, for sudden or accidental pollution liability. Our
commercial umbrella liability insurance is in addition to and
triggered if the general liability insurance policy limits are
exceeded. In addition, we maintain control of well insurance
with per occurrence limits of $5 million and retentions of
$50,000. Our control of well policy insures us for blowout risks
associated with drilling, completing and operating our wells,
including above ground pollution.
Our current insurance policies provide coverage for losses
arising out of our hydraulic fracturing operations. These
policies may not cover fines, penalties or costs and expenses
related to government mandated
clean-up of
pollution. In addition, these policies do not provide coverage
for all liabilities, and we cannot assure you that the insurance
coverage will be adequate to cover claims that may arise, or
that we will be able to maintain adequate insurance at rates we
consider reasonable. A loss not fully covered by insurance could
have a material adverse effect on our financial position,
results of operations and cash flows.
Environmental
Matters and Regulation
General
Our operations are subject to stringent and complex federal,
tribal, state and local laws and regulations governing
environmental protection as well as the discharge of materials
into the environment. These laws and regulations may, among
other things (i) require the acquisition of permits to
conduct exploration, drilling and production operations;
(ii) restrict the types, quantities and concentration of
various substances that can be released into the environment or
injected into formations in connection with oil drilling and
production activities; (iii) limit or
120
prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas;
(iv) require remedial measures to mitigate pollution from
former and ongoing operations, such as requirements to close
pits and plug abandoned wells; and (v) impose substantial
liabilities for pollution resulting from drilling and production
operations. Any failure to comply with these laws and
regulations may result in the assessment of administrative,
civil, and criminal penalties, the imposition of corrective or
remedial obligations, and the issuance of orders enjoining
performance of some or all of our operations.
These laws and regulations may also restrict the rate of
production below the rate that would otherwise be possible. The
regulatory burden on the oil and natural gas industry increases
the cost of doing business in the industry and consequently
affects profitability. Additionally, the U.S. Congress and
federal and state agencies frequently revise environmental laws
and regulations, and any changes that result in more stringent
and costly waste handling, disposal and cleanup requirements for
the oil and natural gas industry could have a significant impact
on our operating costs.
The clear trend in environmental regulation is to place more
restrictions and limitations on activities that may affect the
environment, and thus any changes in environmental laws and
regulations or re-interpretation of enforcement policies that
result in more stringent and costly waste handling, storage
transport, disposal, or remediation requirements could have a
material adverse effect on our financial position and results of
operations. We may be unable to pass on such increased
compliance costs to our customers. Moreover, accidental releases
or spills may occur in the course of our operations, and we
cannot assure you that we will not incur significant costs and
liabilities as a result of such releases or spills, including
any third-party claims for damage to property, natural resources
or persons. While we believe that we are in substantial
compliance with existing environmental laws and regulations and
that continued compliance with existing requirements will not
materially affect us, we can provide no assurance that we will
not incur substantial costs in the future related to revised or
additional environmental regulations that could have a material
adverse effect on our business, financial condition and results
of operations.
The following is a summary of the more significant existing
environmental, health and safety laws and regulations to which
our business operations are subject and for which compliance may
have a material adverse impact on our capital expenditures,
results of operations or financial position.
Hazardous Substances and Waste
The federal Resource Conservation and Recovery Act, as amended,
or RCRA, and comparable state statutes and their respective
implementing regulations, regulate the generation,
transportation, treatment, storage, disposal and cleanup of
hazardous and non-hazardous wastes. Under the auspices of the
U.S. Environmental Protection Agency, or the EPA, most
states administer some or all of the provisions of RCRA,
sometimes in conjunction with their own, more stringent
requirements. Federal and state regulatory agencies can seek to
impose administrative, civil and criminal penalties for alleged
non-compliance with RCRA and analogous state requirements.
Drilling fluids, produced waters, and most of the other wastes
associated with the exploration, development, and production of
oil, if properly handled, are exempt from regulation as
hazardous waste under Subtitle C of RCRA. These wastes, instead,
are regulated under RCRAs less stringent solid waste
provisions, state laws or other federal laws. However, it is
possible that certain oil exploration, development and
production wastes now classified as non-hazardous could be
classified as hazardous wastes in the future. Any such change
could result in an increase in our costs to manage and dispose
of wastes, which could have a material adverse effect on our
results of operations and financial position.
The Comprehensive Environmental Response, Compensation and
Liability Act, as amended, or CERCLA, also known as the
Superfund law, and comparable state laws impose liability,
without regard to fault or legality of conduct, on classes of
persons considered to be responsible for the release of a
hazardous substance into the environment. These
persons include the
121
current and past owner or operator of the site where the release
occurred, and anyone who disposed or arranged for the disposal
of a hazardous substance released at the site. Under CERCLA,
such persons may be subject to joint and several, strict
liability for the costs of cleaning up the hazardous substances
that have been released into the environment, for damages to
natural resources and for the costs of certain health studies.
In addition, neighboring landowners and other third-parties may
file claims for personal injury and property damage allegedly
caused by the hazardous substances released into the
environment. We generate materials in the course of our
operations that may be regulated as hazardous substances.
We currently own, lease, or operate numerous properties that
have been used for oil
and/or
natural gas exploration, production and processing for many
years. Although we believe that we have utilized operating and
waste disposal practices that were standard in the industry at
the time, hazardous substances, wastes, or hydrocarbons may have
been released on, under or from the properties owned or leased
by us, or on, under or from other locations, including off-site
locations, where such substances have been taken for disposal.
In addition, some of our properties have been operated by third
parties or by previous owners or operators whose treatment and
disposal of hazardous substances, wastes, or hydrocarbons was
not under our control. These properties and the substances
disposed or released on, under or from them may be subject to
CERCLA, RCRA, and analogous state laws. Under such laws, we
could be required to undertake response or corrective measures,
which could include removal of previously disposed substances
and wastes, cleanup of contaminated property or performance of
remedial plugging or pit closure operations to prevent future
contamination.
Water Discharges
The federal Water Pollution Control Act, as amended, also known
as the Clean Water Act, and analogous state laws, impose
restrictions and strict controls with respect to the discharge
of pollutants, including oil and hazardous substances, into
waters in the United States. The discharge of pollutants into
federal or state waters is prohibited, except in accordance with
the terms of a permit issued by the EPA or an analogous state or
tribal agency that has been delegated authority for the program
by the EPA. Federal, state and tribal regulatory agencies can
impose administrative, civil and criminal penalties for
non-compliance with discharge permits or other requirements of
the Clean Water Act and analogous state laws and regulations.
Spill prevention, control and countermeasure, or SPCC, plan
requirements imposed under the Clean Water Act require
appropriate containment berms and similar structures to help
prevent the contamination of navigable waters in the event of a
hydrocarbon tank spill, rupture or leak. In addition, the Clean
Water Act and analogous state laws required individual permits
or coverage under general permits for discharges of storm water
runoff from certain types of facilities. The Oil Pollution Act
of 1990, as amended (the OPA), amends the Clean
Water Act and establishes strict liability and natural resource
damages liability for unauthorized discharges of oil into waters
of the United States. OPA requires owners or operators of
certain onshore facilities to prepare facility response plans
for responding to a worst case discharge of oil into waters of
the United States.
The Safe Drinking Water Act (the SDWA) and analogous
state laws impose requirements relating to our underground
injection activities. Under these laws, the EPA and state
environmental agencies have adopted regulations relating to
permitting, testing, monitoring, record-keeping and reporting of
injection well activities, as well as prohibitions against the
migration of injected fluids into underground sources of
drinking water. We currently own and operate a number of
injection wells, used primarily for reinjection of produced
waters that are subject to SDWA requirements.
We employ conventional hydraulic fracturing techniques to
increase the productivity of certain of our properties. This
commonly used process involves the injection of water, sand and
chemicals under pressure into rock formations to stimulate oil
and natural gas production. The
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U.S. Congress is considering legislation to amend the
federal SDWA to require the disclosure of chemicals used by the
oil and natural gas industry in connection with conventional
hydraulic fracturing. If adopted, this legislation could
establish an additional level of regulation and permitting at
the federal level, and could make it easier for third parties to
initiate legal proceedings based on allegations that chemicals
used in the fracturing process could adversely affect the
environment, including groundwater, soil and surface water. In
addition, the EPA has recently asserted regulatory authority
over certain hydraulic fracturing activities involving diesel
fuel under the SDWAs Underground Injection Program and has
begun the process of drafting guidance documents on regulatory
requirements for companies that plan to conduct hydraulic
fracturing using diesel fuel. Moreover, the EPA announced on
October 20, 2011 that it is also launching a study
regarding wastewater resulting from hydraulic fracturing
activities and currently plans to propose standards by 2014 that
such wastewater must meet before being transported to a
treatment plant. In addition, a number of other federal agencies
are also analyzing a variety of environmental issues associated
with hydraulic fracturing and could potentially take regulatory
actions that impair our ability to conduct hydraulic fracturing
activities. Some states, including Texas, and local governments
have adopted, and others are considering, regulations to
restrict and regulate hydraulic fracturing. For example, the
State of Arkansas recently required certain oil and gas
operators to cease water injection associated with hydraulic
fracturing activities due to a concern that the injection was
related to increased earthquake activity. Any similar actions by
the State of Oklahoma could have a material adverse effect on
our business, financial condition, results of operations and
ability to make distributions to our unitholders.
Air Emissions
The federal Clean Air Act, as amended, and comparable state laws
regulate emissions of various air pollutants through air
emissions standards, construction and operating permitting
programs and the imposition of other compliance requirements.
These laws and regulations may require us to obtain pre-approval
for the construction or modification of certain projects or
facilities expected to produce or significantly increase air
emissions, obtain and strictly comply with stringent air permit
requirements or utilize specific equipment or technologies to
control emissions. The need to obtain permits has the potential
to delay the development of our projects.
We may be required to incur certain capital expenditures in the
next few years for air pollution control equipment or other air
emissions-related issues. For example, on July 28, 2011,
the EPA proposed four sets of new rules which, if adopted, will
impose stringent new standards for air emissions from oil and
gas development and production operations, including crude oil
storage tanks with a throughput of at least 20 barrels per
day, condensate storage tanks with a throughput of at least
1 barrel per day, completions of new hydraulically
fractured natural gas wells, and recompletions of existing
natural gas wells that are fractured or refractured. The EPA
will receive public comment and hold hearings regarding the
proposed rules and must take final action by April 3, 2012.
If adopted, these rules may require us to incur additional
expenses to control air emissions from current operations and
during new well developments by installing emissions control
technologies and adhering to a variety of work practice and
other requirements. Though the regulations ultimately adopted
may change, we do not believe that such requirements will have a
material adverse effect on our operations.
Climate Change
On December 15, 2009, the EPA published its findings that
emissions of carbon dioxide, or
CO2,
methane, and other greenhouse gases, or GHGs, present an
endangerment to public health and the environment because
emissions of such gases are, according to the EPA, contributing
to the warming of the earths atmosphere and other climate
changes. These findings allow the EPA to adopt and implement
regulations that would restrict emissions of GHGs under existing
provisions of the federal Clean Air Act. The EPA has adopted two
sets of regulations under the Clean Air Act. The first limits
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emissions of GHGs from motor vehicles beginning with the 2012
model year. The EPA has asserted that these final motor vehicle
GHG emission standards trigger Clean Air Act construction and
operating permit requirements for stationary sources, commencing
when the motor vehicle standards took effect on January 2,
2011. On June 3, 2010, the EPA published its final rule to
address the permitting of GHG emissions from stationary sources
under the Prevention of Significant Deterioration, or
PSD, and Title V permitting programs. This rule
tailors these permitting programs to apply to
certain stationary sources of GHG emissions in a multi-step
process, with the largest sources first subject to permitting.
It is widely expected that facilities required to obtain PSD
permits for their GHG emissions also will be required to reduce
those emissions according to best available control
technology standards for GHG that have yet to be
developed. In addition, in October 2009, the EPA published a
final rule requiring the reporting of GHG emissions from
specified large GHG emission sources in the U.S. beginning
in 2011 for emissions occurring in 2010. On November 8,
2010, the EPA expanded this GHG reporting rule to include
onshore oil production, processing, transmission, storage, and
distribution facilities, with reporting beginning in 2012 for
emissions occurring in 2011. On August 4, 2011, the EPA
issued a proposed rule amending and clarifying certain
provisions of the reporting rule and extended the 2012 reporting
deadline to September 2012. We are required to report under this
rule but we do not believe that our compliance costs associated
with GHG reporting will be material.
In addition, both houses of U.S. Congress have previously
considered legislation to reduce emissions of GHGs, and almost
one-half of the states have already taken legal measures to
reduce emissions of GHGs, primarily through the planned
development of GHG emission inventories
and/or
regional GHG cap and trade programs. Most of these cap and trade
programs work by requiring either major sources of emissions or
major producers of fuels to acquire and surrender emission
allowances, with the number of allowances available for purchase
reduced each year until the overall GHG emission reduction goal
is achieved. The adoption of any legislation or regulations that
requires reporting of GHGs or otherwise limits emissions of GHGs
from our equipment and operations could require us to incur
costs to monitor and report on GHG emissions or reduce emissions
of GHGs associated with our operations, and such requirements
also could adversely affect demand for the oil that we produce.
Finally, it should be noted that some scientists have concluded
that increasing concentrations of greenhouse gases in the
Earths atmosphere may produce climate changes that have
significant physical effects, such as increased frequency and
severity of storms, droughts, and floods and other climatic
events. If any such effects were to occur in areas where we
operate, they could have an adverse effect on our assets and
operations.
National Environmental Policy Act
Oil exploration, development and production activities on
federal lands are subject to the National Environmental Policy
Act, as amended, or NEPA. NEPA requires federal agencies,
including the Department of Interior, to evaluate major agency
actions having the potential to significantly impact the
environment. In the course of such evaluations, an agency will
prepare an environmental assessment that analyses the potential
direct, indirect and cumulative impacts of a proposed project
and, if necessary, will prepare a more detailed environmental
impact statement that may be made available for public review
and comment. Currently, we have no exploration and production
activities on federal lands. However, for future or proposed
exploration and development plans on federal lands, governmental
permits or authorizations that are subject to the requirements
of NEPA may be required. This process has the potential to delay
the development of oil projects.
Endangered Species Act
The Endangered Species Act, as amended, or ESA, may impact
exploration, development and production activities on public or
private lands. The ESA provides broad protection for species of
fish, wildlife and plants that are listed as threatened or
endangered in the U.S., and prohibits
124
taking of endangered species. Federal agencies are required to
insure that any action authorized, funded or carried out by them
is not likely to jeopardize the continued existence of listed
species or modify their critical habitat. While our facilities
are located in areas that are not currently designated as
habitat for endangered or threatened species, the designation of
previously unidentified endangered or threatened species
habitats could cause us to incur additional costs or become
subject to operating restrictions or bans in the affected areas.
OSHA
We are subject to the requirements of the federal Occupational
Safety and Health Act, as amended, or OSHA, and comparable state
statutes whose purpose is to protect the health and safety of
workers. In addition, the OSHA hazard communication standard,
the Emergency Planning and Community Right to Know Act and
implementing regulations, and similar state statutes and
regulations require that we organize
and/or
disclose information about hazardous materials used or produced
in our operations and that this information be provided to
employees, state and local governmental authorities and
citizens. We believe that we are in substantial compliance with
all applicable laws and regulations relating to worker health
and safety.
Other
Regulation of the Oil and Natural Gas Industry
General
Various aspects of our oil and natural gas operations are
subject to extensive and frequently changing regulation as the
activities of the oil and natural gas industry often are
reviewed by legislators and regulators. Numerous departments and
agencies, both federal and state, are authorized by statute to
issue, and have issued, rules and regulations binding upon the
oil and natural gas industry and its individual members.
The Federal Energy Regulatory Commission (FERC)
regulates the transportation and sale for resale of natural gas
in interstate commerce pursuant to the Natural Gas Act of 1938
(the NGA) and the Natural Gas Policy Act of 1978
(the NGPA). FERC regulates interstate oil pipelines
under the provisions of the Interstate Commerce Act
(ICA) as in effect in 1977 when ICA jurisdiction
over oil pipelines was transferred to FERC, and the Energy
Policy Act of 1992 (EPAct 1992). FERC is also
authorized to prevent and sanction market manipulation in
natural gas markets under the Energy Policy Act of 2005
(EPAct 2005) and to maintain oversight of public
utility holding companies under the Public Utility Holding
Company Act of 2005 (PUHCA). In 1989, Congress
enacted the Natural Gas Wellhead Decontrol Act, which removed
all remaining price and nonprice controls affecting wellhead
sales of natural gas, effective January 1, 1993. While
sales by producers of natural gas and all sales of crude oil,
condensate and natural gas liquids can currently be made at
uncontrolled market prices, Congress could reenact price
controls in the future.
In addition, the Federal Trade Commission (FTC), and
the CFTC hold statutory authority to prevent market manipulation
in oil and energy futures markets, respectively. Together with
FERC, these agencies have imposed broad rules and regulations
prohibiting fraud and manipulation in oil and gas markets and
energy futures markets. We are also subject to various reporting
requirements that are designed to facilitate transparency and
prevent market manipulation. Failure to comply with such market
rules, regulations and requirements could have a material
adverse effect on our business, results of operations, and
financial condition.
Oil and NGLs Transportation Rates
Our sales of crude oil, condensate and NGLs are not currently
regulated and are transacted at market prices. In a number of
instances, however, the ability to transport and sell such
products is dependent on pipelines whose rates, terms and
conditions of service are subject to FERC jurisdiction under the
ICA and EPAct 1992. The price we receive from the sale of oil
and NGLs is affected by the cost of transporting those products
to market. Interstate transportation rates for oil, natural gas
liquids, and other products are regulated by the FERC, and in
general,
125
these rates must be cost-based or based on rates in effect in
1992, although FERC has established an indexing system for such
transportation which allows such pipelines to take an annual
inflation-based rate increase. Shippers may, however, contest
rates that do not reflect costs of service. FERC has also
established market-based rates and settlement rates as
alternative forms of ratemaking in certain circumstances.
In other instances involving intrastate-only transportation of
oil, NGLs, and other products, the ability to transport and sell
such products is dependent on pipelines whose rates, terms and
conditions of service are subject to regulation by state
regulatory bodies under state statutes. Such pipelines may be
subject to regulation by state regulatory agencies with respect
to safety, rates
and/or terms
and conditions of service, including requirements for ratable
takes or non-discriminatory access to pipeline services. The
basis for intrastate regulation and the degree of regulatory
oversight and scrutiny given to intrastate pipelines varies from
state to state. Many states operate on a complaint-based system
and state commissions have generally not initiated
investigations of the rates or practices of liquids pipelines in
the absence of a complaint.
Regulation of Oil and Natural Gas Exploration and
Production
Our exploration and production operations are subject to various
types of regulation at the federal, state and local levels. Such
regulations include requiring permits, bonds and pollution
liability insurance for the drilling of wells, regulating the
location of wells, the method of drilling, casing, operating,
plugging and abandoning wells, notice to surface owners and
other third parties, and governing the surface use and
restoration of properties upon which wells are drilled. Many
states also have statutes or regulations addressing conservation
of oil and gas resources, including provisions for the
unitization or pooling of oil and natural gas properties, the
establishment of maximum rates of production from oil and
natural gas wells and the regulation of spacing of such wells.
Oklahoma (where most of our properties are currently located),
allows forced pooling or integration of tracts to facilitate
exploration, while other states rely on voluntary pooling of
lands and leases. In some instances, forced pooling or
unitization may be implemented by third parties and may reduce
our interest in the unitized properties. In addition, state
conservation laws establish maximum rates of production from oil
wells, generally prohibit the venting or flaring of natural gas
and impose requirements regarding the ratability of production.
These laws and regulations may limit the amount of oil we can
produce from our wells or limit the number of wells or the
locations at which we can drill.
States also impose severance taxes and enforce requirements for
obtaining drilling permits. For example, the State of Oklahoma,
where most of our properties are located, currently imposes a
production tax of 7.2% for oil and natural gas properties and an
excise tax of 0.095%. A portion of our wells in the State of
Oklahoma currently receive a reduced production tax rate due to
the Enhanced Recovery Project Gross Production Tax Exemption.
Additionally, production tax rates vary by state. States do not
regulate wellhead prices or engage in other similar direct
economic regulation, but there can be no assurance that they
will not do so in the future.
In 2011, there were numerous new and proposed regulations
related to oil and gas exploration and production activities.
The failure to comply with these rules and regulations can
result in substantial penalties. Our competitors in the oil and
natural gas industry are subject to the same regulatory
requirements and restrictions that affect our operations.
Pipeline Safety and Maintenance
Pipelines, gathering systems and terminal operations are subject
to increasingly strict safety laws and regulations. Both the
transportation and storage of refined products and crude oil
involve a risk that hazardous liquids may be released into the
environment, potentially causing harm to the public or the
environment. In turn, such incidents may result in substantial
expenditures for response actions, significant government
penalties, liability to government agencies for natural
resources damages, and significant business interruption. The
126
U.S. Department of Transportation (DOT) has
adopted safety regulations with respect to the design,
construction, operation, maintenance, inspection and management
of our pipeline and storage facilities. These regulations
contain requirements for the development and implementation of
pipeline integrity management programs, which include the
inspection and testing of pipelines and the correction of
anomalies. These regulations also require that pipeline
operation and maintenance personnel meet certain qualifications
and that pipeline operators develop comprehensive spill response
plans. States may also impose additional or more stringent
safety standards on pipelines.
There have been recent initiatives to strengthen and expand
pipeline safety regulations and to increase penalties for
violations. Legislation has passed the United States Senate and
is pending in the United States House of Representatives that
would impose additional safety requirements on oil and natural
gas pipelines. These additional safety requirements could have a
material effect on our operations. In addition, recent
regulatory initiatives undertaken by DOT could impose additional
safety requirements, which could result in a material increase
in transportation costs for oil and natural gas. However, it is
unlikely that these pending statutory and regulatory measures
would disproportionately affect our operations in comparison to
the rest of the industry.
Legislation continues to be introduced in U.S. Congress,
and the development of regulations continues in the Department
of Homeland Security and other agencies concerning the security
of industrial facilities, including oil and natural gas
facilities. Our operations may be subject to such laws and
regulations. Presently, we do not believe that compliance with
these laws will have a material adverse impact on us.
The oil and natural gas industry is also subject to compliance
with various other federal, state and local regulations and
laws. Some of those laws relate to resource conservation and
equal employment opportunity. We do not believe that compliance
with these laws will have a material adverse effect on us.
Employees
The officers of our general partner will manage our operations
and activities. However, neither we, our subsidiary, nor our
general partner have employees. In connection with the closing
of this offering, our general partner will enter into a services
agreement with Mid-Con Energy Operating pursuant to which
Mid-Con Energy Operating will perform services for us, including
the operation of our properties. Please read Certain
Relationships and Related Party Transactions Agreements
Governing the TransactionsServices Agreement.
Immediately after the closing of this offering, we expect that
Mid-Con Energy Operating will have approximately
60 employees performing services for our operations and
activities. We believe that Mid-Con Energy Operating has a
satisfactory relationship with those employees.
Offices
Our headquarters are located at 2501 North Harwood Street, Suite
2410, Dallas, Texas 75201, with approximately 4,000 square feet
of office space under lease. Our lease expires in 2016. For our
principal operating office, we currently lease approximately
10,000 square feet of office space in Tulsa, Oklahoma at
2431 East 61st Street, Suite 850, Tulsa, Oklahoma
74136. Our lease expires in June 2012.
Legal
Proceedings
Although we may, from time to time, be involved in litigation
and claims arising out of our operations in the normal course of
business, we are not currently a party to any material legal
proceedings. In addition, we are not aware of any significant
legal or governmental proceedings against us, or contemplated to
be brought against us, under the various environmental
protection statutes to which we are subject.
127
MANAGEMENT
Management
of Mid-Con Energy Partners, LP
Our general partner will manage our operations and activities on
our behalf through its executive officers and board of
directors. References in this prospectus to our officers and
board of directors therefore refer to the officers and board of
directors of our general partner. Our general partner is owned
and controlled by the Founders.
Our general partner is not elected by our unitholders and will
not be subject to re-election on an annual or other continuing
basis in the future. In addition, our unitholders will not be
entitled to elect the directors of our general partner, each of
whom will be appointed by the Founders, or directly or
indirectly participate in our management or operations. Further,
our partnership agreement contains provisions that substantially
restrict the fiduciary duties that our general partner would
otherwise owe to our unitholders under Delaware law. Please read
Conflicts of Interest and Fiduciary DutiesFiduciary
Duties.
Upon the closing of this offering, we expect that the board of
directors of our general partner will have seven members. The
NASDAQ listing rules do not require a listed limited partnership
like us to have a majority of independent directors on the board
of directors of our general partner or to establish a
compensation committee or a nominating and corporate governance
committee. We are, however, required to have an audit committee
of at least three members, all of whom are required to meet the
independence and experience standards established by the NASDAQ
listing rules and SEC rules. Please see Director
Independence and Committees of the Board of
Directors below.
All of the executive officers of our general partner are also
officers
and/or
directors of the
Mid-Con
Affiliates. The executive officers of our general partner will
allocate their time between managing our business and affairs
and the business and affairs of the Mid-Con Affiliates. In
addition, employees of Mid-Con Energy Operating will provide
management, administrative and operational services to us
pursuant to the services agreement, but they will also provide
these services to the
Mid-Con
Affiliates. Please see Certain Relationships and Related
Party TransactionsAgreements Governing the
TransactionsServices Agreement. We expect the
executive officers of our general partner and other shared
personnel to devote a sufficient amount of time to our business
and affairs as is necessary for the proper management and
conduct of our business and operations. However, we anticipate
that, for the foreseeable future, the executive officers of our
general partner and other shared personnel will also devote
substantial amounts of their time to managing the businesses of
the Mid-Con Affiliates.
Directors
and Executive Officers of Mid-Con Energy GP, LLC
The following table sets forth certain information regarding the
current directors and executive officers of our general partner
upon consummation of this offering.
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position with Mid-Con Energy GP, LLC
|
|
S. Craig George
|
|
|
59
|
|
|
Executive Chairman of the Board
|
Charles R. Randy Olmstead
|
|
|
63
|
|
|
Chief Executive Officer and Director
|
Jeffrey R. Olmstead
|
|
|
34
|
|
|
President, Chief Financial Officer and Director
|
David A. Culbertson
|
|
|
46
|
|
|
Vice President and Chief Accounting Officer
|
Robbin W. Jones
|
|
|
53
|
|
|
Vice President and Chief Engineer
|
Peter A. Leidel
|
|
|
55
|
|
|
Director
|
Cameron O. Smith
|
|
|
61
|
|
|
Director
|
Robert W. Berry
|
|
|
87
|
|
|
Director
|
Peter Adamson III
|
|
|
70
|
|
|
Director
|
128
The members of our general partners Board of Directors are
appointed for one-year terms by the Founders and hold office
until the earlier of their death, resignation, removal or
disqualification or until their successors have been appointed
and qualified. The executive officers of our general partner
serve at the discretion of the board of directors. All of our
general partners executive officers also serve as
executive officers of the Mid-Con Affiliates. Charles R.
Olmstead and Jeffrey R. Olmstead are father and son,
respectively. There are no other family relationships among our
general partners executive officers and directors. In
evaluating director candidates, the Founders will assess whether
a candidate possesses the integrity, judgment, knowledge,
experience, skill and expertise that are likely to enhance the
ability of the board of directors to manage and direct our
affairs and business, including, when applicable, to enhance the
ability of the committees of the board to fulfill their duties.
While the Founders may consider diversity among other factors
when considering director nominees, they do not apply any
specific diversity policy with regard to selecting and
appointing directors to the board of directors. However, when
appointing new directors, the Founders will consider each
individual directors qualifications, skills, business
experience and capacity to serve as a director, and the
diversity of these attributes for the board of directors as a
whole.
S. Craig George will serve as Executive Chairman of the
board of directors of our general partner. Mr. George has
been a member of the board of directors of Mid-Con Energy III,
LLC, Mid-Con
Energy IV, LLC and
Mid-Con
Energy Operating since June 2011. Mr. George has been a
member of the board of directors of Mid-Con Energy I, LLC
and Mid-Con Energy Operating since its formation in 2004 and of
Mid-Con Energy II, LLC since its formation in 2009. From 1991 to
2004, Mr. George served in various executive positions at
Vintage Petroleum, Inc., including President, Chief Executive
Officer and as a member of the board of directors. In 1981,
Mr. George joined Santa Fe Minerals, Inc. where he
served until 1991 in executive positions including Vice
President of Domestic Operations and Vice
President-International. From
1975-1981,
Mr. George held engineering and management positions with
Amoco Production Company. Mr. George is a graduate of
Missouri University of Science and Technology, with a Bachelor
of Science degree in Mechanical Engineering, and of Aquinas
Institute, with a Master of Arts in Theology. We believe that
Mr. Georges service as the chief executive officer
and a director of a publicly traded exploration and production
company brings important experience and leadership skill to the
board of directors of our general partner.
Charles R. Randy Olmstead will serve as Chief
Executive Officer and as a member of the board of directors of
our general partner. Mr. Olmstead has been Chief Executive
Officer and Chairman of the board of directors of Mid-Con Energy
III, LLC and Mid-Con Energy IV, LLC since June 2011.
Mr. Olmstead has served as President, Chief Financial
Officer and Chairman of the board of directors of Mid-Con
Energy I, LLC since its formation in 2004 and of Mid-Con
Energy II, LLC since its formation in 2009. He has been
President, Chief Financial Officer and Chairman of the board of
directors of Mid-Con Energy Operating since its incorporation in
1986. Prior to that, Mr. Olmstead was general manager for
LB Jackson Drilling Company from 1978 to 1980 and worked in
public accounting for Touche Ross & Co. from 1974 to
1978 as an oil and gas tax consultant. Mr. Olmstead is a
certified public accountant. Mr. Olmstead graduated from
the University of Oklahoma with Bachelors of Business
Administration degrees in finance and accounting before serving
three years in the US Navy. We believe that
Mr. Olmsteads extensive experience in the oil and gas
industry brings important experience and leadership skill to the
board of directors of our general partner.
Jeffrey R. Olmstead will serve as President, Chief
Financial Officer and as a member of the board of directors of
our general partner. Mr. Olmstead has been a member of the
board of directors of
Mid-Con
Energy III, LLC and President, Chief Financial Officer and
a member of the board of directors of Mid-Con Energy IV, LLC
since June 2011. Mr. Olmstead has been a member of the
board of directors of Mid-Con Energy I, LLC and
Mid-Con
Energy Operating since 2007 and of Mid-Con Energy II, LLC since
its formation. Mr. Olmstead previously served as Chief
129
Financial Officer and Vice President of Primexx Energy Partners,
Ltd., a privately held exploration and production company, from
May 2010 until July 2011. From August 2006 until May 2010,
Mr. Olmstead served as an Assistant Vice President at Bank
of Texas/Bank of Oklahoma where, in the banks energy
group, he managed a portfolio of approximately 20 oil and gas
borrowers with total commitments of approximately
$250 million. Mr. Olmstead is a graduate of Vanderbilt
University, with a Bachelor of Engineering degree in Electrical
Engineering and Math, and of the Owen School of Business at
Vanderbilt University, with a Master of Business Administration.
We believe that Mr. Olmsteads experience in
energy-related finance brings important experience and
leadership skill to the board of directors of our general
partner.
David A. Culbertson will serve as Vice President and
Chief Accounting Officer of our general partner.
Mr. Culbertson has served as Controller of Mid-Con
Energy I, LLC since 2006 and of
Mid-Con
Energy II, LLC since its formation in 2009. He has also
supervised the accounting function for affiliates of our
predecessor. Prior to joining us in 2006, Mr. Culbertson
served in various accounting positions with Vintage Petroleum
from
2003-2006,
The Williams Companies from
1999-2003
and Samson Resources from
1989-1999.
Mr. Culbertson is a graduate of Oklahoma State University,
with a Bachelor of Business Administration degree in accounting,
and of the University of Tulsa, with a Master of Business
Administration. He is a Certified Public Accountant.
Robbin W. Jones, P.E. will serve as Vice President and
Chief Engineer of the General Partner. Mr. Jones was
elected President of Mid-Con Energy III, LLC in June 2011.
Mr. Jones has been a Vice President and Chief Operating
Officer of the predecessor and affiliate companies since 2007.
Mr. Jones served as reservoir engineer and manager of our
Houston office from March 2005, when he joined our predecessor,
until 2007. Mr. Jones served as manager at Schlumberger
Data & Consulting Services from 2004 to 2005 and has
twenty years of engineering experience in all phases of
waterflood development and management working for Enserch
Exploration, Caruthers Producing, Diamond Energy Operating
Company and Equinox Oil Company. Mr. Jones received a
Bachelor of Science degree in Petroleum Engineering from the
University of Tulsa. He is a Registered Professional Engineer in
the states of Louisiana and Texas and a member of the Society of
Petroleum Engineers.
Peter A. Leidel will serve as a member of the board of
directors of our general partner. Mr. Leidel is a founder
and principal of Yorktown Partners LLC, which was established in
September 1990. Yorktown Partners LLC is the manager of private
investment partnerships that invest in the energy industry.
Mr. Leidel has been a member of the board of directors of
Mid-Con
Energy III, LLC,
Mid-Con
Energy IV, LLC and
Mid-Con
Energy Operating since June 2011. Mr. Leidel has been a
member of the board of directors of
Mid-Con
Energy I, LLC since its formation in 2004 and of
Mid-Con
Energy II, LLC since its formation in 2009. Previously, he
was a partner of Dillon, Read & Co. Inc., held
corporate treasury positions at Mobil Corporation and worked for
KPMG and for the U.S. Patent and Trademark Office.
Mr. Leidel is a director of certain non-public companies in
the energy industry in which Yorktown holds equity interests.
Mr. Leidel is a graduate of the University of Wisconsin,
with a Bachelor of Business Administration degree in accounting
and of the Wharton School at the University of Pennsylvania,
with a Master of Business Administration. We believe that
Mr. Leidels extensive financial and private
investment experience, as well as his experience on the boards
of directors of numerous public and private companies (including
prior service as the chairman of the audit committies of two
public companies), bring substantial leadership skill and
experience to the board of directors.
Cameron O. Smith will serve as a member of the board of
directors of our general partner. Mr. Smith founded and
from 1992 to 2008, served as a Senior Managing Director of COSCO
Capital Management LLC, an investment bank focused on private
oil and gas corporate and project financing until
Rodman & Renshaw, LLC, a full service investment bank,
purchased the business and assets of COSCO Capital Management
LLC. From 2008 until December 2009, Mr. Smith served as a
Senior Managing Director of Rodman & Renshaw, LLC and
as Head of The Rodman Energy Group, a sector vertical within
Rodman & Renshaw, LLC. Mr. Smith retired
130
from The Rodman Energy Group in December 2009. Mr. Smith
founded and ran Taconic Petroleum Corporation, an exploration
company headquartered in Tulsa, Oklahoma from 1978 to 1991.
Mr. Smith served as exploration geologist, officer and
director of several private family and public client companies
from 1975 to 1985. Mr. Smith attended Princeton University
receiving an A.B. in Art History in 1972 and Pennsylvania State
University receiving a Master of Science in Geology in 1975. We
believe that Mr. Smiths extensive financial and
private equity experience, as well as his experience in the oil
and natural gas industry generally, bring substantial leadership
skill and experience to the board of directors.
Robert W. Berry will serve as a member of the board of
directors of our general partner. Mr. Berry is founder,
Chief Executive Officer and President of Robert W. Berry, Inc.,
Empress Gas Corp. Ltd., R.W. Berry Canada, Inc. and Berry
Ventures, Inc. which produce oil and gas in Oklahoma, Texas,
Arkansas, North Dakota and Canada, and has served in these
positions for more than the past five years. Mr. Berry
has drilled and discovered numerous oil fields in Texas, North
Dakota and Canada since working for Amerada Petroleum
Corporation as a geologist. Mr. Berry graduated from the
University of Oklahoma with a Bachelor of Science degree in
Geology. We believe that Mr. Berrys extensive
experience in the oil and gas industry brings substantial
leadership skill and experience to the board of directors of our
general partner.
Peter Adamson III will serve as a member of the
board of directors of our general partner. Mr. Adamson is a
founder of Adams Hall Asset Management LLC, a Tulsa, Oklahoma
based registered investment advisor with over $1 billion
under management. Prior to forming Adams Hall in 1997,
Mr. Adamson was an owner and principal of Houchin,
Adamson & Co., Inc., a registered broker-dealer formed
in 1980. Mr. Adamson is founding co-investor and advisor to
Horizon Well Logging, a leading provider of geological field
services. Mr. Adamson serves on the advisory board of the
Michel F. Price College of Business at the University of
Oklahoma and serves on the University of Oklahoma asset
oversight committee. Mr. Adamson received his Bachelor of
Business Administration degree in accounting from the University
of Oklahoma. We believe that Mr. Adamsons extensive
financial and investing experience bring substantial leadership
skill and experience to the board of directors.
Reimbursement
of Expenses of Our General Partner
Our partnership agreement requires us to reimburse our general
partner for all direct and indirect expenses it incurs or
payments it makes on our behalf and all other expenses allocable
to us or otherwise incurred by our general partner in connection
with operating our business. Our partnership agreement does not
set a limit on the amount of expenses for which our general
partner and its affiliates, including Mid-Con Energy Operating,
may be reimbursed. Our partnership agreement provides that our
general partner will determine in good faith the expenses that
are allocable to us.
Upon the closing of this offering, we will enter into a services
agreement with Mid-Con Energy Operating pursuant to which
Mid-Con Energy Operating will provide management, administrative
and operational services to us. We will reimburse Mid-Con Energy
Operating, on a monthly basis, for the allocable expenses it
incurs in its performance under the services agreement. These
expenses include, among other things, salary, bonus, incentive
compensation and other amounts paid to persons who perform
services for us or on our behalf and other expenses allocated to
us. Mid-Con Energy Operating will have substantial discretion to
determine in good faith which expenses to incur on our behalf
and what portion to allocate to us. Please read Certain
Relationships and Related Party TransactionsAgreements
with Affiliates in Connection with the Transactions. For
further discussion of the reimbursements that Mid-Con Energy
Operating will be entitled to receive relating to services
provided in connection with the services agreement, please read
Certain Relationships and Related Party
TransactionsAgreements with Affiliates in Connection with
the TransactionsServices Agreement.
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Director
Independence
Messrs. Berry, Smith and Adamson meet the independence
standards established by the NASDAQ listing rules.
Committees
of the Board of Directors
The board of directors of our general partner will have an audit
committee and a conflicts committee. We do not expect that we
will have a compensation committee, but rather that our board of
directors or an appointed committee will approve equity grants
to directors and employees. As noted above, the NASDAQ listing
rules do not require a listed limited partnership to establish a
compensation committee or a nominating and corporate governance
committee.
Audit Committee
We are required to have an audit committee of at least three
members, and all its members are required to meet the
independence and experience standards established by the NASDAQ
listing rules and rules of the SEC. The audit committee will
assist the board of directors in its oversight of the integrity
of our financial statements and our compliance with legal and
regulatory requirements and partnership policies and controls.
The audit committee will have the sole authority to
(1) retain and terminate our independent registered public
accounting firm, (2) approve all auditing services and
related fees and the terms thereof performed by our independent
registered public accounting firm and (3) pre-approve any
non-audit services and tax services to be rendered by our
independent registered public accounting firm. The audit
committee will also be responsible for confirming the
independence and objectivity of our independent registered
public accounting firm. Our independent registered public
accounting firm will be given unrestricted access to the audit
committee and our management, as necessary. Initially,
Messrs. Berry, Smith and Adamson will serve on the audit
committee.
Conflicts Committee
Our partnership agreement requires that at least two independent
members of the board of directors of our general partner will
serve on a conflicts committee to review specific matters that
the board of directors believes may involve conflicts of
interest (including certain transactions with affiliates of our
general partner, including the Mid-Con Affiliates) and that it
determines to submit to the conflicts committee for review. We
expect that additional independent directors will serve on the
conflicts committee as they are appointed. Our general partner
may, but is not required to, seek approval from the conflicts
committee of a resolution of a conflict of interest with our
general partner or affiliates. The members of the conflicts
committee may not be officers or employees of our general
partner or directors, officers or employees of its affiliates,
including the Mid-Con Affiliates or holders of any ownership
interest in our general partner or any of its affiliates, other
than common units or securities exercisable, convertible into or
exchangeable for common units, and must meet the independence
standards established by the NASDAQ listing rules and the
Securities Exchange Act of 1934 to serve on an audit committee
of a board of directors, and certain other requirements. Any
matters approved by the conflicts committee will be conclusively
deemed to have been approved in good faith. In addition, any
such matters will be deemed to be approved by all of our
partners and not constitute a breach of our partnership
agreement or of any duties our general partner may owe us or our
unitholders. Please read Conflicts of Interest and
Fiduciary DutiesConflicts of Interest. Initially,
Messrs. Berry, Smith and Adamson will serve on the
conflicts committee.
Board Leadership Structure and Role in Risk
Oversight
Leadership of our general partners board of directors is
vested in a Chairman of the Board. Although our Chief Executive
Officer currently does not serve as Chairman of the Board of
Directors of our general partner, we currently have no policy
prohibiting our current or any future chief executive officer
from serving as Chairman of the Board. The board of directors,
in
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recognizing the importance of its ability to operate
independently, determined that separating the roles of Chairman
of the Board and Chief Executive Officer is advantageous for us
and our unitholders. Our general partners board of
directors has also determined that having the Chief Executive
Officer serve as a director could enhance understanding and
communication between management and the board of directors,
allows for better comprehension and evaluation of our
operations, and ultimately improves the ability of the board of
directors to perform its oversight role.
The management of enterprise-level risk may be defined as the
process of identification, management and monitoring of events
that present opportunities and risks with respect to the
creation of value for our unitholders. The board of directors of
our general partner has delegated to management the primary
responsibility for enterprise-level risk management, while
retaining responsibility for oversight of our executive officers
in that regard. Our executive officers will offer an
enterprise-level risk assessment to the board of directors at
least once every year.
Compensation
of Executive Officers
We and our general partner were formed in July 2011. As such,
neither we nor our general partner accrued any obligations with
respect to compensation for directors and executive officers for
the fiscal year ended December 31, 2010, or for any prior
periods. Accordingly, we are not presenting any compensation for
historical periods. We have not paid or accrued any amounts for
compensation for directors and executive officers for the 2010
fiscal year.
The executive officers of our general partner are also executive
officers
and/or
directors of the Mid-Con Affiliates. We expect these executive
officers to devote a sufficient amount of time to our business
and affairs as is necessary for the proper management and
conduct of our business and operations. However, we anticipate
that these executive officers will devote substantial amounts of
time to managing the businesses of the Mid-Con Affiliates. We
expect that the executive officers of our general partner will
devote their business time to our business as follows: S. Craig
George, Charles R. Olmstead, Jeffrey R. Olmstead, David A.
Culbertson and Robbin W. Jones will devote approximately 80%,
662/3%,
80%,
662/3%
and 50% of their business time, respectively. The amount of time
that each of our executive officers devotes to our business will
be subject to change depending on our activities, the activities
of the Mid-Con Affiliates to which they also provide services,
and any acquisitions or dispositions made by us or the Mid-Con
Affiliates.
Our general partner will enter into employment agreements with
each of the following named employees of our general partner:
Charles R. Olmstead, Chief Executive Officer; Jeffrey R.
Olmstead, President and Chief Financial Officer; and S. Craig
George, Executive Chairman of the Board of our general partner.
The employment agreements provide for a term that commenced on
August 1, 2011 and expires on August 1, 2014, unless
earlier terminated, with automatic one-year renewal terms unless
either we or the employee gives written notice of termination at
least by February 1 preceding any such August 1. Pursuant
to the employment agreements, each employee will serve in his
respective position with our general partner, as set forth
above, and will have duties, responsibilities, and authority as
the board of directors of our general partner may specify from
time to time, in roles consistent with such positions that are
assigned to him.
The annual base salaries for each employee will be subject to
possible increases through the normal salary review process. In
addition, each employee will continue to be eligible (i) to
participate in our short term incentive plan which is paid as an
annual cash bonus based on the attainment of certain performance
criteria established by the board of our general partner and
(ii) to receive awards under our long-term incentive
program.
The performance criteria for the short-term incentive plan for
2011 include 50% of the target bonus earned upon the successful
completion of this offering and 50% earned upon successful
133
completion of the requirements allowing common units issued to
the Founders in conjunction with this offering that will
initially be restricted from trading to no longer be so
restricted. The performance criteria for the short-term
incentive plan for 2012 and future years include 50% of the
target bonus earned for meeting initial quarterly distribution
goals, 20% earned for generating an increase in the amount of
distributions from the preceding year, 20% earned for generating
additions of new reserves and growth of distributions based on
aggregate acquisitions of 10% growth, and 10% earned for overall
performance as determined by our board. The performance criteria
for earning awards under the long-term incentive program for
2011 and 2012 and later years are the same as the respective
criteria under the short-term incentive plan.
The employment agreements provide that if, during the employment
period, the employees employment is terminated without
cause or by the employee with good
reason (each as defined in the employment agreements), the
employee will be entitled to a lump-sum cash payment equal to
the employees earned but unpaid base salary, accrued but
unpaid vacation pay, any unreimbursed business expenses and any
accrued benefits. Additionally, if the employees
employment is terminated without cause or by the
employee with good reason, and subject to the
employees execution and non-revocation of a general
release of claims, or if we elect not to renew the employment
period and the employee is still willing and able to continue
employment, the employee will be entitled to the following:
(i) payment of his base salary, as in effect immediately
prior to his termination, multiplied by the greater of the
number of years remaining in the employment period and one;
(ii) a lump sum payment to compensate the employee for
COBRA health-care coverage for the employee and the
employees dependents (if applicable);
(iii) accelerated vesting and conversion of any units which
may have been awarded to the employee through our long-term
incentive program; (iv) payment of an amount equal to the
lesser of the target annual bonus (as defined in the
employment agreements) and the average of the previous two
annual bonuses paid to the employee multiplied by the greater of
the number of years remaining in the employment period and one;
and (v) the payment of any unpaid annual bonus that would
have become payable to the employee in respect of any calendar
year that ends on or before the date of termination had the
employee remained employed throughout the payment date of such
annual bonus.
In addition, if, during the period beginning sixty days prior to
and ending two years immediately following a change in
control (as defined in the employment agreements), either
we terminate the employees employment without cause, the
employees death occurs, the employee becomes disabled or
the employee terminates his employment for good reason, then the
employee will be entitled to the severance payments and benefits
described in the preceding paragraph, except that the severance
multiple described in clauses (i) and (iv) will be
equal to two (instead of the greater of the number of years
remaining in the employment period and one). If a change in
control occurs during the employment period, certain
equity-based awards held by the employees, to the extent not
previously vested and converted into common units, will vest in
full upon such change in control and will be settled in common
units in accordance with the applicable award agreements.
The employment agreements provide that if an employees
employment terminates due to his death or disability during the
employment period, the employee or the employees estate
will be entitled to the payment of a lump-sum cash payment equal
to the employees earned but unpaid base salary, accrued
but unpaid vacation pay, any unreimbursed business expenses, and
any accrued benefits. Additionally, subject to the
employees or the employees estates execution
and non-revocation of a general release of claims, the employee
or the employees estate will be entitled to receive:
(i) accelerated vesting and conversion of any units which
may have been awarded to the employee through our long-term
incentive program, in accordance with the terms of the
applicable award agreement; (ii) a lump sum payment to
compensate the employee or the employees estate for COBRA
health-care coverage for the employee (if living) and the
employees dependents (if applicable); (iii) a payment
equal to the product of the employees base salary as in
effect
134
immediately prior to the date of his termination multiplied by
one; (iv) the payment of any unpaid annual bonus that would
have become payable to the employee in respect of any calendar
year that ends on or before the date of termination had the
employee remained employed through the payment date of such
annual bonus; and (v) the payment of the target annual
bonus for the year in which the employees separation from
service occurs.
The employment agreements also provide for customary
confidentiality, non-solicitation, non-compete and
indemnification protections. The non-solicitation provisions
prohibit an executive from soliciting persons to leave our
employment who are employed by us within six months before or
after the executives termination. This restriction
continues during the term of and for twelve months following
termination of the executives employment, and also for
twelve months following the termination of the solicited
employees employment. The non-solicitation provisions also
prohibit an executive from soliciting our customers during the
term of and for twelve months following termination of the
executives employment. The non-competition provisions
prohibit the executive from competing with us during the term of
the executives employment and for a period during which
severance payments are being made to the executive, which by the
terms of the agreements may be up to two years after the
executives separation of employment.
The above summary of the terms of the employment agreements with
each of the employees named above is qualified in its entirety
by reference to the employment agreements themselves.
Because the executive officers of our general partner are
employees of Mid-Con Energy Operating, their compensation will
be paid by Mid-Con Energy Operating and we will reimburse
Mid-Con Energy Operating pursuant to the services agreement for
the portion of such compensation allocable to us. Please see
Certain Relationships and Related Party
TransactionsAgreements with Affiliates in Connection with
the TransactionsServices Agreement.
The executive officers of our general partner, as well as the
employees of Mid-Con Energy Operating who provide services to
us, may participate in employee benefit plans and arrangements
sponsored by Mid-Con Energy Operating, including plans that may
be established in the future.
We anticipate that, following the closing of this offering, our
general partner will adopt a long-term incentive program and the
board of directors of our general partner may grant awards to
our executive officers, key employees and our outside directors
pursuant to this long-term incentive program. However, the board
has not made any determination as to the number of awards, the
type of awards or whether or when any awards would be granted.
The long-term incentive program is described in further detail
below.
Compensation Committee Interlocks and Insider
Participation
The NASDAQ listing rules do not require a listed limited
partnership to establish a compensation committee. Although the
board of directors of our general partner does not currently
intend to establish a compensation committee, it may do so in
the future.
Compensation
Discussion and Analysis
General
We do not directly employ any of the persons responsible for
managing our business. Our general partners executive
officers will manage and operate our business as part of the
services provided by Mid-Con Energy Operating to our general
partner under the services agreement. All of our general
partners executive officers and other employees necessary
to operate our business will be employed and compensated by
Mid-Con Energy Operating, subject to reimbursement by our
general partner. The compensation for all of our executive
officers will be indirectly paid by us to the extent provided
for in the partnership agreement because we will reimburse our
general partner for payments it makes to Mid-Con Energy
Operating. Please see Certain Relationships
135
and Related Party TransactionsAgreements with Affiliates
in Connection with the TransactionsServices
Agreement and Reimbursement of Expenses of Our
General Partner.
We and our general partner were formed in July 2011; therefore,
we incurred no cost or liability with respect to the
compensation of our executive officers, nor has our general
partner accrued any liabilities for management incentive or
retirement benefits for our executive officers for the fiscal
year ended December 31, 2010 or for any prior periods.
Accordingly, we are not presenting any compensation information
for historical periods.
The Founders, as the controlling members of our general partner,
will have responsibility and authority for compensation-related
decisions for our Chief Executive Officer and, upon consultation
and recommendations by our Chief Executive Officer, for our
other executive officers. Equity grants pursuant to our
long-term incentive program will also be administered by the
Founders. Our predecessor historically compensated its executive
officers primarily with base salary and cash bonuses.
In connection with this offering, the Founders may consider the
compensation structures and levels that they believe will be
necessary for executive recruitment and retention for us as a
public company. The Founders expect to examine the compensation
practices of our peer companies and may also review compensation
data from the exploration and production industry generally.
Our general partner may also grant equity-based awards to our
executive officers pursuant to a long-term incentive program
which our general partner intends to adopt as described below.
However, no determination has been made as to the number of
awards, the type of awards or whether or when any awards would
be granted under this program. We expect that annual bonuses
payable to our executive officers will be determined based on
our financial performance as measured across a fiscal year.
However, incentive compensation in respect of services provided
to us will not be tied in any way to the performance of entities
other than our partnership. Specifically, any performance
metrics will not be tied in any way to the performance of the
Mid-Con Affiliates or any other affiliate of ours.
Although we will bear an allocated portion of Mid-Con Energy
Operatings costs of providing compensation and benefits to
Mid-Con Energy Operating employees who serve as the executive
officers of our general partner and provide services to us, we
will have no control over such costs and will not establish or
direct the compensation policies or practices of Mid-Con Energy
Operating. Mr. Charles R. Olmstead previously made all
compensation related-decisions for Mid-Con Energy Operating.
Mr. Olmstead determined the overall compensation philosophy
and set the final compensation of the executive officers of our
predecessors without the assistance of a compensation
consultant. Mr. Olmstead will continue to make all
compensation-related decisions for those Mid-Con Energy
Operating employees who do not perform services for us.
Mid-Con Energy Operating does not maintain a defined benefit or
pension plan for its executive officers or employees because it
believes such plans primarily reward longevity rather than
performance. Mid-Con Energy Operating provides a basic benefits
package to all its employees, which includes a 401(k) plan and
health, and basic term life insurance, and personal accident and
short and long-term disability coverage. Employees provided to
us under the services agreement will be entitled to the same
basic benefits.
Awards under Our Long-Term Incentive Program
In connection with this offering, the board of directors of our
general partner intends to adopt a long-term incentive program
for employees, officers, consultants and directors of our
general partner and affiliates, including Mid-Con Energy
Operating, who perform services for us. The long-term incentive
program will provide for the grant of restricted units, phantom
units, unit options, unit appreciation rights, distribution
equivalent rights, other unit-based awards and unit awards as
described below.
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Compensation
of Directors
Officers or employees of our general partner or its affiliates,
including Mid-Con Energy Operating, who also serve as directors
will not receive additional compensation for their service as a
director of our general partner. Our general partner anticipates
that each director who is not an officer or employee of our
general partner or its affiliates will receive an annual
retainer, compensation for attending meetings of the board of
directors, as well as committee meetings and an equity grant
pursuant to our long-term incentive program. The amount of
compensation to be paid to our general partners
non-employee directors has not yet been determined.
In addition, each director will be reimbursed for his
out-of-pocket
expenses in connection with attending meetings of the board of
directors or committees. Each director will be fully indemnified
by us for actions associated with being a director to the extent
permitted under Delaware law.
Long-Term
Incentive Program
Our general partner intends to adopt a long-term incentive
program for employees, officers, consultants and directors of
our general partner and its affiliates, including Mid-Con Energy
Operating, who perform services for us.
The description of the long-term incentive program set forth
below is a summary of the anticipated material features of the
program. This summary, however, does not purport to be a
complete description of all of the anticipated provisions of the
program. Additionally, our general partner is still in the
process of implementing the program and, accordingly, this
summary is subject to change prior to the effectiveness of the
registration statement of which this prospectus is a part.
We expect that the long-term incentive program will consist of
the following components: restricted units, phantom units, unit
options, unit appreciation rights, distribution equivalent
rights, other unit-based awards and unit awards. The purpose of
awards under the long-term incentive program is to provide
additional incentive compensation, at the discretion of the
board, to employees providing services to us, and to align the
economic interests of such employees with the interests of our
unitholders. The long-term incentive program will initially
limit the number of units that may be delivered pursuant to
vested awards to 1,764,000 common units. Common units cancelled,
forfeited or withheld to satisfy exercise prices or tax
withholding obligations will be available for delivery pursuant
to other awards. The program will be administered by the board
of directors of our general partner or a designated committee
thereof, which we refer to as the program administrator. The
program administrator may also delegate its duties as
appropriate.
Amendment or Termination of Long-Term Incentive
Program
The program administrator may terminate or amend the long-term
incentive program at any time with respect to any units for
which a grant has not yet been made. The program administrator
also has the right to alter or amend the long-term incentive
program or any part of the program from time to time, including
increasing the number of units that may be granted subject to
the requirements of the exchange upon which the common units are
listed at that time. However, no change in any outstanding grant
may be made that would materially reduce the rights or benefits
of the participant without the consent of the participant. The
program will expire on the earliest to occur of (i) the
date on which all common units available under the program for
grants have been paid to participants, (ii) termination of
the program by the program administrator or (iii) the date
ten years following its date of adoption.
Restricted Units
A restricted unit is a common unit that vests over a period of
time, and during that time, is subject to forfeiture. Forfeiture
provisions lapse at the end of the vesting period. The program
administrator may make grants of restricted units containing
such terms as it shall determine, including the period over
which restricted units will vest. The program administrator, in
its
137
discretion, may base its determination upon the achievement of
specified financial or other performance objectives. Restricted
units will be entitled to receive quarterly distributions during
the vesting period.
We intend the restricted units under the program to serve as a
means of incentive compensation for performance and not
primarily as an opportunity to participate in the equity
appreciation of our common units. Therefore, it is expected that
program participants will not pay any consideration for
restricted units they receive, and we will receive no
remuneration for the restricted units.
Phantom Units
A phantom unit is a notional common unit that entitles the
grantee to receive a common unit upon the vesting of the phantom
unit or, in the discretion of the program administrator, cash
equivalent to the value of a common unit. The program
administrator may make grants of phantom units under the program
containing such terms as the program administrator shall
determine, including the period over which phantom units granted
will vest. The program administrator, in its discretion, may
base its determination upon the achievement of specified
financial or other performance objectives.
We intend the issuance of any common units upon vesting of the
phantom units under the program to serve as a means of incentive
compensation for performance and not primarily as an opportunity
to participate in the equity appreciation of our common units.
Therefore, it is expected that plan participants will not pay
any consideration for the common units they receive, and we will
receive no remuneration for the common units.
Unit Options
The long-term incentive program will permit the grant of options
covering common units. Unit options represent the right to
purchase a designated number of common units at a specified
price. The program administrator may make grants containing such
terms as the program administrator shall determine. Unit options
will have an exercise price that is not less than the fair
market value of the common units on the date of grant. In
general, unit options granted will become exercisable over a
period determined by the program administrator.
Unit Appreciation Rights
The long-term incentive program will permit the grant of unit
appreciation rights. A unit appreciation right is an award that,
upon exercise, entitles the participant to receive the excess of
the fair market value of a common unit on the exercise date over
the exercise price established for the unit appreciation right.
Such excess will be paid in cash or common units. The program
administrator may make grants of unit appreciation rights
containing such terms as the program administrator shall
determine. Unit appreciation rights will have an exercise price
that is not less than the fair market value of the common units
on the date of grant. In general, unit appreciation rights
granted will become exercisable over a period determined by the
program administrator.
Distribution Equivalent Rights
The program administrator may, in its discretion, grant
distribution equivalent rights, or DERs, in tandem with phantom
unit awards under the long-term incentive program. DERs entitle
the participant to receive an amount in cash, units or phantom
units equal to the amount of any cash distributions made by us
during the period that the phantom unit award is outstanding.
Payment of a DER issued in connection with another award may be
subject to the same or different vesting terms as the award to
which it relates or in the discretion of the program
administrator.
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Other Unit-Based Awards
The long-term incentive program will permit the grant of other
unit-based awards, which are awards that are based, in whole or
in part, on the value or performance of a common unit. Upon
vesting, the award may be paid in common units, cash or a
combination thereof, as provided in the grant agreement.
Unit Awards
The long-term incentive program will permit the grant of common
units that are not subject to vesting restrictions. Unit awards
may be in lieu of or in addition to other compensation payable
to the individual.
Change in Control and Anti-Dilution Adjustments
Upon a change of control (as defined in the
long-term incentive program) , any change in applicable law or
regulation affecting the long-term incentive program or awards
thereunder, or any change in accounting principles affecting the
financial statements of our general partner, the program
administrator, in an attempt to prevent dilution or enlargement
of any benefits available under the long-term incentive program
may, in its discretion, provide that awards will (i) become
exercisable or payable, as applicable, (ii) be exchanged
for cash, (iii) be replaced with other rights or property
selected by the program administrator, (iv) be assumed by
the successor or survivor entity or be exchanged for similar
options, rights or awards covering the equity of such successor
or survivor, or a parent or subsidiary thereof, with other
appropriate adjustments or (v) be terminated. Additionally,
the program administrator may also, in its discretion, make
adjustments to the terms and conditions, vesting and performance
criteria and the number and type of common units, other
securities or property subject to outstanding awards.
Termination of Service
The consequences of the termination of a grantees
employment, consulting arrangement or membership on the board of
directors will be determined by the program administrator in the
terms of the relevant award agreement or employment agreement.
Source of Common Units
Common units to be delivered pursuant to awards under the
long-term incentive program may be common units already owned by
our general partner or us or acquired by our general partner in
the open market from any other person, directly from us or any
combination of the foregoing. If we issue new common units upon
the grant, vesting or payment of awards under the long-term
incentive program, the total number of common units outstanding
will increase, and our general partner will remit the proceeds
it receives from a participant, if any, upon exercise of an
award to us. With respect to any awards settled in cash, our
general partner will be entitled to reimbursement by us for the
amount of the cash settlement.
Relation of Compensation Policies and Practices to Risk
Management
We anticipate that our compensation policies and practices will
be designed to provide rewards for short-term and long-term
performance, both on an individual basis and at the entity
level. In general, optimal financial and operational
performance, particularly in a competitive business, requires
some degree of risk taking. Accordingly, the use of compensation
as an incentive for performance can foster the potential for
management and others to take unnecessary or excessive risks to
reach performance thresholds which qualify them for additional
compensation. From a risk management perspective, our policy
will be to conduct our commercial activities in a manner
intended to control and minimize the potential for unwarranted
risk taking. We expect to also routinely monitor and measure the
execution and performance of our projects and acquisitions
relative to expectations. Additionally, our compensation
arrangements may include delaying the rewards and subjecting
such rewards to forfeiture for terminations related to
violations of our risk management policies and practices or of
our code of conduct.
139
SECURITY
OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the beneficial ownership of our
common units that, upon the consummation of this offering and
the related transactions and assuming the underwriters do not
exercise their option to purchase additional common units, will
be owned by:
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beneficial owners of more than 5% of our common units;
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each executive officer of our general partner; and
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all directors, director nominees and executive officers of our
general partner as a group.
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Percentage of
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Common
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Common Units
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Units to be
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to be
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Beneficially
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Beneficially
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Name of Beneficial Owner(1)
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Owned
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Owned
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Yorktown Energy Partners VI, L.P.(1)(2)
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3,381,660
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19.2
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%
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Yorktown Energy Partners VII, L.P.(1)(3)
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1,690,830
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9.6
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%
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Yorktown Energy Partners VIII, L.P.(1)(4)
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3,914,498
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22.2
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%
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Charles R. Olmstead(5)
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876,935
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5.0
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%
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Jeffrey R. Olmstead(5)
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323,153
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1.8
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%
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Robbin W. Jones(5)
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232,184
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1.3
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%
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David A. Culbertson(5)
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71,772
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0.4
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%
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S. Craig George(5)
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155,939
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0.9
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%
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Peter A. Leidel(5)
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Peter Adamson III(5)
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Robert W. Berry(5)
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Cameron O. Smith(5)
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21,135
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0.1
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%
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All named executive officers, directors and director nominees as
a group (9 persons)(5)
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1,681,118
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9.5
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%
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(1)
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Has a principal business address of
410 Park Avenue, 19th Floor, New York, New York 10022.
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(2)
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Yorktown VI Company LP is the sole
general partner of Yorktown Energy Partners VI, L.P. Yorktown VI
Associates LLC is the sole general partner of Yorktown VI
Company LP. As a result, Yorktown VI Associates LLC may be
deemed to have the power to vote or direct the vote or to
dispose or direct the disposition of the common units owned by
Yorktown Energy Partners VI, L.P. Yorktown VI Company LP and
Yorktown VI Associates LLC disclaim beneficial ownership of the
common units owned by Yorktown Energy Partners VI, L.P. in
excess of their pecuniary interests therein.
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(3)
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Yorktown VII Company LP is the sole
general partner of Yorktown Energy Partners VII, L.P. Yorktown
VII Associates LLC is the sole general partner of Yorktown VII
Company LP. As a result, Yorktown VII Associates LLC may be
deemed to have the power to vote or direct the vote or to
dispose or direct the disposition of the common units owned by
Yorktown Energy Partners VII, L.P. Yorktown VII Company LP and
Yorktown VII Associates LLC disclaim beneficial ownership of the
common units owned by Yorktown Energy Partners VII, L.P. in
excess of their pecuniary interests therein.
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(4)
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Yorktown VIII Company LP is the
sole general partner of Yorktown Energy Partners VIII, L.P.
Yorktown VIII Associates LLC is the sole general partner of
Yorktown VIII Company LP. As a result, Yorktown VIII Associates
LLC may be deemed to have the power to vote or direct the vote
or to dispose or direct the disposition of the common units
owned by Yorktown Energy Partners VIII, L.P. Yorktown VIII
Company LP and Yorktown VIII Associates LLC disclaim beneficial
ownership of the common units owned by Yorktown Energy Partners
VIII, L.P. in excess of their pecuniary interests therein.
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(5)
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c/o Mid-Con Energy GP, LLC,
2431 E. 61st Street, Suite 850 Tulsa, Oklahoma
74136.
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140
The following table sets forth the beneficial ownership of
equity interests in our general partner.
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Member
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Name of Beneficial Owner
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Interest(2)
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Charles R. Olmstead(1)
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33.33
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%
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S. Craig George(1)
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33.33
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%
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Jeffrey R. Olmstead(1)
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33.33
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%
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(1)
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c/o Mid-Con Energy GP, LLC,
2431 E. 61st Street, Suite 850 Tulsa, Oklahoma
74136.
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(2)
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Messrs. Olmstead, George, and
Olmstead, by virtue of their ownership interest in our general
partner, may be deemed to beneficially own the interests in us
held by our general partner. Each of Messrs. Olmstead,
George and Olmstead disclaims beneficial ownership of these
securities in excess of his pecuniary interest in such
securities.
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141
CERTAIN
RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Upon the consummation of this offering, assuming the
underwriters do not exercise their option to purchase additional
common units, the Founders and Yorktown will own 10,343,015
common units representing an approximate 58.6% limited partner
interest in us. In addition, our general partner will own a 2.0%
general partner interest in us, evidenced by 360,000 general
partner units. These percentages do not reflect any common units
that may be issued under the long-term incentive program that
our general partner expects to adopt prior to the closing of
this offering.
Distributions
and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments to
be made by us to our general partner and its affiliates in
connection with our formation, ongoing operation and
liquidation. These distributions and payments were determined by
and among affiliated entities and, consequently, were not the
result of arms length negotiations.
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The consideration received by our general partner and the
Contributing Parties prior to or in connection with this offering |
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12,240,000 common units;
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360,000 general partner units; and
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approximately $121.2 million in cash.
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To the extent the underwriters exercise their option to purchase
up to an additional 810,000 common units, the number of common
units issued to the Contributing Parties (as reflected in the
first bullet above) will decrease by the aggregate number of
common units purchased by the underwriters pursuant to such
exercise. The net proceeds from any exercise of such option will
be used to distribute additional cash consideration to the
Contributing Parties in respect of the merger of Mid-Con Energy
I, LLC and Mid-Con Energy II, LLC into our subsidiary at the
closing of this offering. |
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Distributions of available cash to our general partner and its
affiliates |
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We will generally make cash distributions 98.0% to our
unitholders, pro rata, including the Contributing Parties as the
holder of approximately 69.4% of our limited partner interests,
and 2.0% to our general partner, assuming it makes any capital
contributions necessary to maintain its 2.0% general partner
interest in us. |
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Assuming we have sufficient available cash to pay the full
initial quarterly distribution on all of our outstanding units
for four quarters, our general partner would receive an annual
distribution of approximately $0.7 million on its general
partner units and the Contributing Parties would receive an
annual distribution of approximately $23.3 million on their
common units. |
142
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Payments to our general partner and its affiliates |
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Our general partner will not receive a management fee or other
compensation for its management of our partnership, but we will
reimburse our general partner for all direct and indirect
expenses it incurs and payments it makes on our behalf and all
other expenses allocable to us or otherwise incurred by our
general partner in connection with operating our business. Our
partnership agreement does not set a limit on the amount of
expenses for which our general partner may be reimbursed. These
expenses include salary, bonus, incentive compensation,
employment benefits and other amounts paid to persons who
perform services for us or on our behalf and expenses allocated
to our general partner by its affiliates. Our partnership
agreement provides that our general partner will determine in
good faith the expenses that are allocable to us. |
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Withdrawal or removal of our general partner |
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In the event of removal of our general partner under
circumstances where cause exists or withdrawal of our general
partner where that withdrawal violates our partnership
agreement, a successor general partner will have the option to
purchase the departing general partners general partner
interest for a cash payment equal to the fair market value of
such interest. Under all other circumstances where our general
partner withdraws or is removed by the limited partners, the
departing general partner will have the option to require the
successor general partner to purchase the departing general
partners general partner interest in us for its fair
market value. |
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Liquidation Stage |
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Liquidation |
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Upon our liquidation, the partners, including our general
partner, will be entitled to receive liquidating distributions
according to their respective capital account balances. |
Agreements
with Affiliates in Connection with the Transactions
In connection with the closing of this offering, we, our general
partner and its affiliates will enter into the various documents
and agreements that will affect the transactions described in
Prospectus SummaryFormation Transactions and
Partnership Structure including the vesting of assets in,
and the assumption of liabilities by, us and the application of
the net proceeds of this offering. These agreements have been
negotiated among affiliated parties and, consequently, are not
the result of arms length negotiations. All of the
transaction expenses incurred in connection with these
transactions, including the expenses associated with
transferring assets to us, will be paid from the proceeds of
this offering.
Services Agreement
In connection with the closing of this offering, we will enter
into a services agreement with Mid-Con Energy Operating pursuant
to which Mid-Con Energy Operating will provide certain services
to us, including management, administrative and operational
services to us, which include marketing, geological and
engineering services. Under the services agreement, we will
reimburse Mid-Con Energy Operating, on a monthly basis, for the
allocable expenses it incurs in its performance under the
services agreement. These expenses include, among other things,
143
salary, bonus, incentive compensation and other amounts paid to
persons who perform services for us or on our behalf and other
expenses allocated by Mid-Con Energy Operating to us. Mid-Con
Energy Operating will have substantial discretion to determine
in good faith which expenses to incur on our behalf and what
portion to allocate to us. Mid-Con Energy Operating will not be
liable to us for its performance of, or failure to perform,
services under the services agreement unless its acts or
omissions constitute gross negligence or willful misconduct.
Assignment, Bill of Sale and Conveyance Agreement
Immediately prior to the closing of this offering, we will enter
into an assignment, bill of sale and conveyance agreement
pursuant to which J&A Oil Company, a company controlled by
Charles R. Olmstead and Jeffrey R. Olmstead, and Charles R.
Olmstead, in his individual capacity, will contribute to us
certain working interests in the Cushing Field and J & A
Oil Company will contribute to us its interests in certain
derivative contracts for aggregate consideration of
approximately $6.0 million. The working interests to be
acquired were producing approximately 30 Boe per day (net) and
contained approximately 228 MBoe of estimated net proved
reserves, each as of September 30, 2011. The related
derivative contracts to be acquired for 2011 are swaps covering
volumes of approximately 36 Bbls per day with a floor of
$86.30 per barrel. The related derivative contracts to be
acquired for 2012 are either swaps or collars covering volumes
of approximately 23 Bbls per day with a floor of at least
$100.00 per barrel. For information on our other interests in
the Cushing Field and our commodity derivative contracts, please
read Business and PropertiesOur
PropertiesNortheastern OklahomaCushing Field
and Managements Discussion and Analysis of Financial
Condition and Results of OperationHow We Evaluate Our
OperationsRealized Prices on the Sale of
OilCommodity Derivative Contracts.
Contribution, Conveyance, Assumption and Merger
Agreement
In connection with the closing of this offering, we will enter
into a contribution, conveyance, assumption and merger agreement
pursuant to which Mid-Con Energy I, LLC and Mid-Con Energy
II, LLC will merge into our subsidiary, Mid-Con Energy
Properties, and our general partner will make a contribution to
us. The contribution, conveyance, assumption and merger
agreement will provide for the Contributing Parties, as the
owners of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC,
to receive consideration that includes a combination of common
units and cash from the proceeds of this offering and for our
general partner to receive a 2.0% general partner interest in
us. All of the transaction expenses incurred in connection with
these transactions will be paid from proceeds of this offering.
Other
Transactions with Related Persons
Operating Agreements
We, various third parties with an ownership interest in the same
property and our affiliate, Mid-Con Energy Operating, are party
to standard oil and gas joint operating agreements entered into
prior to the closing of this offering, pursuant to which we and
those third parties pay Mid-Con Energy Operating overhead
charges associated with operating our properties (commonly
referred to as the Council of Petroleum Accountants Societies,
or COPAS, fee). We and those third parties will also pay Mid-Con
Energy Operating for its direct and indirect expenses that are
chargeable to the wells under their respective operating
agreements.
Certain Derivative Transactions
At September 30, 2011, we had a payable to J&A Oil
Company, LLC of $162,000 arising from shared derivative
transactions that we jointly entered into with financial
institutions.
Review,
Approval or Ratification of Transactions with Related
Persons
We expect that we will adopt a Code of Business Conduct and
Ethics that will set forth our policies for the review, approval
and ratification of transactions with related persons. Upon our
adoption of a Code of Business Conduct and Ethics, a director
would be expected to bring to the
144
attention of the Chief Executive Officer or the board of
directors of our general partner any conflict or potential
conflict of interest that may arise between the director or any
affiliate of the director, on the one hand, and us or our
general partner on the other. The resolution of any such
conflict or potential conflict will be addressed in accordance
with our general partners organizational documents and the
provisions of our partnership agreement. The resolution may be
determined by disinterested directors, our general
partners board of directors, or the conflicts committee of
our general partners board of directors.
Upon our adoption of a Code of Business Conduct and Ethics, any
executive officer of our general partner will be required to
avoid conflicts of interest unless approved by the board of
directors.
The board of directors of our general partner will have a
standing conflicts committee comprised of at least two
independent directors. Our general partner may, but is not
required to, seek the approval of the conflicts committee in
connection with future acquisitions of oil and natural gas
properties from the Mid-Con Affiliates or any other affiliates
of the general partner. In addition to acquisitions from
affiliates of our general partner, the board of directors of our
general partner will also determine whether to seek conflicts
committee approval to the extent we act jointly to acquire
additional oil and natural gas properties with affiliates of our
general partner. In the case of any sale of equity or debt by us
to an owner or affiliate of an owner of our general partner, we
anticipate that our practice will be to obtain the approval of
the conflicts committee of the board of directors of our general
partner for the transaction. The conflicts committee will be
entitled to hire its own financial and legal advisors in
connection with any matters on which the board of directors of
our general partner has sought the conflicts committees
approval.
The Mid-Con Affiliates or other affiliates of our general
partner are free to offer properties to us on terms they deem
acceptable, and the board of directors of our general partner
(or the conflicts committee) is free to accept or reject any
such offers, negotiating terms it deems acceptable to us. As a
result, the board of directors of our general partner (or the
conflicts committee) will decide, in its sole discretion, the
appropriate value of any assets offered to us by affiliates of
our general partner. In so doing, we expect the board of
directors (or the conflicts committee) will consider a number of
factors in its determination of value, including, without
limitation, production and reserve data, operating cost
structure, current and projected cash flow, financing costs, the
anticipated impact on distributions to our unitholders,
production decline profile, commodity price outlook, reserve
life, future drilling inventory and the weighting of the
expected production between oil and natural gas.
We expect that the Mid-Con Affiliates or other affiliates of our
general partner will consider a number of the same factors
considered by the board of directors of our general partner to
determine the proposed purchase price of any assets it may offer
to us in future periods. In addition to these factors, given
that the Founders and Yorktown will own an approximate 57.4%
limited partner interest in us following the consummation of
this offering and through their interests in our general
partner, they may consider the potential positive impact on
their underlying investment in us by causing the
Mid-Con
Affiliates to offer properties to us at attractive purchase
prices. Likewise, the affiliates of our general partner may
consider the potential negative impact on their underlying
investment in us if we are unable to acquire additional assets
on favorable terms, including the negotiated purchase price.
145
CONFLICTS
OF INTEREST AND FIDUCIARY DUTIES
Conflicts
of Interest
Conflicts of interest exist and may arise in the future as a
result of the relationships between our general partner, our
general partners affiliates (including the Mid-Con
Affiliates) and Yorktown on the one hand, and us and our limited
partners, on the other hand. The directors and officers of our
general partner have fiduciary duties to manage the business of
our general partner in a manner beneficial to its owners. In
addition, all of our general partners executive officers
and non-independent directors will continue to have economic
interests in affiliates of our general partner, which may lead
to additional conflicts of interest. At the same time, our
general partner has a fiduciary duty to manage our partnership
in a manner beneficial to us and our unitholders.
Whenever a conflict arises between our general partner or its
affiliates, on the one hand, and us and our limited partners, on
the other hand, our general partner will resolve that conflict.
Our partnership agreement contains provisions that modify and
limit our general partners fiduciary duties to our
unitholders. Our partnership agreement also restricts the
remedies available to unitholders for actions taken that,
without those limitations, might constitute breaches of
fiduciary duty.
Our general partner will not be in breach of its obligations
under our partnership agreement or its duties to us or our
unitholders if the resolution of the conflict is:
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approved by the conflicts committee, although our general
partner is not obligated to seek such approval;
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approved by the vote of the holders of a majority of the
outstanding common units, excluding any common units owned by
our general partner or any of its affiliates;
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on terms no less favorable to us than those generally being
provided to or available from unrelated third parties; or
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fair and reasonable to us, taking into account the totality of
the relationships among the parties involved, including other
transactions that may be particularly favorable or advantageous
to us.
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If the resolution or course of action taken with respect to the
conflict of interest satisfies any of the standards set forth in
the first, third or fourth bullet points above, then such
resolution or course of action will be deemed to be approved by
all of our unitholders and, in the case of all four bullet
points above, will not constitute a breach of our partnership
agreement or of any duties our general partner may owe us or our
unitholders.
As required by our partnership agreement, the board of directors
of our general partner will maintain a conflicts committee
comprised of at least two independent directors. Our general
partner may, but is not required to, seek approval from the
conflicts committee of a resolution of a conflict of interest
with our general partner or affiliates. Any matters approved by
the conflicts committee will be conclusively deemed to have been
approved in good faith. If our general partner does not seek
approval from the conflicts committee and its board of directors
determines that the resolution or course of action taken with
respect to the conflict of interest satisfies either of the
standards set forth in the third or fourth bullet points above,
then it will be presumed that, in making its decision, the board
of directors acted in good faith and, in each case, in any
proceeding brought by or on behalf of any limited partner or us
challenging such approval, the person bringing or prosecuting
such proceeding will have the burden of overcoming such
presumption. Unless the resolution of a conflict is specifically
provided for in our partnership agreement, our general partner
or the conflicts committee may consider any factors it
determines in good faith to consider when resolving a conflict.
When our partnership agreement requires someone to act in good
faith, it requires that person to subjectively believe that he
or she is acting in our best interest.
146
Conflicts of interest could arise in the situations described
below, among others:
Affiliates of our general partner will not be limited in
their ability to compete with us, which could cause conflicts of
interest and limit our ability to acquire additional
assets.
Our partnership agreement provides that our general partner will
be restricted from engaging in any business activities other
than acting as our general partner (or as general partner or
managing member, as the case may be, of another company of which
we are a partner or member) or those activities incidental to
its ownership of interests in us. However, affiliates of our
general partner, including the Mid-Con Affiliates, and Yorktown
are not prohibited from engaging in other businesses or
activities, including those that might be in direct competition
with us. Additionally, Yorktown, through its investment funds
and managed accounts, makes investments and purchases entities
in various areas of the oil and natural industry. These
investments and acquisitions may include entities or assets that
we would have been interested in acquiring.
Pursuant to the terms of our partnership agreement, the doctrine
of corporate opportunity, or any analogous doctrine, will not
apply to our general partner, any of its affiliates (including
its executive officers, directors and the Mid-Con Affiliates) or
Yorktown. Any such person or entity that becomes aware of a
potential transaction, agreement, arrangement or other matter
that may be an opportunity for us will not have any duty to
communicate or offer such opportunity to us. Any such person or
entity will not be liable to us or to any limited partner for
breach of any fiduciary duty or other duty by reason of the fact
that such person or entity pursues or acquires such opportunity
for itself, directs such opportunity to another person or entity
or does not communicate such opportunity or information to us;
provided, however, that such person does not pursue or acquire
such opportunity for itself as a result of using confidential
or proprietary information provided by or on behalf of us to
such person. Therefore, affiliates of our general partner,
including the Mid-Con Affiliates, and Yorktown may compete with
us for investment opportunities and may own an interest in
entities that compete with us.
Our general partner and its affiliates are allowed to take
into account the interests of parties other than us in resolving
conflicts of interest.
Our partnership agreement contains provisions that reduce the
standards to which our general partner would otherwise be held
by state fiduciary duty law. For example, our partnership
agreement permits our general partner to make a number of
decisions in its individual capacity, as opposed to in its
capacity as our general partner. This entitles our general
partner to consider only the interests and factors that it
desires, and it has no duty or obligation to give any
consideration to any interest of, or factors affecting, us, our
affiliates or any limited partner. Examples include our general
partners limited call right, its registration rights and its
determination whether or not to consent to any merger or
consolidation involving us.
All of the executive officers and non-independent
directors of our general partner will spend significant time
serving entities that may compete with us in seeking
acquisitions and business opportunities and, accordingly, may
have conflicts of interest in allocating time or pursuing
business opportunities.
To maintain and increase our levels of production, we will need
to acquire oil and natural gas properties. All of the executive
officers and non-independent directors of our general partner
are also officers
and/or
directors of the Mid-Con Affiliates and will continue to devote
significant time to those businesses. Further, all of our
executive officers and non-independent directors will continue
to have economic interests in, as well as management and
fiduciary duties to, the Mid-Con Affiliates. The existing
positions held by these directors and officers may give rise to
fiduciary duties that are in conflict with fiduciary duties they
owe to us. We cannot assure our unitholders that these conflicts
will be resolved in our favor. As officers and directors of our
general partner, these individuals may become aware of business
opportunities that may be appropriate for presentation to us as
well as the other entities with which they are or may
147
become affiliated. Due to these existing and potential future
affiliations and economic interests in these and other entities,
they may have fiduciary obligations or incentives to present
potential business opportunities to those entities prior to
presenting them to us, which could cause additional conflicts of
interest. They may also decide that certain opportunities are
more appropriate for other entities with which they are
affiliated, and as a result, they may elect not to present them
to us. For further discussion of our managements business
affiliations and the potential conflicts of interest of which
our unitholders should be aware, please read Business and
PropertiesOur Principal Business Relationships and
Management.
Our partnership agreement limits our general
partners fiduciary duties to our unitholders and restricts
the remedies available to unitholders for actions taken by our
general partner that might otherwise constitute breaches of
fiduciary duty.
Our partnership agreement contains provisions that reduce the
fiduciary standards to which our general partner would otherwise
be held by state fiduciary duty laws. For example, our
partnership agreement:
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permits our general partner to make a number of decisions in its
individual capacity, as opposed to in its capacity as our
general partner, which allows our general partner to consider
only the interests and factors that it desires, without a duty
or obligation to give any consideration to any interest of, or
factors affecting, us, our affiliates or any limited partner.
Examples include the exercise of its limited call right, the
exercise of its rights to transfer or vote the units it owns,
the exercise of its registration rights and its determination
whether or not to consent to any merger or consolidation
involving us or to any amendment to the partnership agreement;
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provides that our general partner will not have any liability to
us or our unitholders for decisions made in its capacity as
general partner so long as it acted in good faith;
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generally provides that affiliated transactions and resolutions
of conflicts of interest not approved by the conflicts committee
of the board of directors of our general partner and not
involving a vote of unitholders must either be (i) on terms
no less favorable to us than those generally being provided to
or available from unrelated third parties or (ii) must be
fair and reasonable to us, as determined by our
general partner in good faith. In determining whether a
transaction or resolution is fair and reasonable,
our general partner may consider the totality of the
relationships between the parties involved, including other
transactions that may be particularly favorable or advantageous
to us;
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provides that our general partner and its officers and directors
will not be liable for monetary damages to us, our limited
partners or assignees for any acts or omissions unless there has
been a final and non-appealable judgment entered by a court of
competent jurisdiction determining that, in respect of the
matter in question, our general partner or its officers and
directors acted in bad faith or engaged in fraud or willful
misconduct or, in the case of a criminal matter, acted with
knowledge that the conduct was criminal;
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provides that in resolving conflicts of interest, it will be
presumed that in making its decision our general partners
board of directors acted in good faith, and in any proceeding
brought by or on behalf of any limited partner or us, the person
bringing or prosecuting such proceeding will have the burden of
overcoming such presumption; and
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provides that in resolving conflicts of interest, it will be
conclusively deemed that in making its decision the conflicts
committee of our general partners board of directors acted
in good faith.
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By purchasing a common unit, a unitholder will become bound by
the provisions in the partnership agreement, including the
provisions discussed above. Please read Fiduciary
Duties.
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Except in limited circumstances, our general partner has
the power and authority to conduct our business without
unitholder approval.
Under our partnership agreement, our general partner has full
power and authority to do all things, other than those items
that require unitholder approval or with respect to which our
general partner has sought conflicts committee approval, on such
terms as it determines to be necessary or appropriate to conduct
our business, including, but not limited to, the following:
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the making of any expenditures, the lending or borrowing of
money, the assumption or guarantee of or other contracting for,
indebtedness and other liabilities, the issuance of evidences of
indebtedness, including indebtedness that is convertible or
exchangeable into our securities, and the incurring of any other
obligations;
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the purchase, sale or other acquisition or disposition of our
securities, or the issuance of options, rights, warrants,
restricted units, unit appreciation rights, phantom or tracking
interests or other economic interests in us or relating to our
securities;
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the acquisition, disposition, mortgage, pledge, encumbrance,
hypothecation or exchange of any or all of our assets or the
merger or other combination of us with or into another entity
(subject to certain prior approvals);
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the use of our assets (including cash on hand) for any purpose
consistent with our partnership agreement;
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the negotiation, execution and performance of any contracts,
conveyances or other instruments;
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the distribution of our cash;
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the selection, employment, retention and dismissal of employees
and agents, outside attorneys, accountants, consultants and
contractors and the determination of their compensation and
other terms of employment or hiring;
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the maintenance of insurance for our benefit and the benefit of
our partners;
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the formation of, or acquisition of an interest in, the
contribution of property to, and the making of loans to, any
limited or general partnerships, joint ventures, corporations,
limited liability companies or other entities;
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the control of any matters affecting our rights and obligations,
including the bringing and defending of actions at law or in
equity and otherwise engaging in the conduct of litigation,
arbitration or mediation and the incurring of legal expense and
the settlement of claims and litigation;
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the indemnification of any person against liabilities and
contingencies to the extent permitted by law;
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the making of tax, regulatory and other filings or rendering of
periodic or other reports to governmental or other agencies
having jurisdiction over our business or assets; and
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the entering into of agreements with any of its affiliates to
render services to us or to itself in the discharge of its
duties as our general partner.
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Our partnership agreement provides that our general partner must
act in good faith when making decisions on our
behalf, and our partnership agreement further provides that in
order for a determination by our general partner to be made in
good faith, our general partner must subjectively
believe that the determination is in our best interests. Please
read The Partnership AgreementLimited Voting
Rights for information regarding matters that require
unitholder approval.
Our general partner determines the amount and timing of
asset purchases and sales, capital expenditures, borrowings,
issuance of additional partnership interests and the creation,
reduction or increase of reserves, each of which can affect the
amount of cash that is distributed to our unitholders.
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The amount of cash that is available for distribution to
unitholders is affected by decisions of our general partner
regarding such matters as:
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the manner in which our business is operated;
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the amount, nature and timing of asset purchases and sales,
including whether to pursue acquisitions that may also be
suitable for affiliates of our general partner;
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the amount, nature and timing of our capital expenditures;
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the amount of borrowings;
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the issuance of additional units; and
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the creation, reduction or increase of reserves in any quarter.
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Our partnership agreement provides that we and our subsidiary
may borrow funds from our general partner and its affiliates.
However, our general partner and its affiliates may not borrow
funds from us or our operating subsidiaries.
Our general partner determines which costs incurred by it
are reimbursable by us.
We will reimburse our general partner and its affiliates for
costs incurred in managing and operating our business, including
costs incurred in rendering staff and support services to us
pursuant to the services agreement with Mid-Con Energy
Operating, an affiliate of our general partner.
Payments for these services will be substantial and will reduce
the amount of cash available for distribution to our
unitholders. Please read Certain Relationships and Related
Party Transactions Agreements with Affiliates in
Connection with the Transactions Services
Agreement. Our general partner will have substantial
discretion to determine in good faith which expenses to incur on
our behalf and what portion to allocate to us. In turn, our
partnership agreement provides that our general partner will
determine in good faith the expenses that are allocable to us.
Please read Certain Relationships and Related Party
Transactions.
In addition, under Delaware partnership law, our general partner
has unlimited liability for our obligations, such as our debts
and environmental liabilities, except for our contractual
obligations that are expressly made without recourse to our
general partner. To the extent our general partner incurs
obligations on our behalf, we are obligated to reimburse or
indemnify it. If we are unable or unwilling to reimburse or
indemnify our general partner, our general partner may take
actions to cause us to make payments of these obligations and
liabilities. Any such payments could reduce the amount of cash
otherwise available for distribution to our unitholders.
Contracts between us, on the one hand, and our general
partner and its affiliates, on the other, will not be the result
of arms-length negotiations.
Our partnership agreement allows our general partner to
determine, in good faith, any amounts to pay itself or its
affiliates for any services rendered to us. Our general partner
may also enter into additional contractual arrangements with any
of its affiliates on our behalf. Neither our partnership
agreement nor any of the other agreements, contracts, and
arrangements between us and our general partner and its
affiliates are or will be the result of arms-length
negotiations. Similarly, agreements, contracts or arrangements
between us and our general partner and its affiliates that are
entered into following the closing of this offering will not be
required to be negotiated on an arms-length basis,
although, in some circumstances, our general partner may
determine that the conflicts committee may make a determination
on our behalf with respect to such arrangements.
Our general partner will determine, in good faith, the terms of
any of these transactions entered into after the close of this
offering.
Our general partner and its affiliates will have no obligation
to permit us to use any facilities or assets of our general
partner and its affiliates, except as may be provided in
contracts entered
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into specifically for such use. There is no obligation of our
general partner and its affiliates to enter into any contracts
of this kind.
Our general partner may exercise its right to call and
purchase common units if it and its affiliates own more than 80%
of the common units.
If at any time our general partner and its affiliates own more
than 80% of the common units, our general partner may exercise
its right to call and purchase common units as provided in the
partnership agreement or assign this right to one of its
affiliates or to us. Our general partner is not bound by
fiduciary duty restrictions in determining whether to exercise
this right. As a result, a common unitholder may have his common
units purchased from him at an undesirable time or price. Please
read The Partnership AgreementLimited Call
Right.
Common unitholders will have no right to enforce
obligations of our general partner and its affiliates under
agreements with us.
Any agreements between us, on the one hand, and our general
partner and its affiliates, on the other, will not grant to the
unitholders, separate and apart from us, the right to enforce
the obligations of our general partner and its affiliates in our
favor.
Our general partner, our general partners affiliates
(including the Founders) and Yorktown may be able to amend our
partnership agreement without the approval of any other
unitholder.
Our general partner has the discretion to propose amendments to
our partnership agreement, certain of which may be made by our
general partner without unitholder approval. Our partnership
agreement can also be amended with the consent of our general
partner and the approval of the holders of a majority of our
outstanding common units (including common units held by
affiliates of our general partner and Yorktown). Upon the
consummation of this offering, the Founders and Yorktown will
own approximately 10,343,015 common units representing a
58.6% limited partnership interest in us. Assuming that the
Founders and Yorktown retain a sufficient number of their
respective common units and that we do not issue additional
common units, our general partner, our general partners
affiliates and Yorktown will have the ability to amend our
partnership agreement without the approval of any other
unitholder. Please read The Partnership
AgreementAmendment of the Partnership Agreement.
Our general partner intends to limit its liability
regarding our obligations.
Our general partner will enter into contractual arrangements on
our behalf and intends to limit its liability under such
contractual arrangements so that the other party has recourse
only to our assets and not against our general partner or its
assets. The partnership agreement provides that any action taken
by our general partner to limit its liability is not a breach of
our general partners fiduciary duties, even if we could
have obtained more favorable terms without the limitation on
liability.
Our general partner decides whether to retain separate
counsel, accountants or others to perform services for
us.
The attorneys, independent accountants and others who have
performed services for us regarding this offering have been
retained by our general partner. The attorneys, independent
accountants and others who perform services for us are selected
by our general partner, or the conflicts committee of our
general partners board of directors, and may also perform
services for our general partner and its affiliates. We may
retain separate counsel for ourselves or the holders of common
units in the event of a conflict of interest between our general
partner and its affiliates, on the one hand, and us or the
holders of common units, on the other, depending on the nature
of the conflict. We do not intend to do so in most cases.
Fiduciary
Duties
Our general partner is accountable to us and our unitholders as
a fiduciary. Fiduciary duties owed to unitholders by our general
partner are prescribed by law and the partnership agreement.
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The Delaware Revised Uniform Limited Partnership Act, which we
refer to in this prospectus as the Delaware Act, provides that
Delaware limited partnerships may, in their partnership
agreements, modify, restrict or expand the fiduciary duties
otherwise owed by a general partner to limited partners and the
partnership.
Our partnership agreement contains various provisions modifying
and restricting the fiduciary duties that might otherwise be
owed by our general partner. We have adopted these restrictions
to allow our general partner and its affiliates to engage in
transactions with us that would otherwise be prohibited by
state-law fiduciary duty standards and to take into account the
interests of other parties in addition to our interests when
resolving conflicts of interest. Without these modifications,
our general partners ability to make decisions involving
conflicts of interest would be restricted, and engaging in such
transactions could result in violations of our general
partners state-law fiduciary standards. We believe these
modifications are appropriate and necessary because our general
partners board of directors has fiduciary duties to manage
our general partner in a manner beneficial to its owners, as
well as to our unitholders. The modifications to the fiduciary
standards enable our general partner to take into consideration
the interests of all parties involved in the proposed action, so
long as the resolution is fair and reasonable to us. These
modifications also enable our general partner to attract and
retain experienced and capable directors. These modifications
are detrimental to our common unitholders because they restrict
the rights and remedies that would otherwise be available to our
unitholders for actions that, without those limitations, might
constitute breaches of fiduciary duty, as described below, and
permit our general partner to take into account the interests of
third parties in addition to our interests when resolving
conflicts of interest.
The following is a summary of the material restrictions of the
fiduciary duties owed by our general partner to the limited
partners:
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State-law fiduciary duty standards |
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Fiduciary duties are generally considered to include an
obligation to act in good faith and with due care and loyalty.
The duty of care, in the absence of a provision in a partnership
agreement providing otherwise, would generally require a general
partner to act for the partnership in the same manner as a
prudent person would act on his own behalf. The duty of loyalty,
in the absence of a provision in a partnership agreement
providing otherwise, would generally prohibit a general partner
of a Delaware limited partnership from taking any action or
engaging in any transaction where a conflict of interest is
present. |
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Rights and remedies of unitholders |
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The Delaware Act generally provides that a limited partner may
institute legal action on behalf of the partnership to recover
damages from a third party where a general partner has refused
to institute the action or where an effort to cause a general
partner to do so is not likely to succeed. These legal actions
include actions against a general partner for breach of
fiduciary duty or the partnership agreement. In addition, the
statutory or case law of some jurisdictions may permit a limited
partner to institute legal action on behalf of himself and all
other similarly situated limited partners to recover damages
from a general partner for violations of its fiduciary duties to
the limited partners. |
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Partnership agreement modified standards |
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Our partnership agreement contains provisions that waive or
consent to conduct by our general partner and its affiliates
that might otherwise raise issues about compliance with
fiduciary duties or applicable law. For example, our partnership
agreement provides that when our general partner is acting in
its capacity as our general partner, as opposed to in its
individual capacity, it must act in good faith and
will not be subject to any other standard under applicable law.
In addition, when our general partner is acting in its
individual capacity, as opposed to in its capacity as our
general partner, it may act without any fiduciary obligation to
us or the unitholders whatsoever. These standards reduce the
obligations to which our general partner would otherwise be held. |
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In addition to the other more specific provisions limiting the
obligations of our general partner, our partnership agreement
further provides that our general partner and its officers and
directors will not be liable for monetary damages to us or our
limited partners for losses sustained or liabilities incurred as
a result of any act or omission unless there has been a final
and non-appealable judgment entered by a court of competent
jurisdiction determining that, in respect of the matter in
question, our general partner or its officers and directors
acted in bad faith or engaged in fraud or willful misconduct, or
in the case of a criminal matter, acted with the knowledge that
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Special Provisions Regarding Affiliated
Transactions. Our partnership agreement generally
provides that affiliated transactions and resolutions of
conflicts of interest that are not approved by a vote of
unitholders and that are not approved by the conflicts committee
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on terms no less favorable to us than those
generally being provided to or available from unrelated third
parties; or
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fair and reasonable to us, taking into account the
totality of the relationships between the parties involved
(including other transactions that may be particularly favorable
or advantageous to us).
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If our general partner does not seek approval from the conflicts
committee and the board of directors of our general partner
determines that the resolution or course of action taken with
respect to the conflict of interest satisfies either of the
standards set forth in the bullet points above, then it will be
presumed that, in making its decision, the board of directors,
which may include board members affected by the conflict of
interest, acted in good faith, and in any proceeding brought by
or on behalf of any limited partner or us challenging such
approval, the person bringing or |
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prosecuting such proceeding will have the burden of overcoming
such presumption. These standards reduce the obligations to
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By purchasing our common units, each common unitholder
automatically agrees to be bound by the provisions in our
partnership agreement, including the provisions discussed above.
This is in accordance with the policy of the Delaware Act
favoring the principle of freedom of contract and the
enforceability of partnership agreements. The failure of a
limited partner to sign a partnership agreement does not render
our partnership agreement unenforceable against that person.
Under our partnership agreement, we must indemnify our general
partner and its officers, directors, managers and certain other
specified persons, to the fullest extent permitted by law,
against liabilities, costs and expenses incurred by our general
partner or these other persons. We must provide this
indemnification unless there has been a final and non-appealable
judgment by a court of competent jurisdiction determining that,
in respect of the matter for which these persons are seeking
indemnification, these persons acted in bad faith or engaged in
fraud or willful misconduct. We must also provide this
indemnification for criminal proceedings unless our general
partner or these other persons acted with knowledge that their
conduct was unlawful. Thus, our general partner could be
indemnified for its negligent acts if it meets the requirements
set forth above. To the extent these provisions purport to
include indemnification for liabilities arising under the
Securities Act of 1933, in the opinion of the SEC, such
indemnification is contrary to public policy and, therefore,
unenforceable. Please read The Partnership
AgreementIndemnification.
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DESCRIPTION
OF THE COMMON UNITS
The
Units
The holders of units are entitled to participate in partnership
distributions and exercise the rights or privileges available to
limited partners under our partnership agreement. For a
description of the rights of holders of common units in and to
partnership distributions, please read this section and
Our Cash Distribution Policy and Restrictions on
Distributions. For a description of other rights and
privileges of limited partners under our partnership agreement,
including voting rights, please read The Partnership
Agreement.
Transfer
Agent and Registrar
Duties
Wells Fargo Shareholder Services will serve as registrar and
transfer agent for the common units. We will pay all fees
charged by the transfer agent for transfers of common units,
except the following, which must be paid by our unitholders:
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surety bond premiums to replace lost or stolen certificates or
to cover taxes and other governmental charges;
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special charges for services requested by a common
unitholder; and
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other similar fees or charges.
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There will be no charge to our unitholders for disbursements of
our cash distributions. We will indemnify the transfer agent,
its agents and each of their respective stockholders, directors,
officers and employees against all claims and losses that may
arise out of their actions for their activities in that
capacity, except for any liability due to any gross negligence
or willful misconduct of the indemnitee.
Resignation or Removal
The transfer agent may resign, by notice to us, or be removed by
us. The resignation or removal of the transfer agent will become
effective upon our appointment of a successor transfer agent and
registrar and its acceptance of the appointment. If no successor
is appointed, our general partner may act as the transfer agent
and registrar until a successor is appointed.
Transfer of Common Units
By transfer of common units in accordance with our partnership
agreement, each transferee of common units shall be admitted as
a limited partner with respect to the common units transferred
when such transfer and admission are reflected in our books and
records. Each transferee:
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represents that the transferee has the capacity, power and
authority to become bound by our partnership agreement;
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automatically agrees to be bound by the terms and conditions of
our partnership agreement; and
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makes the consents, acknowledgments and waivers contained in our
partnership agreement, such as the approval of all transactions
and agreements that we are entering into in connection with our
formation and this offering.
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Our general partner may request that a transferee of common
units certify that such transferee is an Eligible Holder. As of
the date of this prospectus, an Eligible Holder means:
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a citizen of the United States;
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a corporation organized under the laws of the United States or
of any state thereof;
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a public body of the United States, including a municipality of
the United States;
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an association of United States citizens, such as a partnership
or limited liability company, organized under the laws of the
United States or of any state thereof, but only if such
association does not have any direct or indirect foreign
ownership, other than foreign ownership of stock in a parent
corporation organized under the laws of the United States or of
any state thereof; or
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a limited partner whose nationality, citizenship or other
related status would not, in the determination of our general
partner, create a substantial risk of cancellation or forfeiture
of any property in which we or our subsidiary has an interest.
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For the avoidance of doubt, onshore mineral leases or any direct
or indirect interest therein may be acquired and held by aliens
only through stock ownership, holding or control in a
corporation organized under the laws of the United States or of
any state thereof.
In addition to other rights acquired upon transfer, the
transferor gives the transferee the right to be admitted to our
partnership as a limited partner with respect to the transferred
common units. A transferee will become a limited partner of our
partnership for the transferred common units automatically upon
the recording of the transfer on our books and records. Our
general partner will cause any transfers to be recorded on our
books and records no less frequently than quarterly.
Until a common unit has been transferred on our books, we and
the transfer agent may treat the record holder of the unit as
the absolute owner for all purposes, except as otherwise
required by law or stock exchange regulations.
We may, at our discretion, treat the nominee holder of a common
unit as the absolute owner. In that case, the beneficial
holders rights are limited solely to those that it has
against the nominee holder as a result of any agreement between
the beneficial owner and the nominee holder.
Common units are securities and any transfers are subject to the
laws governing transfers of securities.
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THE
PARTNERSHIP AGREEMENT
The following is a summary of the material provisions of our
partnership agreement. The form of our partnership agreement is
included in this prospectus as Appendix A. We will provide
prospective investors with a copy of our partnership agreement
upon request at no charge.
We summarize the following provisions of our partnership
agreement elsewhere in this prospectus:
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with regard to distributions of available cash, please read
Our Cash Distribution Policy and Restrictions on
Distributions and Provisions of Our Partnership
Agreement Relating to Cash Distributions;
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with regard to the fiduciary duties of our general partner,
please read Conflicts of Interest and Fiduciary
Duties;
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with regard to the transfer of common units, please read
Description of the Common UnitsTransfer Agent and
RegistrarTransfer of Common Units; and
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with regard to allocations of taxable income, taxable loss and
other matters, please read Material Tax Consequences.
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Organization
and Duration
Our partnership was organized in July 2011 and will have a
perpetual existence unless terminated pursuant to the terms of
our partnership agreement.
Purpose
Our purpose under our partnership agreement is to engage
directly in, or enter into or form, hold and dispose of any
corporation, partnership, joint venture, limited liability
company or other arrangement to engage directly in, any business
activity that is approved by our general partner and that
lawfully may be conducted by a limited partnership organized
under Delaware law and, in connection therewith, to exercise all
of the rights and powers conferred upon us pursuant to the
agreements relating to such business activity and do anything
necessary or appropriate to the foregoing. However, our general
partner may not cause us to engage in any business activity that
it determines would be reasonably likely to cause us to be
treated as an association taxable as a corporation or otherwise
taxable as an entity for federal income tax purposes.
Although our general partner has the ability to cause us and our
subsidiary to engage in activities other than the ownership,
acquisition, exploitation and development of oil and natural gas
properties and the ownership, acquisition and operation of
related assets, our general partner has no current plans to do
so and may decline to do so free of any fiduciary duty or
obligation whatsoever to us or our limited partners, including
any duty to act in good faith or in the best interests of us or
our limited partners. Our general partner is generally
authorized to perform all acts it determines to be necessary or
appropriate to carry out our purposes and to conduct our
business.
Cash
Distributions
Our partnership agreement specifies the manner in which we will
make cash distributions to our unitholders and other partnership
interests as well as to our general partner in respect of its
general partner interest. For a description of these cash
distribution provisions, please read Provisions of Our
Partnership Agreement Relating to Cash Distributions.
Capital
Contributions
Unitholders are not obligated to make additional capital
contributions, except as described under Limited
Liability.
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For a discussion of our general partners right to
contribute capital to maintain its 2.0% general partner interest
if we issue additional units, please read Issuance
of Additional Interests.
Limited
Voting Rights
The following is a summary of the unitholder vote required for
each of the matters specified below.
Various matters require the approval of a unit
majority, which means the approval of a majority of the
outstanding common units.
In voting their common units, our general partner, and our
general partners affiliates (including the Founders) and
Yorktown will have no fiduciary duty or obligation whatsoever to
us or the limited partners, including any duty to act in good
faith or in the best interests of us or our limited partners.
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Issuance of additional units |
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No approval right. Please read Issuance of
Additional Interests. |
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Amendment of the partnership agreement |
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Certain amendments may be made by our general partner without
the approval of any limited partner. Other amendments generally
require the approval of a unit majority. Please read
Amendment of the Partnership Agreement. |
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Merger of our partnership or the sale of all or substantially
all of our assets |
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Unit majority, in certain circumstances. Please read
Merger, Consolidation, Sale or Other Disposition of
Assets. |
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Dissolution of our partnership |
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Unit majority. Please read Dissolution. |
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Continuation of our business upon dissolution |
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Unit majority. Please read Dissolution. |
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Withdrawal of our general partner |
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Prior to December 31, 2021, under most circumstances, the
approval of a majority of the common units, excluding common
units held by our general partner and its affiliates (including
the Founders), is required for the withdrawal of our general
partner in a manner that would cause a dissolution of our
partnership. Please read Withdrawal or Removal of
Our General Partner. |
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Removal of our general partner |
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Not less than
662/3%
of the outstanding units, including units held by our general
partner and its affiliates (including the Founders). Please read
Withdrawal or Removal of Our General Partner. |
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Transfer of our general partner interest |
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Our general partner may transfer without a vote of our
unitholders all, but not less than all, of its general partner
interest in us to an affiliate or another person (other than an
individual) in connection with its merger or consolidation with
or into, or sale of all, or substantially all, of its assets to,
such other person. The approval of a majority of the common
units, excluding common units held by our general partner and
its affiliates (including the Founders), is required in other
circumstances for a transfer of the general partner interest to
a third party prior to December 31, 2021. Please read
Transfer of General Partner Interest. |
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Transfer of ownership interests in our general partner |
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No approval required at any time. Please read
Transfer of Ownership Interests in Our General
Partner. |
Applicable
Law; Forum, Venue and Jurisdiction
Our partnership agreement is governed by Delaware law. Our
partnership agreement requires that any claims, suits, actions
or proceedings:
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arising out of or relating in any way to the partnership
agreement (including any claims, suits or actions to interpret,
apply or enforce the provisions of the partnership agreement or
the duties, obligations or liabilities among limited partners or
of limited partners to us, or the rights or powers of, or
restrictions on, the limited partners or us);
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brought in a derivative manner on our behalf;
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asserting a claim of breach of duty (including any fiduciary
duty) owed by any director, officer or other employee of us or
our general partner, or owed by our general partner, to us or
the limited partners;
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asserting a claim arising pursuant to or to interpret or enforce
any provision of the Delaware Act; or
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asserting a claim governed by the internal affairs doctrine,
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shall be exclusively brought in the Court of Chancery of the
State of Delaware (or, if such court does not have subject
matter jurisdiction thereof, any other court in the State of
Delaware with subject matter jurisdiction), in each case,
regardless of whether such claims, suits, actions or proceedings
sound in contract, tort, fraud or otherwise, are based on common
law, statutory, equitable, legal or other grounds, or are
derivative or direct claims. By purchasing a common unit, a
limited partner (i) irrevocably submits to the exclusive
jurisdiction of such courts in connection with any such claim,
suit, action or proceedings; (ii) irrevocably agrees not to, and
waives any right to, assert in any such claim, suit, action or
proceeding that (A) it is not personally subject to the
jurisdiction of such courts or of any other court to which
proceedings in such courts may be appealed, (B) such claim,
suit, action or proceeding is brought in an inconvenient forum,
or (C) the venue of such claim, suit, action or proceeding is
improper; (iii) expressly waives any requirement for the posting
of a bond by a party bringing such claim, suit, action or
proceeding; (v) consents to process being served in any such
claim, suit, action or proceeding by (X) mailing, certified
mail, return receipt requested, a copy thereof to such party at
the address in effect for notices under our partnership
agreement or (Y) any other manner permitted by law; and (vi)
irrevocably waives any and all right to trial by jury in any
such claim, suit, action or proceeding.
Limited
Liability
Assuming that a limited partner does not participate in the
control of our business within the meaning of the Delaware Act
and that he otherwise acts in conformity with the provisions of
our partnership agreement, his liability under the Delaware Act
will be limited, subject to possible exceptions, to the amount
of capital he is obligated to contribute to us for his common
units plus his share of any undistributed profits and assets. If
it were determined, however, that the right or exercise of the
right by our limited partners as a group:
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to remove or replace our general partner;
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to approve some amendments to the partnership agreement; or
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to take other action under the partnership agreement;
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constituted participation in the control of our
business for the purposes of the Delaware Act, then our limited
partners could be held personally liable for our obligations
under Delaware law, to the same extent as our general partner.
This liability would extend to persons who transact business
with us and reasonably believe that the limited partner is a
general partner. Neither
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our partnership agreement nor the Delaware Act specifically
provides for legal recourse against our general partner if a
limited partner were to lose limited liability through any fault
of our general partner. While this does not mean that a limited
partner could not seek legal recourse, we know of no precedent
for this type of a claim in Delaware case law.
Under the Delaware Act, a limited partnership may not make a
distribution to a partner if, after the distribution, all
liabilities of the limited partnership, other than liabilities
to partners on account of their partnership interests and
liabilities for which the recourse of creditors is limited to
specific property of the partnership, would exceed the fair
value of the assets of the limited partnership. For the purpose
of determining the fair value of the assets of a limited
partnership, the Delaware Act provides that the fair value of
property subject to liability for which recourse of creditors is
limited shall be included in the assets of the limited
partnership only to the extent that the fair value of that
property exceeds the nonrecourse liability. The Delaware Act
provides that a limited partner who receives a distribution and
knew at the time of the distribution that the distribution was
in violation of the Delaware Act shall be liable to the limited
partnership for the amount of the distribution for three years.
Under the Delaware Act, a substituted limited partner of a
limited partnership is liable for the obligations of his
assignor to make contributions to the partnership, except that
such person is not obligated for liabilities unknown to him at
the time he became a limited partner and that could not be
ascertained from the partnership agreement.
Our operating subsidiary conducts business in Oklahoma and
Colorado, and we may have operating subsidiaries that conduct
business in other states in the future. Maintenance of our
limited liability as an owner of our operating subsidiary may
require compliance with legal requirements in the jurisdictions
in which our operating subsidiary conducts business, including
qualifying our operating subsidiary to do business there.
Limitations on the liability of members or limited partners for
the obligations of a limited liability company or limited
partnership have not been clearly established in many
jurisdictions. If, by virtue of our ownership in our subsidiary
or otherwise, it were determined that we were conducting
business in any state without compliance with the applicable
limited partnership or limited liability company statute, or
that the right or exercise of the right by our limited partners
as a group to remove or replace our general partner, to approve
some amendments to our partnership agreement, or to take other
action under our partnership agreement constituted
participation in the control of our business for
purposes of the statutes of any relevant jurisdiction, then our
limited partners could be held personally liable for our
obligations under the law of that jurisdiction to the same
extent as our general partner under the circumstances. We will
operate in a manner that our general partner considers
reasonable and necessary or appropriate to preserve the limited
liability of our limited partners.
Issuance
of Additional Interests
Our partnership agreement authorizes us to issue an unlimited
number of additional partnership interests and options, rights,
warrants, restricted units, appreciation rights, phantom or
tracking interests or other economic interests in us or in our
securities for the consideration and on the terms and conditions
determined by our general partner without the approval of our
unitholders.
It is possible that we will fund acquisitions through the
issuance of additional common units or other partnership
interests. Holders of any additional common units we issue will
be entitled to share equally with the then-existing holders of
common units in our distributions of available cash. In
addition, the issuance of additional common units or other
partnership interests may dilute the value of the interests of
the then-existing holders of common units in our net assets.
In accordance with Delaware law and the provisions of our
partnership agreement, we may also issue additional partnership
interests that, as determined by our general partner, may have
special voting rights to which the common units are not
entitled. In addition, our partnership
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agreement does not prohibit the issuance by our subsidiary of
equity interests, which may effectively rank senior to our
common units.
If we issue additional partnership interests (other than the
issuance of common units upon exercise by the underwriters of
their option to purchase additional common units, the issuance
of common units to the Contributing Parties upon expiration of
the underwriters option to purchase additional common
units or the issuance of partnership interests upon conversion
of any outstanding partnership interests that may be converted
into common units), our general partner will be entitled, but
not required, to make additional capital contributions to the
extent necessary to maintain its 2.0% general partner interest
in us. Our general partners 2.0% general partner interest
in us will be reduced if we complete any such issuance of
partnership interests in the future and our general partner does
not contribute a proportionate amount of capital to us to
maintain its 2.0% general partner interest in us. Moreover, our
general partner will have the right, which it may from time to
time assign in whole or in part to any of its affiliates, to
purchase common units or other partnership interests whenever,
and on the same terms that, we issue those interests to persons
other than our general partner and its affiliates, to the extent
necessary to maintain the aggregate percentage interest in us of
our general partner and its affiliates, including such interest
represented by common units or other partnership interests, that
existed immediately prior to each issuance. The holders of
common units will not have preemptive rights to acquire
additional common units or other partnership interests.
Amendment
of the Partnership Agreement
General
Amendments to our partnership agreement may be proposed only by
our general partner. However, our general partner will have no
duty or obligation to propose any amendment and may decline to
do so free of any fiduciary duty or obligation whatsoever to us
or our limited partners, including any duty to act in good faith
and in the best interests of us or our limited partners. To
adopt a proposed amendment, other than the amendments discussed
below under No Unitholder Approval, our
general partner is required to seek written approval of the
holders of the number of units required to approve the amendment
or call a meeting of our limited partners to consider and vote
upon the proposed amendment. Except as described below, an
amendment must be approved by a unit majority.
Prohibited Amendments
No amendment may:
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enlarge the obligations of any limited partner without its
consent, unless approved by at least a majority of the type or
class of limited partner interests so affected; or
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enlarge the obligations of, restrict, change or modify in any
way any action by or rights of, or reduce in any way the amounts
distributable, reimbursable or otherwise payable by us to our
general partner or any of its affiliates without the consent of
our general partner, which consent may be given or withheld in
its sole discretion.
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The provision of our partnership agreement preventing the
amendments having the effects described in any of the clauses
above can be amended upon the approval of the holders of at
least 90% of the outstanding units (including units owned by our
general partner, our general partners affiliates
(including the Founders) and Yorktown) or upon receipt of a
written opinion of counsel acceptable to our general partner to
the effect that such amendment will not affect the limited
liability of any limited partner under the Delaware Act. Upon
the consummation of this offering, affiliates of our general
partner (including the Founders) and Yorktown will own an
aggregate of approximately 58.6% of our outstanding common units.
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No Unitholder Approval
Our general partner may generally make amendments to our
partnership agreement without the approval of any limited
partner to reflect:
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a change in our name, the location of our principal place of
business, our registered agent or our registered office;
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the admission, substitution, withdrawal or removal of partners
in accordance with our partnership agreement;
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a change that our general partner determines to be necessary or
appropriate for us to qualify or to continue our qualification
as a limited partnership or other entity in which the limited
partners have limited liability under the laws of any state or
to ensure that neither we, nor our subsidiary will be treated as
an association taxable as a corporation or otherwise taxed as an
entity for federal income tax purposes;
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a change in our fiscal year or taxable period and related
changes;
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an amendment that is necessary, in the opinion of our counsel,
to prevent us or our general partner or the directors, officers,
agents or trustees of our general partner from in any manner
being subjected to the provisions of the Investment Company Act
of 1940, as amended, the Investment Advisers Act of 1940, as
amended, or plan asset regulations adopted under the
Employee Retirement Income Security Act of 1974, as amended, or
ERISA, regardless of whether such are substantially similar to
plan asset regulations currently applied or proposed by the U.S.
Department of Labor;
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an amendment that our general partner determines to be necessary
or appropriate for the creation, authorization or issuance of
any class or series of additional partnership securities or
options, rights, warrants, restricted units, appreciation
rights, tracking or phantom interests or other economic
interests in the partnership relating to our securities;
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any amendment expressly permitted in our partnership agreement
to be made by our general partner acting alone;
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an amendment effected, necessitated or contemplated by a merger
agreement that has been approved under the terms of our
partnership agreement;
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any amendment that our general partner determines to be
necessary or appropriate to reflect and account for the
formation by us of, or our investment in, any corporation,
partnership, limited liability company, joint venture or other
entity, as otherwise permitted by our partnership agreement;
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conversions into, mergers with or conveyances to another limited
liability entity that is newly formed and has no assets,
liabilities or operations at the time of the conversion, merger
or conveyance other than those it receives by way of the
conversion, merger or conveyance subject in each case to certain
restrictions; or
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any other amendments substantially similar to any of the matters
described in the clauses above.
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In addition, our general partner may make amendments to our
partnership agreement without the approval of any limited
partner if our general partner determines that those amendments:
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do not adversely affect our limited partners (or any particular
class of limited partners) in any material respect;
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are necessary or appropriate to satisfy any requirements,
conditions or guidelines contained in any opinion, directive,
order, ruling or regulation of any federal or state agency or
judicial authority or contained in any federal or state statute;
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are necessary or appropriate to facilitate the trading of our
units or to comply with any rule, regulation, guideline or
requirement of any securities exchange on which any class of our
partnership interests is or will be listed for trading;
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are necessary or appropriate for any action taken by our general
partner relating to splits or combinations of units under the
provisions of our partnership agreement; or
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are required to effect the intent expressed in this prospectus
or the intent of the provisions of our partnership agreement or
are otherwise contemplated by our partnership agreement.
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Opinion of Counsel and Unitholder Approval
Our general partner will not be required to obtain an opinion of
counsel that an amendment will not result in a loss of limited
liability to our limited partners or result in our being treated
as an association taxable as a corporation or otherwise taxable
as an entity for federal income tax purposes in connection with
any of the amendments described above under No
Unitholder Approval. No other amendments to our
partnership agreement will become effective without the approval
of holders of at least 90% of the outstanding units unless we
first obtain an opinion of counsel to the effect that the
amendment will not affect the limited liability under Delaware
law of any of our limited partners.
In addition to the above restrictions, any amendment that would
have a material adverse effect on the rights or preferences of
any type or class of outstanding units in relation to other
classes of units will require the approval of at least a
majority of the type or class of units so affected, but no vote
will be required by any class or classes or type or types of
limited partners that our general partner determines are not
adversely affected in any material respect. Any amendment that
reduces the voting percentage required to take any action other
than to remove the general partner or call a meeting of
unitholders must be approved by the affirmative vote of partners
holding aggregate partnership interests constituting not less
than the voting requirement sought to be reduced. Any amendment
that would increase the percentage of units required to remove
the general partner or call a meeting of unitholders must be
approved by the affirmative vote of limited partners whose
aggregate outstanding units constitute not less than the
percentage sought to be increased.
Merger,
Consolidation, Sale or Other Disposition of Assets
A merger or consolidation of us requires the prior consent of
our general partner. However, our general partner will have no
duty or obligation to consent to any merger or consolidation and
may decline to do so free of any duty (including any fiduciary
duty) or obligation whatsoever to us or our limited partners,
including any duty to act in good faith and in the best interest
of us or our limited partners.
In addition, our partnership agreement generally prohibits our
general partner, without the prior approval of the holders of a
unit majority, from causing us, among other things, to sell,
exchange or otherwise dispose of all or substantially all of our
and our subsidiarys assets (taken as a whole) in a single
transaction or a series of related transactions, including by
way of merger, consolidation or other combination or sale of
ownership interests of our subsidiary. Our general partner may,
however, mortgage, pledge, hypothecate or grant a security
interest in all or substantially all of our assets without such
approval. Our general partner may also sell all or substantially
all of our assets under a foreclosure or other realization upon
those encumbrances without such approval. Finally, our general
partner may consummate any merger or consolidation without the
prior approval of our unitholders if we are the surviving entity
in the transaction, our general partner has received an opinion
of counsel regarding limited liability and tax matters, the
merger or consolidation will not result in a material amendment
to our partnership agreement (other than an amendment that the
general partner could adopt without the consent of other
partners), each of our partnership interests outstanding
immediately prior to the merger or consolidation will be an
identical partnership interest of our partnership following
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the transaction, and the number partnership interests to be
issued in such merger or consolidation does not exceed 20% of
our outstanding partnership interests immediately prior to the
effective date of such merger or consolidation.
If the conditions specified in our partnership agreement are
satisfied, our general partner may convert us or our subsidiary
into a new limited liability entity or merge us or our
subsidiary into, or convey all of our assets to, a newly formed
entity that has no assets, liabilities or operations at the time
of such conversion, merger or conveyance, if the sole purpose of
that conversion, merger or conveyance is to effect a mere change
in our legal form into another limited liability entity, our
general partner has received an opinion of counsel regarding
limited liability and tax matters, and the governing instruments
of the new entity provide our limited partners and our general
partner with substantially the same rights and obligations as
contained in our partnership agreement. The unitholders are not
entitled to dissenters rights of appraisal under our
partnership agreement or applicable Delaware law in the event of
a conversion, merger or consolidation, a sale of substantially
all of our assets or any other similar transaction or event.
Dissolution
We will continue as a limited partnership until dissolved under
our partnership agreement. We will dissolve upon:
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the election of our general partner to dissolve us, if approved
by the holders of a unit majority;
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there being no limited partners, unless we are continued without
dissolution in accordance with the Delaware Act;
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the entry of a decree of judicial dissolution of our partnership
pursuant to the provisions of the Delaware Act; or
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the withdrawal or removal of our general partner or any other
event that results in its ceasing to be our general partner,
other than by reason of a transfer of its general partner
interest in us in accordance with our partnership agreement,
unless a successor general partner is elected and admitted
pursuant to our partnership agreement.
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Upon a dissolution under the last clause above, the holders of a
unit majority may also elect, within specific time limitations,
to continue our business on the same terms and conditions
described in our partnership agreement by appointing as a
successor general partner an entity approved by the holders of a
unit majority, subject to our receipt of an opinion of counsel
to the effect that:
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the exercise of the right would not result in the loss of
limited liability under the Delaware Act of any limited
partner; and
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neither our partnership nor our subsidiary would be treated as
an association taxable as a corporation or otherwise be taxable
as an entity for U.S. federal income tax purposes upon the
exercise of that right to continue (to the extent not already so
treated or taxed).
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Liquidation
and Distribution of Proceeds
Upon our dissolution, unless our business is continued, the
liquidator authorized to wind up our affairs will, acting with
all of the powers of our general partner that are necessary or
appropriate, liquidate our assets and apply the proceeds of the
liquidation as described in Provisions of Our Partnership
Agreement Relating to Cash DistributionsDistributions of
Cash Upon Liquidation. The liquidator may defer
liquidation or distribution of our assets for a reasonable
period of time or distribute assets to partners in kind if it
determines that a sale would be impractical or would cause undue
loss to our partners.
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Withdrawal
or Removal of Our General Partner
Except as described below, our general partner has agreed not to
withdraw voluntarily as our general partner prior to
December 31, 2021 without obtaining the approval of the
holders of at least a majority of our outstanding common units,
excluding common units held by our general partner and its
affiliates (including the Founders), and furnishing an opinion
of counsel regarding limited liability and tax matters. On or
after December 31, 2021, our general partner may withdraw
as our general partner without first obtaining approval of any
unitholder by giving at least 90 days written notice,
and that withdrawal will not constitute a violation of our
partnership agreement. Notwithstanding the information above,
our general partner may withdraw as our general partner without
unitholder approval upon 90 days notice to our
limited partners if at least 50% of the outstanding common units
are held or controlled by one person and its affiliates other
than our general partner and its affiliates (including the
Founders). In addition, subject to the restrictions set forth in
our partnership agreement, on or after December 31, 2021,
our general partner may sell or otherwise transfer all of its
general partner interest in us without the approval of the
unitholders. Please read Transfer of General Partner
Interest.
Upon withdrawal of our general partner under any circumstances,
other than as a result of a transfer by our general partner of
all or a part of its general partner interest in us, the holders
of a unit majority may, prior to the effective date of such
withdrawal, elect a successor to the withdrawing general
partner. If a successor is not elected, or is elected but an
opinion of counsel regarding limited liability and tax matters
is not obtained, we will be dissolved, wound up and liquidated,
unless within a specified period of time after that withdrawal,
the holders of a unit majority agree in writing to continue our
business and to appoint a successor general partner. Please read
Dissolution.
Our general partner may not be removed unless that removal is
approved by the vote of the holders of not less than
662/3%
of our outstanding units, including units held by our general
partner, our general partners affiliates (including the
Founders) and Yorktown, and we receive an opinion of counsel
regarding limited liability and tax matters. Any removal of our
general partner is also subject to the approval of a successor
general partner by the vote of the holders of a majority of our
outstanding common units, voting as a separate class. The
ownership of more than
331/3%
of our outstanding units by our general partner, our general
partners affiliates (including the Founders) and Yorktown
would give them the practical ability to prevent our general
partners removal. Upon the consummation of this offering,
affiliates of our general partner (including the Founders) and
Yorktown will own an aggregate of approximately 58.6% of our
outstanding common units.
Our partnership agreement also provides that if our general
partner is removed as our general partner under circumstances
where cause does not exist our general partner will have the
right to convert its general partner interest into common units
or to receive cash in exchange for those interests based on the
fair market value of the interests at the time.
In the event of removal of our general partner under
circumstances where cause exists or withdrawal of our general
partner where that withdrawal violates our partnership
agreement, a successor general partner will have the option to
purchase the departing general partners general partner
interest for a cash payment equal to the fair market value of
those interests. Under all other circumstances where our general
partner withdraws or is removed by the limited partners, the
departing general partner will have the option to require the
successor general partner to purchase the general partner
interest of the departing general partner for fair market value.
In each case, this fair market value will be determined by
agreement between the departing general partner and the
successor general partner. If no agreement is reached within the
period provided under our partnership agreement, an independent
investment banking firm or other independent expert selected by
the departing general partner and the successor general partner
will determine the fair market value. If the departing general
partner and the successor general partner cannot agree upon one
independent investment banking firm or other
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independent expert, then an independent investment banking firm
or other independent expert chosen by agreement of the
independent investment banking firm or other independent expert
selected by each of them will determine the fair market value.
If the option described above is not exercised by either the
departing general partner or the successor general partner, the
departing general partner will become a limited partner and such
general partner interest will automatically convert into common
units equal to the fair market value of those interests as
determined by an investment banking firm or other independent
expert selected in the manner described in the preceding
paragraph.
In addition, we will be required to reimburse the departing
general partner for all amounts due the departing general
partner, including, without limitation, all employee-related
liabilities, including severance liabilities, incurred for the
termination of any employees employed by the departing general
partner or its affiliates for our benefit.
Transfer
of General Partner Interest
Except for the transfer by our general partner of all, but not
less than all, of its general partner interest to:
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an affiliate of our general partner (other than an
individual); or
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another entity as part of the merger or consolidation of our
general partner with or into another entity or the transfer by
our general partner of all or substantially all of its assets to
another entity,
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our general partner may not transfer all or any part of its
general partner interest to another person prior to
December 31, 2021, without the approval of the holders of
at least a majority of our outstanding common units, excluding
common units held by our general partner and its affiliates
(including the Founders). As a condition of this transfer, the
transferee must agree to purchase all (or the appropriate
portion thereof, if applicable) of the partnership or membership
interests held by our general partner as the general partner or
managing member, if any, of us or our subsidiary and must
assume, among other things, the rights and duties of our general
partner, agree to be bound by the provisions of our partnership
agreement, and furnish an opinion of counsel regarding limited
liability and tax matters.
Our general partner, our general partners affiliates
(including the Founders) and Yorktown may at any time transfer
common units to one or more persons without unitholder approval.
Transfer
of Ownership Interests in Our General Partner
At any time, the members of our general partner may sell or
transfer all or part of their membership interests in our
general partner to an affiliate or a third party without the
approval of our unitholders.
Change of
Management Provisions
Our partnership agreement contains specific provisions that are
intended to discourage a person or group from attempting to
remove our general partner or otherwise change the management of
our general partner. If any person or group other than our
general partner, its affiliates (including the Founders) and
Yorktown acquires beneficial ownership of 20% or more of any
class of units, that person or group loses voting rights with
respect to all of such partnership interests. This loss of
voting rights does not apply to any person or group that
acquires partnership interests directly from our general partner
or its affiliates and any transferees of that person or group
approved by our general partner or to any person or group who
acquires partnership interests with the prior approval of the
board of directors of our general partner.
If our general partner is removed without cause, our partnership
agreement provides that, among other things, our general partner
will have the right to convert its general partner interest into
common units or receive cash in exchange for those interests.
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Limited
Call Right
If at any time our general partner and its affiliates (including
the Founders) own more than 80% of our then-issued and
outstanding limited partner interests of any class, our general
partner will have the right, which it may assign and transfer in
whole or in part to any of its affiliates or to us, to purchase
all, but not less than all, of the limited partner interests of
the class held by unaffiliated persons as of a record date to be
selected by our general partner, on at least 10 but not more
than 60 days notice. The purchase price in the event
of this purchase is the greater of:
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the highest cash price paid by our general partner or any of its
affiliates for any limited partner interests of such class
purchased within the 90 days preceding the date on which
our general partner first mails notice of its election to
purchase such limited partner interests; and
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the average of the daily closing prices of the limited partner
interests of such class over the 20 trading days preceding the
date three days before the date the notice is mailed.
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As a result of our general partners right to purchase
outstanding limited partner interests, a holder of limited
partner interests may have his limited partner interests
purchased at an undesirable time or price. The federal income
tax consequences to a unitholder of the exercise of this call
right are the same as a sale by that unitholder of his common
units in the market. Please read Material Tax
ConsequencesDisposition of Units.
Meetings;
Voting
Except as described below regarding a person or group owning 20%
or more of any class of partnership interests then outstanding,
record holders of limited partner interests on the record date
will be entitled to notice of, and to vote at, meetings of our
limited partners and to act upon matters for which approvals may
be solicited. Units that are owned by non-citizens or other
ineligible holders will be voted by our general partner and our
general partner will cast the votes on those units in the same
ratios as the votes of limited partners on other units are cast.
Please read Non-Citizen Unitholders; Redemption for
additional information concerning the citizenship, nationality,
and related status requirements for owning our common units.
Our general partner does not anticipate that any meeting of
unitholders will be called in the foreseeable future. If
authorized by our general partner, any action that is required
or permitted to be taken by the unitholders may be taken either
at a meeting of the unitholders or without a meeting if an
approval in writing or by electronic transmission is signed or
transmitted by holders of not less than the number of units
necessary to authorize or take that action at a meeting.
Meetings of the unitholders may be called by our general partner
or by unitholders owning at least 20% of the outstanding units
of the class for which a meeting is proposed. Unitholders may
vote either in person or by proxy at meetings. The holders of a
majority of the outstanding units of the class or classes for
which a meeting has been called, represented in person or by
proxy, will constitute a quorum unless any action by the
unitholders requires approval by holders of a greater percentage
of the units, in which case the quorum will be the greater
percentage.
Each record holder of a unit has a vote according to his
percentage interest in us, although additional limited partner
interests having special voting rights could be issued. Please
read Issuance of Additional Interests.
However, if at any time any person or group, other than our
general partner and its affiliates (including the Founders) or a
direct or subsequently approved transferee of our general
partner or its affiliates and specifically approved by our
general partner, acquires, in the aggregate, beneficial
ownership of 20% or more of any class of partnership interests
then outstanding, that person or group will lose voting rights
with respect to all of such partnership interests and the units
may not be voted on any matter and will not be considered to be
outstanding when sending notices of a meeting of unitholders,
calculating required votes or, determining the presence of a
quorum or for other similar purposes. Common units held in
nominee or street name account will be
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voted by the broker or other nominee in accordance with the
instruction of the beneficial owner unless the arrangement
between the beneficial owner and his nominee provides otherwise.
Any notice, demand, request, report or proxy material required
or permitted to be given or made to record holders of common
units under our partnership agreement will be delivered to the
record holder by us or by the transfer agent.
Status as
Limited Partner
Upon a transfer of any common units in accordance with our
partnership agreement, each transferee of common units shall be
admitted as a limited partner with respect to the common units
transferred when such transfer and admission is reflected in our
books and records and such limited partner becomes the record
holder of the common units so transferred. Except as described
under Limited Liability, the common
units will be fully paid, and unitholders will not be required
to make additional contributions.
Non-Citizen
Unitholders; Redemption
We may acquire interests in oil and natural gas leases on United
States federal lands in the future. To comply with certain
U.S. laws relating to the ownership of interests in oil and
natural gas leases on federal lands, our general partner, acting
on our behalf, may request any unitholder to furnish to the
general partner within 30 days of the request a properly
completed certificate certifying as to the unitholders
nationality, citizenship or other related status. If, following
a request by our general partner, a unitholder fails to furnish
such certification within the
30-day
period or if the general partner determines, with the advice of
counsel, that the unitholders nationality, citizenship or
other related status would create a substantial risk of
cancellation or forfeiture of property in which the we have an
interest, we will have the right to redeem the units held by
such unitholder. Further, the units held by such unitholder will
not be entitled to any voting rights. The redemption price will
be paid in cash or delivery of a promissory note, as determined
by our general partner. If our general partner chooses to redeem
the units in cash, the redemption price will be the average of
the daily closing prices per unit for the 20 consecutive trading
days immediately prior to the date set for redemption. If our
general partner chooses to redeem the units with a promissory
note, the promissory note will bear interest at the rate of 5%
annually and be payable in three equal annual installments of
principal and accrued interest, commencing one year after the
redemption date.
For the avoidance of doubt, onshore mineral leases or any direct
or indirect interest therein may be acquired and held by aliens
only through stock ownership, holding or control in a
corporation organized under the laws of the United States or of
any state thereof.
Indemnification
Under our partnership agreement, in most circumstances, we will
indemnify the following persons, to the fullest extent permitted
by law, from and against all losses, claims, damages or similar
events whether civil, criminal, administrative or investigative,
and whether formal or informal and including appeals:
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our general partner;
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any departing general partner;
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any person who is or was an affiliate of our general partner or
any departing general partner;
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any person who is or was a director, officer, employee, agent,
manager, managing member, partner, fiduciary or trustee of us,
our subsidiary or any entity set forth in the preceding three
bullet points;
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any person who is or was serving at the request of a general
partner, any departing general partner, or any affiliate of us
or our subsidiary, as a director, officer, employee,
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agent, manager, managing member, general partner, fiduciary or
trustee of another person owing a fiduciary duty to us or our
subsidiary;
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any person who controls our general partner or any departing
general partner; and
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any person designated by our general partner.
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Any indemnification under these provisions will only be out of
our assets. Unless it otherwise agrees, our general partner will
not be personally liable for, or have any obligation to
contribute or lend funds or assets to us to enable us to
effectuate, indemnification. We may purchase insurance covering
liabilities asserted against and expenses incurred by persons
for our activities, regardless of whether we would have the
power to indemnify the person against liabilities under our
partnership agreement.
Reimbursement
of Expenses
Our partnership agreement requires us to reimburse our general
partner for all direct and indirect expenses it incurs or
payments it makes on behalf of us or our subsidiary and all
other expenses allocable to us or otherwise incurred by our
general partner in connection with operating our business. Our
partnership agreement does not set a limit on the amount of
expenses for which our general partner and its affiliates,
including Mid-Con Energy Operating, may be reimbursed. These
expenses include salary, bonus, incentive compensation,
employment benefits, and other amounts paid to persons who
perform services for us or on our behalf, and expenses allocated
to our general partner by its affiliates. Our general partner is
entitled to determine in good faith the expenses that are
allocable to us.
Books and
Reports
Our general partner is required to keep appropriate books and
records of our business at our principal offices. The books will
be maintained for both tax and financial reporting purposes on
an accrual basis in accordance with GAAP. For financial
reporting and tax purposes, our fiscal year end is
December 31.
We will furnish or make available to record holders of common
units, within 100 days after the close of each fiscal year,
an annual report containing audited financial statements,
including a balance sheet and statements of operations,
partnership equity and cash flows and a report on those
financial statements by our independent registered public
accounting firm. Except for our fourth quarter, we will also
furnish or make available within 50 days after the close of each
quarter, a report containing unaudited financial statements and
such other information as may be received by applicable law,
regulation or NASDAQ Global Market rule, or as our general
partner determines to be necessary or appropriate.
Our general partner will be deemed to have made a report
available if it has either filed such report with the SEC and
such report is publicly available or made such report available
on any publicly available website maintained by us.
The tax information reasonably required for federal, state and
local income tax reporting purposes will be furnished within 90
days of the close of the calendar year in which our taxable
period ends.
Right to
Inspect Our Books and Records
Our partnership agreement provides that a limited partner can,
for a purpose reasonably related to his interest as a limited
partner, upon reasonable written demand stating the purpose of
such demand and at his own expense, obtain:
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a current list of the name and last known address of each record
holder;
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copies of our partnership agreement, our certificate of limited
partnership and related amendments if such documents are not
available on the SECs website;
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true and full information regarding the status of our business
and financial condition (provided that these requirements will
be satisfied to the extent the limited partner is furnished our
most recent annual report any subsequent quarterly or periodic
reports required to be filed with the SEC pursuant to Section 13
of the Exchange Act); and
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any other information regarding our affairs as our general
partner determines in its sole discretion is just and reasonable.
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Our general partner may, and intends to, keep confidential from
the limited partners trade secrets or other information
the disclosure of which our general partner believes in good
faith is not in our best interests or that we are required by
law or by agreements with third parties to keep confidential.
Registration
Rights
Under our partnership agreement, our general partner and its
affiliates (including the Founders) have the right to cause us
to register for resale under the Securities Act and applicable
state securities laws any common units or other partnership
interests proposed to be sold by our general partner or any of
its affiliates or their assignees if an exemption from the
registration requirements is not otherwise available. In
addition, our general partner and its affiliates (including the
Founders) have the right to include such securities in a
registration by us or any other unitholder, subject to customary
exceptions. These registration rights continue for two years
following the withdrawal or removal of our general partner and
for so long as is required for the holder to sell all of the
partnership interests with respect to which it has requested
registration during such two-year period. In addition, we are
restricted from granting any superior piggyback registration
rights during this two-year period. We will pay all expenses
incidental to the registration, excluding underwriting fees and
discounts. In connection with any registration of this kind, we
will indemnify the unitholders participating in the registration
and their officers, directors and controlling persons from and
against specified liabilities, including under the Securities
Act or any applicable state securities laws. Please read
Units Eligible for Future Sale.
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UNITS
ELIGIBLE FOR FUTURE SALE
After the sale of the common units offered hereby, the Founders,
Yorktown and the other Contributing Parties will hold an
aggregate of 12,240,000 common units. The sale of these
units could have an adverse impact on the price of the common
units or on any trading market that may develop.
The common units sold in this offering will generally be freely
transferable without restriction or further registration under
the Securities Act, except that any common units owned by an
affiliate of ours may not be resold publicly except
in compliance with the registration requirements of the
Securities Act or under an exemption under Rule 144 or
otherwise. Rule 144 permits securities acquired by an
affiliate of the issuer to be sold into the market in an amount
that does not exceed, during any three-month period, the greater
of:
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1.0% of the total number of the securities outstanding; or
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the average weekly reported trading volume of the common units
for the four calendar weeks prior to the sale.
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Sales under Rule 144 are also subject to specific manner of
sale provisions, holding period requirements, notice
requirements and the availability of current public information
about us. A unitholder who is not deemed to have been an
affiliate of ours at any time during the three months preceding
a sale, and who has beneficially owned his common units for at
least six months (provided we are in compliance with the current
public information requirement) or one year (regardless of
whether we are in compliance with the current public information
requirement), would be entitled to sell his common units under
Rule 144 without regard to the rules public
information requirements, volume limitations, manner of sale
provisions and notice requirements.
Our partnership agreement does not restrict our ability to issue
any partnership interests. Any issuance of additional common
units or other equity interests would result in a corresponding
decrease in the proportionate ownership interest in us
represented by, and could adversely affect the cash
distributions to and market price of, our common units then
outstanding. Please read The Partnership
AgreementIssuance of Additional Interests.
Under our partnership agreement, our general partner and its
affiliates, including the Founders, have the right to cause us
to register under the Securities Act and applicable state
securities laws the offer and sale of any common units or other
partnership interests that they hold, which we refer to as
registerable securities. Subject to the terms and conditions of
our partnership agreement, these registration rights allow our
general partner and its affiliates or their assignees holding
any registerable securities to require registration of such
registerable securities and to include any such registerable
securities in a registration by us of common units or other
partnership interests, including common units or other
partnership interests offered by us or by any unitholder. Our
general partner and its affiliates will continue to have these
registration rights for two years following the withdrawal or
removal of our general partner. In connection with any
registration of units held by our general partner or its
affiliates, we will indemnify each unitholder participating in
the registration and its officers, directors, and controlling
persons from and against any liabilities under the Securities
Act or any applicable state securities laws arising from the
registration statement or prospectus. We will bear all costs and
expenses incidental to any registration, excluding any
underwriting discounts. Except as described below, our general
partner and its affiliates may sell their common units or other
partnership interests in private transactions at any time,
subject to compliance with certain conditions and applicable
laws.
We, our general partner and certain of its affiliates and the
directors and executive officers of our general partner have
agreed, subject to certain exceptions, not to sell any common
units for a period of 180 days from the date of this
prospectus. For a description of these
lock-up
provisions, please read Underwriting.
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MATERIAL
TAX CONSEQUENCES
This section is a summary of the material U.S. federal
income, state and local tax consequences that may be relevant to
prospective unitholders and, unless otherwise noted in the
following discussion, is the opinion of Andrews Kurth LLP
insofar as it describes legal conclusions with respect to
matters of U.S. federal income tax law. Such statements are
based on the accuracy of the representations made by our general
partner and us to Andrews Kurth LLP, and statements of fact do
not represent opinions of Andrews Kurth LLP. To the extent this
section discusses U.S. federal income taxes, that
discussion is based upon current provisions of the Internal
Revenue Code of 1986, as amended (the Internal Revenue
Code), existing and proposed Treasury regulations
promulgated thereunder (the Treasury Regulations),
and current administrative rulings and court decisions, all of
which are subject to change. Changes in these authorities may
cause the tax consequences to vary substantially from the
consequences described below. Unless the context otherwise
requires, references in this section to us or
we are references to Mid-Con Energy Partners, LP and
our subsidiary.
This section does not address all U.S. federal, state and
local tax matters that affect us or our unitholders. To the
extent that this section relates to taxation by a state, local
or other jurisdiction within the United States, such discussion
is intended to provide only general information. We have not
sought the opinion of legal counsel regarding U.S. state,
local or other taxation and, thus, any portion of the following
discussion relating to such taxes does not represent the opinion
of Andrews Kurth LLP or any other legal counsel. Furthermore,
this section focuses on unitholders who are individual citizens
or residents of the United States, whose functional currency is
the U.S. dollar and who hold common units as a capital
asset (generally, property that is held as an investment). This
section has only limited application to corporations,
partnerships (and entities treated as partnerships for
U.S. federal income tax purposes), estates, trusts,
non-resident aliens or other unitholders subject to specialized
tax treatment, such as tax-exempt institutions,
non-U.S. persons,
individual retirement accounts, employee benefit plans, real
estate investment trusts or mutual funds. Accordingly, we
encourage each prospective unitholder to consult such
unitholders own tax advisor in analyzing the
U.S. federal, state, local and
non-U.S. tax
consequences particular to that unitholder resulting from his
ownership or disposition of his common units.
No ruling has been or will be requested from the Internal
Revenue Service (the IRS) regarding any matter that
affects us or our unitholders. Instead, we will rely on opinions
and advice of Andrews Kurth LLP. Unlike a ruling, an opinion of
counsel represents only that counsels best legal judgment
and does not bind the IRS or the courts. Accordingly, the
opinions and statements made herein may not be sustained by a
court if contested by the IRS. Any contest of this sort with the
IRS may materially and adversely impact the market for our
common units and the prices at which such common units trade. In
addition, the costs of any contest with the IRS, principally
legal, accounting and related fees, will result in a reduction
in cash available for distribution to our unitholders and our
general partner and thus will be borne indirectly by our
unitholders and our general partner. Furthermore, our tax
treatment, or the tax treatment of an investment in us, may be
significantly modified by future legislative or administrative
changes or court decisions. Any modifications may or may not be
retroactively applied.
For the reasons described below, Andrews Kurth LLP has not
rendered an opinion with respect to the following specific
U.S. federal income tax issues: (1) the treatment of a
unitholder whose common units are loaned to a short seller to
cover a short sale of common units (please read Tax
Consequences of Unit OwnershipTreatment of Short
Sales); (2) whether our monthly convention for
allocating taxable income and losses is permitted by existing
Treasury Regulations (please read Disposition of
UnitsAllocations Between Transferors and
Transferees); and (3) whether our method for
depreciating Section 743 adjustments is sustainable in
certain cases (please read Tax Consequences of Unit
OwnershipSection 754 Election and
Uniformity of Units).
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Taxation
of Mid-Con Energy Partners, LP
Partnership Status
We will be treated as a partnership for U.S. federal income
tax purposes and, therefore, generally will not be liable for
U.S. federal income taxes. Instead, each of our unitholders
will be required to take into account his respective share of
our items of income, gain, loss and deduction in computing his
U.S. federal income tax liability as if the unitholder had
earned such income directly, even if no cash distributions are
made to the unitholder. Distributions by us to a unitholder
generally will not be taxable to the unitholder unless the
amount of cash distributed to the unitholder exceeds the
unitholders tax basis in his common units.
Section 7704 of the Internal Revenue Code provides that
publicly traded partnerships will, as a general rule, be taxed
as corporations. However, an exception, referred to as the
Qualifying Income Exception, exists with respect to
publicly traded partnerships of which 90% or more of the gross
income for every taxable year consists of qualifying
income. Qualifying income includes income and gains
derived from exploration and production of certain natural
resources, including oil, natural gas, and products thereof.
Other types of qualifying income include interest (other than
from a financial business), dividends, gains from the sale of
real property and gains from the sale or other disposition of
capital assets held for the production of income that otherwise
constitutes qualifying income. We estimate that less than 5% of
our current gross income is not qualifying income; however, this
estimate could change from time to time. Based upon and subject
to this estimate, the factual representations made by us and our
general partner, and a review of the applicable legal
authorities, Andrews Kurth LLP is of the opinion that at least
90% of our current gross income constitutes qualifying income.
The portion of our income that is qualifying income may change
from time to time.
No ruling has been or will be sought from the IRS, and the IRS
has made no determination as to our status or the status of our
operating subsidiary for U.S. federal income tax purposes
or whether our operations generate qualifying income
under Section 7704 of the Internal Revenue Code. Instead,
we will rely on the opinion of Andrews Kurth LLP on such
matters. It is the opinion of Andrews Kurth LLP that we will be
classified as a partnership and our operating subsidiary will be
disregarded as an entity separate from us for U.S. federal
income tax purposes.
In rendering its opinion, Andrews Kurth LLP has relied on
factual representations made by us and our general partner. The
representations made by us and our general partner upon which
Andrews Kurth LLP has relied include, without limitation:
(a) neither we nor our operating subsidiary has elected or
will elect to be treated as a corporation; and
(b) for each taxable year, including short taxable years
occurring as a result of a constructive termination, more than
90% of our gross income has been and will be income that Andrews
Kurth LLP has opined or will opine is qualifying
income within the meaning of Section 7704(d) of the
Internal Revenue Code.
We believe that these representations have been true in the past
and expect that these representations will continue to be true
in the future.
If we fail to meet the Qualifying Income Exception, unless such
failure is determined by the IRS to be inadvertent and is cured
within a reasonable time after discovery (in which case the IRS
may also require us to make adjustments with respect to our
unitholders or pay other amounts), we will be treated as if we
had transferred all of our assets, subject to liabilities, to a
newly formed corporation, on the first day of the year in which
we failed to meet the Qualifying Income Exception, in return for
stock in that corporation and then distributed that stock to our
unitholders in liquidation of their interests in us. This deemed
contribution and liquidation should be tax-free to our
unitholders and us so long as we, at that time, do not have
liabilities in
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excess of the tax basis of our assets. Thereafter, we would be
treated as a corporation for U.S. federal income tax
purposes.
If we were taxed as a corporation for U.S. federal income
tax purposes in any taxable year, either as a result of a
failure to meet the Qualifying Income Exception or otherwise,
our items of income, gain, loss and deduction would be reflected
only on our tax return, rather than being passed through to our
unitholders, and our net income would be taxed to us at
corporate rates. In addition, any distribution made to a
unitholder would be treated as taxable dividend income, to the
extent of our current and accumulated earnings and profits, or,
in the absence of earnings and profits, a nontaxable return of
capital, to the extent of the unitholders tax basis in our
common units, or taxable capital gain, after the
unitholders tax basis in his common units is reduced to
zero. Accordingly, taxation as a corporation would result in a
material reduction in a unitholders cash flow and
after-tax return and thus would likely result in a substantial
reduction of the value of our common units.
The discussion below is based on Andrews Kurth LLPs
opinion that we will be classified as a partnership for
U.S. federal income tax purposes.
Tax
Consequences of Unit Ownership
Limited Partner Status
Unitholders who are admitted as limited partners of Mid-Con
Energy Partners, LP, as well as unitholders whose common units
are held in street name or by a nominee and who have the right
to direct the nominee in the exercise of all substantive rights
attendant to the ownership of common units, will be treated as
partners of Mid-Con Energy Partners, LP for U.S. federal
income tax purposes. A beneficial owner of common units whose
units have been transferred to a short seller to complete a
short sale would appear to lose his status as a partner with
respect to those units for U.S. federal income tax
purposes. Please read Treatment of Short
Sales. Unitholders who are not treated as partners in us
as described above are urged to consult their own tax advisors
with respect to the tax consequences applicable to them under
the circumstances.
The references to unitholders in the discussion that
follows are to persons who are treated as partners in Mid-Con
Energy Partners, LP for federal income tax purposes.
Flow-Through of Taxable Income
Subject to the discussion below under
Entity-Level Collections of Unitholder
Taxes, neither we nor our subsidiary will pay any
U.S. federal income tax. For U.S. federal income tax
purposes, each unitholder will be required to report on his
income tax return his share of our income, gains, losses and
deductions without regard to whether we make cash distributions
to such unitholder. Consequently, we may allocate income to a
unitholder even if that unitholder has not received a cash
distribution. Each unitholder will be required to include in
income his allocable share of our income, gains, losses and
deductions for his taxable year or years ending with or within
our taxable year. Our taxable year ends on December 31.
Treatment of Distributions
Distributions made by us to a unitholder generally will not be
taxable to the unitholder for federal income tax purposes,
except to the extent the amount of any such cash distribution
exceeds his tax basis in his common units immediately before the
distribution. Cash distributions made by us to a unitholder in
an amount in excess of the unitholders tax basis in his
common units generally will be considered to be gain from the
sale or exchange of those common units, taxable in accordance
with the rules described under Disposition of
Units below. Any reduction in a unitholders share of
our liabilities, including as a result of future issuances of
additional common units, will be treated as a distribution of
cash to that unitholder. To the
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extent that cash distributions made by us cause a
unitholders at risk amount to be less than
zero at the end of any taxable year, that unitholder must
recapture any losses deducted in previous years. Please read
Limitations on Deductibility of Losses.
A decrease in a unitholders percentage interest in us
because of our issuance of additional common units will decrease
his share of our nonrecourse liabilities, and thus will result
in a corresponding deemed distribution of cash. This deemed
distribution may constitute a non-pro rata distribution. A
non-pro rata distribution of money or property, including a
deemed distribution, may result in ordinary income to a
unitholder, regardless of that unitholders tax basis in
its common units, if the distribution reduces the
unitholders share of our unrealized
receivables, including depreciation recapture, depletion
recapture
and/or
substantially appreciated inventory items, both as
defined in Section 751 of the Internal Revenue Code, and
collectively, Section 751 Assets. To the extent
of such reduction, a unitholder will be treated as having
received his proportionate share of the Section 751 Assets
and then having exchanged those assets with us in return for an
allocable portion of the non-pro rata distribution made to such
unitholder. This latter deemed exchange generally will result in
the unitholders realization of ordinary income in an
amount equal to the excess of (1) the non-pro rata portion
of that distribution over (2) the unitholders tax
basis (generally zero) in the Section 751 Assets deemed
relinquished in the exchange.
Ratio of Taxable Income to Distributions
We estimate that a purchaser of common units in this offering
who owns those common units from the date of closing of this
offering through the record date for distributions for the
period ending December 31, 2014, will be allocated, on a
cumulative basis, an amount of federal taxable income for that
period that will be less than 40% of the cash distributed with
respect to that period. Thereafter, we anticipate that the ratio
of allocable taxable income to cash distributions to the
unitholders could substantially increase. These estimates are
based upon the assumption that gross income from operations will
approximate the amount required to make the initial quarterly
distribution on all common units and other assumptions with
respect to capital expenditures, cash flow, net working capital
and anticipated cash distributions. These estimates and
assumptions are subject to, among other things, numerous
business, economic, regulatory, legislative, competitive and
political uncertainties beyond our control. Further, the
estimates are based on current tax law and tax reporting
positions that we will adopt and with which the IRS could
disagree. Accordingly, we cannot assure our unitholders that
these estimates will prove to be correct. The actual percentage
of distributions that will constitute taxable income could be
higher or lower than expected, and any differences could be
material and could materially affect the value of the common
units. For example, the ratio of allocable taxable income to
cash distributions to a purchaser of common units in this
offering will be greater, and perhaps substantially greater,
than our estimate with respect to the period described above if:
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gross income from operations exceeds the amount required to pay
distributions at the initial quarterly distribution rate on all
common units, yet we only pay distributions at the initial
quarterly distribution rate on all common units; or
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we make a future offering of common units and use the proceeds
of the offering in a manner that does not produce substantial
additional deductions during the period described above, such as
to repay indebtedness outstanding at the time of this offering
or to acquire property that is not eligible for depreciation or
amortization for federal income tax purposes or that is
depreciable or amortizable at a rate significantly slower than
the rate applicable to our assets at the time of this offering.
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Basis of Units
A unitholders initial tax basis in his common units will
be the amount he paid for those common units plus his share of
our nonrecourse liabilities. That basis generally will be
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(i) increased by the unitholders share of our income
and by any increases in such unitholders share of our
nonrecourse liabilities, and (ii) decreased, but not below
zero, by distributions to him, by his share of our losses, by
depletion deductions taken by him to the extent such deductions
do not exceed his proportionate share of the adjusted tax basis
of the underlying properties, by any decreases in his share of
our nonrecourse liabilities and by his share of our expenditures
that are not deductible in computing taxable income and are not
required to be capitalized. A unitholder will have no share of
our debt that is recourse to our general partner, but will have
a share, generally, based on his share of our profits, of our
nonrecourse liabilities. Please read Disposition of
UnitsRecognition of Gain or Loss.
Limitations on Deductibility of Losses
The deduction by a unitholder of that unitholders share of
our losses will be limited to the lesser of (i) the tax
basis such unitholder has in his common units, and (ii) in
the case of an individual, estate, trust or corporate unitholder
(if more than 50% of the corporate unitholders stock is
owned directly or indirectly by or for five or fewer individuals
or some tax exempt organizations) to the amount for which the
unitholder is considered to be at risk with respect
to our activities. A unitholder subject to these limitations
must recapture losses deducted in previous years to the extent
that distributions cause the unitholders at risk amount to
be less than zero at the end of any taxable year. Losses
disallowed to a unitholder or recaptured as a result of these
limitations will carry forward and will be allowable as a
deduction in a later year to the extent that the
unitholders tax basis or at risk amount, whichever is the
limiting factor, is subsequently increased. Upon the taxable
disposition of a unit, any gain recognized by a unitholder can
be offset by losses that were previously suspended by the at
risk limitation but may not be offset by losses suspended by the
basis limitation. Any loss previously suspended by the at risk
limitation in excess of that gain would no longer be utilizable.
In general, a unitholder will be at risk to the extent of the
tax basis of the unitholders common units, excluding any
portion of that basis attributable to the unitholders
share of our nonrecourse liabilities, reduced by (1) any
portion of that basis representing amounts otherwise protected
against loss because of a guarantee, stop loss agreement or
other similar arrangement and (2) any amount of money the
unitholder borrows to acquire or hold his common units, if the
lender of those borrowed funds owns an interest in us, is
related to another unitholder or can look only to the common
units for repayment. A unitholders at risk amount will
increase or decrease as the tax basis of the unitholders
common units increases or decreases, other than tax basis
increases or decreases attributable to increases or decreases in
the unitholders share of our liabilities.
The at risk limitation applies on an
activity-by-activity
basis, and in the case of oil and natural gas properties, each
property is treated as a separate activity. Thus, a
taxpayers interest in each oil or natural gas property is
generally required to be treated separately so that a loss from
any one property would be limited to the at risk amount for that
property and not the at risk amount for all the taxpayers
oil and natural gas properties. It is uncertain how this rule is
implemented in the case of multiple oil and natural gas
properties owned by a single entity treated as a partnership for
federal income tax purposes. However, for taxable years ending
on or before the date on which further guidance is published,
the IRS will permit aggregation of oil or natural gas properties
we own in computing a unitholders at risk limitation with
respect to us. If a unitholder were required to compute his at
risk amount separately with respect to each oil or natural gas
property we own, he might not be allowed to utilize his share of
losses or deductions attributable to a particular property even
though he has a positive at risk amount with respect to his
common units as a whole.
In addition to the basis and at risk limitations on the
deductibility of losses, the passive loss limitations generally
provide that individuals, estates, trusts and some closely-held
corporations and personal service corporations may deduct losses
from passive activities, which are generally
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defined as trade or business activities in which the taxpayer
does not materially participate, only to the extent of the
taxpayers income from those passive activities. The
passive loss limitations are applied separately with respect to
each publicly-traded partnership. Consequently, any passive
losses we generate will only be available to offset our passive
income generated in the future and will not be available to
offset income from other passive activities or investments,
including our investments or a unitholders investments in
other publicly-traded partnerships, or a unitholders
salary or active business income. Passive losses that are not
deductible because they exceed a unitholders share of
income we generate may be deducted in full when he disposes of
his entire investment in us in a fully taxable transaction with
an unrelated party. The passive loss limitations are applied
after other applicable limitations on deductions, including the
at risk rules and the basis limitation.
A unitholders share of our net income may be offset by any
of our suspended passive losses, but it may not be offset by any
other current or carryover losses from other passive activities,
including those attributable to other publicly traded
partnerships.
Limitations on Interest Deductions
The deductibility of a non-corporate taxpayers
investment interest expense is generally limited to
the amount of that taxpayers net investment
income. Investment interest expense includes:
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interest on indebtedness properly allocable to property held for
investment;
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our interest expense attributed to portfolio income; and
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the portion of interest expense incurred to purchase or carry an
interest in a passive activity to the extent attributable to
portfolio income.
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The computation of a unitholders investment interest
expense will take into account interest on any margin account
borrowing or other loan incurred to purchase or carry a unit.
Net investment income includes gross income from property held
for investment and amounts treated as portfolio income under the
passive loss rules, less deductible expenses, other than
interest, directly connected with the production of investment
income, but generally does not include gains attributable to the
disposition of property held for investment or (if applicable)
qualified dividend income. The IRS has indicated that net
passive income earned by a publicly-traded partnership will be
treated as investment income to its unitholders for purposes of
the investment interest expense limitation. In addition, the
unitholders share of our portfolio income will be treated
as investment income.
Entity-Level Collections of Unitholder Taxes
If we are required or elect under applicable law to pay any
U.S. federal, state, local or
non-U.S. tax
on behalf of any unitholder or our general partner or any former
unitholder, we are authorized to pay those taxes from our funds.
That payment, if made, will be treated as a distribution of cash
to the unitholder on whose behalf the payment was made. If the
payment is made on behalf of a unitholder whose identity cannot
be determined, we are authorized to treat the payment as a
distribution to all current unitholders. We are authorized to
amend our partnership agreement in the manner necessary to
maintain uniformity of intrinsic tax characteristics of common
units and to adjust later distributions, so that after giving
effect to these distributions, the priority and characterization
of distributions otherwise applicable under our partnership
agreement is maintained as nearly as is practicable. Payments by
us as described above could give rise to an overpayment of tax
on behalf of an individual unitholder in which event the
unitholder would be required to file a claim in order to obtain
a credit or refund.
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Allocation of Income, Gain, Loss and Deduction
In general, our items of income, gain, loss and deduction will
be allocated among our general partner and the unitholders in
accordance with their percentage interests in us. If we have a
net loss for an entire taxable year, the loss will be allocated
first to our general partner and the unitholders in accordance
with their percentage interests in us to the extent of the
unitholders positive capital accounts as adjusted to take
into account the unitholders share of nonrecourse debt,
and thereafter to our general partner.
Specified items of our income, gain, loss and deduction will be
allocated to account for the difference between the tax basis
and fair market value of our assets, a Book Tax
Disparity, at the time of this offering and any future
offerings or certain other transactions. The effect of these
allocations, referred to as Section 704(c) Allocations, to
a unitholder acquiring common units in this offering will be
essentially the same as if the tax bases of our assets were
equal to their fair market values at the time of this offering.
However, in connection with providing this benefit to any future
unitholders, similar allocations will be made to all holders of
partnership interests immediately prior to a future offering or
certain other transactions, including purchasers of common units
in this offering, to account for any Book Tax Disparity at the
time of such transaction. In addition, items of recapture income
will be allocated to the extent possible to the unitholder who
was allocated the deduction giving rise to the treatment of that
gain as recapture income in order to minimize the recognition of
ordinary income by other unitholders.
An allocation of items of our income, gain, loss or deduction,
other than an allocation required by the Internal Revenue Code
to eliminate a Book-Tax Disparity, will generally be given
effect for U.S. federal income tax purposes in determining
a unitholders share of an item of income, gain, loss or
deduction only if the allocation has substantial economic
effect. In any other case, a unitholders share of an item
will be determined on the basis of his interest in us, which
will be determined by taking into account all the facts and
circumstances, including:
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his relative contributions to us;
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the interests of all the partners in profits and losses;
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the interest of all the partners in cash flow; and
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the rights of all the partners to distributions of capital upon
liquidation.
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Andrews Kurth LLP is of the opinion that, with the exception of
the issues described in Section 754
Election and Disposition of Common
UnitsAllocations Between Transferors and
Transferees, allocations under our partnership agreement
will be given effect for federal income tax purposes in
determining a partners share of an item of income, gain,
loss or deduction.
Treatment of Short Sales
A unitholder whose common units are loaned to a short
seller to cover a short sale of common units may be
considered as having disposed of those common units. If so, such
unitholder would no longer be treated for tax purposes as a
partner with respect to those common units during the period of
the loan and may recognize gain or loss from the disposition. As
a result, during this period:
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any of our income, gain, loss or deduction with respect to those
common units would not be reportable by the unitholder;
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any cash distributions received by the unitholder as to those
common units would be fully taxable; and
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all of these distributions may be subject to tax as ordinary
income.
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Andrews Kurth LLP has not rendered an opinion regarding the tax
treatment of a unitholder whose common units are loaned to a
short seller to cover a short sale of our common units.
Unitholders desiring to assure their status as partners and
avoid the risk of gain recognition from a loan to a short seller
are urged to consult with their tax advisor about modifying any
applicable brokerage account agreements to prohibit their
brokers from borrowing and loaning their common units. The IRS
has previously announced that it is studying issues relating to
the tax treatment of short sales of partnership interests.
Please read Disposition of UnitsRecognition of
Gain or Loss.
Alternative Minimum Tax
Each unitholder will be required to take into account the
unitholders distributive share of any items of our income,
gain, loss or deduction for purposes of the alternative minimum
tax. The current minimum tax rate for non-corporate taxpayers is
26% on the first $175,000 of alternative minimum taxable income
in excess of the exemption amount and 28% on any additional
alternative minimum taxable income. Prospective unitholders are
urged to consult with their tax advisors with respect to the
impact of an investment in our common units on their liability
for the alternative minimum tax.
Tax Rates
Under current law, the highest marginal U.S. federal income
tax rate applicable to ordinary income of individuals is 35% and
the highest marginal U.S. federal income tax rate
applicable to long-term capital gains (generally, gains from the
sale or exchange of certain investment assets held for more than
one year) of individuals is 15%. However, absent new legislation
extending the current rates, beginning January 1, 2013, the
highest marginal U.S. federal income tax rate applicable to
ordinary income and long-term capital gains of individuals will
increase to 39.6% and 20%, respectively. These rates are subject
to change by new legislation at any time.
Recently enacted legislation will impose a 3.8% Medicare tax on
certain investment income earned by individuals, estates, and
trusts for taxable years beginning after December 31, 2012.
For these purposes, investment income generally includes a
unitholders allocable share of our income and gain
realized by a unitholder from a sale of common units. In the
case of an individual, the tax will be imposed on the lesser of
(i) the unitholders net investment income from all
investments, or (ii) the amount by which the
unitholders modified adjusted gross income exceeds
specified threshold levels depending on a unitholders
federal income tax filing status. In the case of an estate or
trust, the tax will be imposed on the lesser of
(i) undistributed net investment income, or (ii) the
excess adjusted gross income over the dollar amount at which the
highest income tax bracket applicable to an estate or trust
begins.
Section 754 Election
We will make the election permitted by Section 754 of the
Internal Revenue Code. That election is irrevocable without the
consent of the IRS. That election will generally permit us to
adjust a unit purchasers tax basis in our assets
(inside basis) under Section 743(b) of the
Internal Revenue Code to reflect the unitholders purchase
price. The Section 743(b) adjustment separately applies to
any transferee of a unitholder who purchases outstanding common
units from another unitholder based upon the values and bases of
our assets at the time of the transfer to the transferee. The
Section 743(b) adjustment does not apply to a person who
purchases common units directly from us, and belongs only to the
purchaser and not to other unitholders. Please read, however,
Allocation of Income, Gain, Loss and
Deduction. For purposes of this discussion, a
unitholders inside basis in our assets will be considered
to have two components: (1) the unitholders share of
our tax basis in our assets (common basis) and
(2) the unitholders Section 743(b) adjustment to
that basis.
The timing and calculation of deductions attributable to
Section 743(b) adjustments to our common basis will depend
upon a number of factors, including the nature of the assets to
which
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the adjustment is allocable, the extent to which the adjustment
offsets any Internal Revenue Code Section 704(c) type gain
or loss with respect to an asset and certain elections we make
as to the manner in which we apply Internal Revenue Code
Section 704(c) principles with respect to an asset to which
the adjustment is applicable. Please read Allocation
of Income, Gain, Loss and Deduction.
The timing of these deductions may affect the uniformity of our
common units. Under our partnership agreement, our general
partner is authorized to take a position to preserve the
uniformity of common units even if that position is not
consistent with these and any other Treasury Regulations or if
the position would result in lower annual depreciation or
amortization deductions than would otherwise be allowable to
some unitholders. Please read Uniformity of
Units. Andrews Kurth LLP is unable to opine as to the
validity of any such alternate tax positions because there is no
clear applicable authority. A unitholders basis in a unit
is reduced by his share of our deductions (whether or not such
deductions were claimed on an individual income tax return) so
that any position that we take that understates deductions will
overstate the unitholders basis in his common units and
may cause the unitholder to understate gain or overstate loss on
any sale of such common units. Please read
Uniformity of Units.
A Section 754 election is advantageous if the
transferees tax basis in his common units is higher than
the common units share of the aggregate tax basis of our
assets immediately prior to the transfer. In that case, as a
result of the election, the transferee would have, among other
items, a greater amount of depreciation and depletion deductions
and the transferees share of any gain or loss on a sale of
assets by us would be less. Conversely, a Section 754
election is disadvantageous if the transferees tax basis
in his common units is lower than those common units share
of the aggregate tax basis of our assets immediately prior to
the transfer. Thus, the fair market value of the common units
may be affected either favorably or unfavorably by the election.
A basis adjustment is required regardless of whether a
Section 754 election is made in the case of a transfer of
an interest in us if we have a substantial built-in loss
immediately after the transfer, or if we distribute property and
have a substantial basis reduction. Generally a built-in loss or
a basis reduction is substantial if it exceeds $250,000.
The calculations involved in the Section 754 election are
complex and will be made on the basis of assumptions as to the
fair market value of our assets and other matters. For example,
the allocation of the Section 743(b) adjustment among our
assets must be made in accordance with the Internal Revenue
Code. The IRS could seek to reallocate some or all of any
Section 743(b) adjustment we allocated to our tangible
assets to goodwill instead. Goodwill, as an intangible asset, is
generally either
non-amortizable
or amortizable over a longer period of time or under a less
accelerated method than our tangible assets. We cannot assure
our unitholders that the determinations we make will not be
successfully challenged by the IRS or that the resulting
deductions will not be reduced or disallowed altogether. Should
the IRS require a different basis adjustment to be made, and
should our general partner determine the expense of compliance
exceeds the benefit of the election, we may seek permission from
the IRS to revoke our Section 754 election. If permission
is granted, a subsequent purchaser of common units may be
allocated more income than such purchaser would have been
allocated had the election not been revoked.
Tax
Treatment of Operations
Accounting Method and Taxable Year
We will use the year ending December 31 as our taxable year and
the accrual method of accounting for federal income tax
purposes. Each unitholder will be required to include in income
his share of our income, gain, loss and deduction for our
taxable year ending within or with his taxable year. In
addition, a unitholder who has a taxable year ending on a date
other than December 31 and who disposes of all of his common
units following the close of our taxable year
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but before the close of his taxable year must include his share
of our income, gain, loss and deduction in income for his
taxable year, with the result that he will be required to
include in income for his taxable year his share of more than
one year of our income, gain, loss and deduction. Please read
Disposition of UnitsAllocations Between
Transferors and Transferees.
Depletion Deductions
Subject to the limitations on deductibility of losses discussed
above (please read Tax Consequences of Unit
OwnershipLimitations on Deductibility of Losses),
unitholders will be entitled to deductions for the greater of
either cost depletion or (if otherwise allowable) percentage
depletion with respect to our oil and natural gas interests.
Although the Internal Revenue Code requires each unitholder to
compute his own depletion allowance and maintain records of his
share of the adjusted tax basis of the underlying property for
depletion and other purposes, we intend to furnish each of our
unitholders with information relating to this computation for
federal income tax purposes. Each unitholder, however, remains
responsible for calculating his own depletion allowance and
maintaining records of his share of the adjusted tax basis of
the underlying property for depletion and other purposes.
Percentage depletion is generally available with respect to
unitholders who qualify under the independent producer exemption
contained in Section 613A(c) of the Internal Revenue Code.
To qualify as an independent producer eligible for
percentage depletion (and that is not subject to the intangible
drilling and development cost deduction limits, please read
Deductions for Intangible Drilling and Development
Costs,) a unitholder, either directly or indirectly
through certain related parties, may not be involved in the
refining of more than 75,000 barrels of oil (or the
equivalent amount of natural gas) on average for any day during
the taxable year or in the retail marketing of oil and natural
gas products exceeding $5.0 million per year in the
aggregate. Percentage depletion is calculated as an amount
generally equal to 15% (and, in the case of marginal production,
potentially a higher percentage) of the unitholders gross
income from the depletable property for the taxable year. The
percentage depletion deduction with respect to any property is
limited to 100% of the taxable income of the unitholder from the
property for each taxable year, computed without the depletion
allowance. A unitholder that qualifies as an independent
producer may deduct percentage depletion only to the extent the
unitholders average net daily production of domestic crude
oil, or the natural gas equivalent, does not exceed
1,000 barrels. This depletable amount may be allocated
between oil and natural gas production, with 6,000 cubic feet of
domestic natural gas production regarded as equivalent to one
barrel of crude oil. The 1,000-barrel limitation must be
allocated among the independent producer and controlled or
related persons and family members in proportion to the
respective production by such persons during the period in
question.
In addition to the foregoing limitations, the percentage
depletion deduction otherwise available is limited to 65% of a
unitholders total taxable income from all sources for the
year, computed without the depletion allowance, net operating
loss carrybacks, or capital loss carrybacks. Any percentage
depletion deduction disallowed because of the 65% limitation may
be deducted in the following taxable year if the percentage
depletion deduction for such year plus the deduction carryover
does not exceed 65% of the unitholders total taxable
income for that year. The carryover period resulting from the
65% net income limitation is unlimited.
Unitholders that do not qualify under the independent producer
exemption are generally restricted to depletion deductions based
on cost depletion. Cost depletion deductions are calculated by
(i) dividing the unitholders share of the adjusted
tax basis in the underlying mineral property by the number of
mineral common units (barrels of oil and thousand cubic feet, or
Mcf, of natural gas) remaining as of the beginning of the
taxable year and (ii) multiplying the result by the number
of mineral common units sold within the taxable year. The total
amount of
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deductions based on cost depletion cannot exceed the
unitholders share of the total adjusted tax basis in the
property.
All or a portion of any gain recognized by a unitholder as a
result of either the disposition by us of some or all of our oil
and natural gas interests or the disposition by the unitholder
of some or all of his common units may be taxed as ordinary
income to the extent of recapture of depletion deductions,
except for percentage depletion deductions in excess of the tax
basis of the property. The amount of the recapture is generally
limited to the amount of gain recognized on the disposition.
The foregoing discussion of depletion deductions does not
purport to be a complete analysis of the complex legislation and
Treasury Regulations relating to the availability and
calculation of depletion deductions by the unitholders. Further,
because depletion is required to be computed separately by each
unitholder and not by our partnership, no assurance can be
given, and counsel is unable to express any opinion, with
respect to the availability or extent of percentage depletion
deductions to the unitholders for any taxable year. Moreover,
the availability of percentage depletion may be reduced or
eliminated if recently proposed (or similar) tax legislation is
enacted. For a discussion of such legislative proposals, please
read Recent Legislative Developments. We
encourage each prospective unitholder to consult his tax advisor
to determine whether percentage depletion would be available to
him.
Deductions for Intangible Drilling and Development
Costs
We will elect to currently deduct intangible drilling and
development costs (IDCs). IDCs generally include our
expenses for wages, fuel, repairs, hauling, supplies and other
items that are incidental to, and necessary for, the drilling
and preparation of wells for the production of oil, natural gas,
or geothermal energy. The option to currently deduct IDCs
applies only to those items that do not have a salvage value.
Although we will elect to currently deduct IDCs, each unitholder
will have the option of either currently deducting IDCs or
capitalizing all or part of the IDCs and amortizing them on a
straight-line basis over a
60-month
period, beginning with the taxable month in which the
expenditure is made. If a unitholder makes the election to
amortize the IDCs over a
60-month
period, no IDC preference amount in respect of those IDCs will
result for alternative minimum tax purposes.
Integrated oil companies must capitalize 30% of all their IDCs
(other than IDCs paid or incurred with respect to oil and
natural gas wells located outside of the United States) and
amortize these IDCs over 60 months beginning in the month
in which those costs are paid or incurred. If the taxpayer
ceases to be an integrated oil company, it must continue to
amortize those costs as long as it continues to own the property
to which the IDCs relate. An integrated oil company
is a taxpayer that has economic interests in oil or natural gas
properties and also carries on substantial retailing or refining
operations. An oil or natural gas producer is deemed to be a
substantial retailer or refiner if it is does not qualify as an
independent producer under the rules disqualifying retailers and
refiners from taking percentage depletion. Please read
Depletion Deductions.
IDCs previously deducted that are allocable to property
(directly or through ownership of an interest in a partnership)
and that would have been included in the adjusted tax basis of
the property had the IDC deduction not been taken are recaptured
to the extent of any gain realized upon the disposition of the
property or upon the disposition by a unitholder of interests in
us. Recapture is generally determined at the unitholder level.
Where only a portion of the recapture property is sold, any IDCs
related to the entire property are recaptured to the extent of
the gain realized on the portion of the property sold. In the
case of a disposition of an undivided interest in a property, a
proportionate amount of the IDCs with respect to the property is
treated as
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allocable to the transferred undivided interest to the extent of
any gain recognized. Please read Disposition
of UnitsRecognition of Gain or Loss.
The election to currently deduct IDCs may be restricted or
eliminated if recently proposed (or similar) tax legislation is
enacted. For a discussion of such legislative proposals, please
read Recent Legislative Developments.
Deduction for U.S. Production Activities
Subject to the limitations on the deductibility of losses
discussed above and the limitation discussed below, unitholders
will be entitled to a deduction, herein referred to as the
Section 199 deduction, equal to 6% of our qualified
production activities income that is allocated to such
unitholder.
Qualified production activities income is generally equal to
gross receipts from domestic production activities reduced by
cost of goods sold allocable to those receipts, other expenses
directly associated with those receipts, and a share of other
deductions, expenses and losses that are not directly allocable
to those receipts or another class of income. The products
produced must be manufactured, produced, grown or extracted in
whole or in significant part by the taxpayer in the United
States.
For a partnership, the Section 199 deduction is determined
at the partner level. To determine his Section 199
deduction, each unitholder will aggregate his share of the
qualified production activities income allocated to him from us
with the unitholders qualified production activities
income from other sources. Each unitholder must take into
account his distributive share of the expenses allocated to him
from our qualified production activities regardless of whether
we otherwise have taxable income. However, our expenses that
otherwise would be taken into account for purposes of computing
the Section 199 deduction are taken into account only if
and to the extent the unitholders share of losses and
deductions from all of our activities is not disallowed by the
tax basis rules, the at risk rules or the passive activity loss
rules. Please read Tax Consequences of Unit
OwnershipLimitations on Deductibility of Losses.
The amount of a unitholders Section 199 deduction for
each year is limited to 50% of the IRS
Form W-2
wages actually or deemed paid by the unitholder during the
calendar year that are deducted in arriving at qualified
production activities income. Each unitholder is treated as
having been allocated IRS
Form W-2
wages from us equal to the unitholders allocable share of
our wages that are deducted in arriving at qualified production
activities income for that taxable year. It is not anticipated
that we or our operating subsidiary will pay material wages that
will be allocated to our unitholders, and thus a
unitholders ability to claim the Section 199
deduction may be limited.
This discussion of the Section 199 deduction does not
purport to be a complete analysis of the complex legislation and
Treasury authority relating to the calculation of domestic
production gross receipts, qualified production activities
income, or IRS
Form W-2
wages, or how such items are allocated by us to unitholders.
Further, because the Section 199 deduction is required to
be computed separately by each unitholder, no assurance can be
given, and counsel is unable to express any opinion, as to the
availability or extent of the Section 199 deduction to the
unitholders. Moreover, the availability of Section 199
deductions may be reduced or eliminated if recently proposed (or
similar) tax legislation is enacted. For a discussion of such
legislative proposals, please read Recent
Legislative Developments. Each prospective unitholder is
encouraged to consult his tax advisor to determine whether the
Section 199 deduction would be available to him.
Lease Acquisition Costs
The cost of acquiring oil and natural gas lease or similar
property interests is a capital expenditure that must be
recovered through depletion deductions if the lease is
productive. If a
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lease is proved worthless and abandoned, the cost of acquisition
less any depletion claimed may be deducted as an ordinary loss
in the year the lease becomes worthless. Please read
Tax Treatment of OperationsDepletion
Deductions.
Geophysical Costs
The cost of geophysical exploration incurred in connection with
the exploration and development of oil and natural gas
properties in the United States are deducted ratably over a
24-month
period beginning on the date that such expense is paid or
incurred. The amortization period for certain geological and
geophysical expenditures may be extended if recently proposed
(or similar) tax legislation is enacted. For a discussion of
such legislative proposals, please read Recent
Legislative Developments.
Operating and Administrative Costs
Amounts paid for operating a producing well are deductible as
ordinary business expenses, as are administrative costs, to the
extent they constitute ordinary and necessary business expenses
that are reasonable in amount.
Tax Basis, Depreciation and Amortization
The tax basis of our assets will be used for purposes of
computing depreciation and cost recovery deductions and,
ultimately, gain or loss on the disposition of these assets. The
federal income tax burden associated with the difference between
the fair market value of our assets and their tax basis
immediately prior to an offering will be borne by our partners
holding interests in us prior to such offering. Please read
Tax Consequences of Unit OwnershipAllocation
of Income, Gain, Loss and Deduction.
To the extent allowable, we may elect to use the depreciation
and cost recovery methods, including bonus depreciation to the
extent applicable, that will result in the largest deductions
being taken in the early years after assets subject to these
allowances are placed in service. We may not be entitled to any
amortization deductions with respect to certain goodwill
properties conveyed to us or held by us at the time of any
future offering. Please read Uniformity of
Units. Property we subsequently acquire or construct may
be depreciated using accelerated methods permitted by the
Internal Revenue Code.
If we dispose of depreciable property by sale, foreclosure or
otherwise, all or a portion of any gain, determined by reference
to the amount of depreciation previously deducted and the nature
of the property, may be subject to the recapture rules and taxed
as ordinary income rather than capital gain. Similarly, a
unitholder who has taken cost recovery or depreciation
deductions with respect to property we own will likely be
required to recapture some or all of those deductions as
ordinary income upon a sale of his interest in us. Please read
Tax Consequences of Unit OwnershipAllocation
of Income, Gain, Loss and Deduction and
Disposition of UnitsRecognition of Gain or
Loss.
The costs incurred in selling our common units (called
syndication expenses) must be capitalized and cannot
be deducted currently, ratably or upon our termination. There
are uncertainties regarding the classification of costs as
organization expenses, which may be amortized by us, and as
syndication expenses, which may not be amortized by us. The
underwriting discounts we incur will be treated as syndication.
Valuation and Tax Basis of Our Properties
The federal income tax consequences of the ownership and
disposition of common units will depend in part on our estimates
of the relative fair market values and the initial tax bases of
our assets. Although we may from time to time consult with
professional appraisers regarding valuation matters, we will
make many of the relative fair market value estimates ourselves.
These estimates and determinations of basis are subject to
challenge and will not be binding on
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the IRS or the courts. If the estimates of fair market value or
basis are later found to be incorrect, the character and amount
of items of income, gain, loss or deduction previously reported
by unitholders might change, and unitholders might be required
to adjust their tax liability for prior years and incur interest
and penalties with respect to those adjustments.
Disposition
of Units
Recognition of Gain or Loss
Gain or loss will be recognized on a sale of common units equal
to the difference between the unitholders amount realized
and the unitholders tax basis for the common units sold. A
unitholders amount realized will equal the sum of the cash
or the fair market value of other property he receives plus his
share of our liabilities. Because the amount realized includes a
unitholders share of our liabilities, the gain recognized
on the sale of common units could result in a tax liability in
excess of any cash received from the sale.
Prior distributions from us that in the aggregate were in excess
of the cumulative net taxable income allocated for a unit that
decreased a unitholders tax basis in that unit will, in
effect, become taxable income if the unit is sold at a price
greater than the unitholders tax basis in the unit, even
if the price received is less than his original cost.
Except as noted below, gain or loss recognized by a unitholder
on the sale or exchange of a unit held for more than one year
will generally be taxable as long-term capital gain or loss.
However, a portion of this gain or loss, which will likely be
substantial, will be separately computed and taxed as ordinary
income or loss under Section 751 of the Internal Revenue
Code to the extent attributable to assets giving rise to
depreciation recapture or other unrealized
receivables or inventory items that we own.
The term unrealized receivables includes potential
recapture items, including depreciation, depletion, amortization
or IDC recapture. Ordinary income attributable to unrealized
receivables, inventory items and depreciation recapture may
exceed net taxable gain realized on the sale of a unit and may
be recognized even if there is a net taxable loss realized on
the sale of a unit. Thus, a unitholder may recognize both
ordinary income and a capital loss upon a sale of common units.
Capital losses may offset capital gains and no more than $3,000
of ordinary income each year, in the case of individuals, and
may only be used to offset capital gain in the case of
corporations.
The IRS has ruled that a partner who acquires interests in a
partnership in separate transactions must combine those
interests and maintain a single adjusted tax basis for all those
interests. Upon a sale or other disposition of less than all of
those interests, a portion of that tax basis must be allocated
to the interests sold using an equitable
apportionment method, which generally means that the tax
basis allocated to the interest sold equals an amount that bears
the same relation to the partners tax basis in his entire
interest in the partnership as the value of the interest sold
bears to the value of the partners entire interest in the
partnership. Treasury Regulations under Section 1223 of the
Internal Revenue Code allow a selling unitholder who can
identify common units transferred with an ascertainable holding
period to elect to use the actual holding period of the common
units transferred. Thus, according to the ruling discussed
above, a unitholder will be unable to select high or low basis
common units to sell as would be the case with corporate stock,
but, according to the Treasury Regulations, he may designate
specific common units sold for purposes of determining the
holding period of common units transferred. A unitholder
electing to use the actual holding period of common units
transferred must consistently use that identification method for
all subsequent sales or exchanges of our common units. A
unitholder considering the purchase of additional common units
or a sale of common units purchased in separate transactions is
urged to consult his tax advisor as to the possible consequences
of this ruling and application of the Treasury Regulations.
Specific provisions of the Internal Revenue Code affect the
taxation of some financial products and securities, including
partnership interests, by treating a taxpayer as having sold an
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appreciated partnership interest, one in which gain
would be recognized if it were sold, assigned or terminated at
its fair market value, if the taxpayer or related persons
enter(s) into:
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a short sale;
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an offsetting notional principal contract; or
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a futures or forward contract;
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in each case, with respect to the partnership interest or
substantially identical property.
Moreover, if a taxpayer has previously entered into a short
sale, an offsetting notional principal contract or a futures or
forward contract with respect to the partnership interest, the
taxpayer will be treated as having sold that position if the
taxpayer or a related person then acquires the partnership
interest or substantially identical property. The Secretary of
the Treasury is also authorized to issue regulations that treat
a taxpayer that enters into transactions or positions that have
substantially the same effect as the preceding transactions as
having constructively sold the financial position.
Allocations Between Transferors and Transferees
In general, our taxable income or loss will be determined
annually, will be prorated on a monthly basis and will be
subsequently apportioned among the unitholders in proportion to
the number of common units owned by each of them as of the
opening of the applicable exchange on the first business day of
the month (the Allocation Date). However, gain or
loss realized on a sale or other disposition of our assets other
than in the ordinary course of business will be allocated among
the unitholders on the Allocation Date in the month in which
that gain or loss is recognized. As a result, a unitholder
transferring common units may be allocated income, gain, loss
and deduction realized after the date of transfer.
Although simplifying conventions are contemplated by the
Internal Revenue Code and most publicly-traded partnerships use
similar simplifying conventions, the use of this method may not
be permitted under existing Treasury Regulations. Recently,
however, the Department of the Treasury and the IRS issued
proposed Treasury Regulations that provide a safe harbor
pursuant to which a publicly-traded partnership may use a
similar monthly simplifying convention to allocate tax items
among transferor and transferee unitholders, although such tax
items must be prorated on a daily basis. Nonetheless, the
proposed regulations do not specifically authorize the use of
the proration method we have adopted. Existing publicly-traded
partnerships are entitled to rely on those proposed Treasury
Regulations; however, they are not binding on the IRS and are
subject to change until the final Treasury Regulations are
issued. Accordingly, Andrews Kurth LLP is unable to opine on the
validity of this method of allocating income and deductions
between transferee and transferor unitholders. If this method is
not allowed under the Treasury Regulations, or only applies to
transfers of less than all of the unitholders interest,
our taxable income or losses might be reallocated among the
unitholders. We are authorized to revise our method of
allocation between transferee and transferor unitholders, as
well as among unitholders whose interests vary during a taxable
year, to conform to a method permitted under future Treasury
Regulations.
A unitholder who disposes of common units prior to the record
date set for a cash distribution for any quarter will be
allocated items of our income, gain, loss and deductions
attributable to the month of sale but will not be entitled to
receive that cash distribution.
Notification Requirements
A unitholder who sells any of his common units is generally
required to notify us in writing of that sale within
30 days after the sale (or, if earlier, January 15 of the
year following the sale). A purchaser of common units who
purchases common units from another unitholder is also generally
required to notify us in writing of that purchase within
30 days after the purchase.
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Upon receiving such notifications, we are required to notify the
IRS of that transaction and to furnish specified information to
the transferor and transferee. Failure to notify us of a
transfer of common units may, in some cases, lead to the
imposition of penalties. However, these reporting requirements
do not apply to a sale by an individual who is a citizen of the
United States and who effects the sale or exchange through a
broker who will satisfy such requirements.
Constructive Termination
We will be considered to have terminated our tax partnership for
U.S. federal income tax purposes upon the sale or exchange
of interests in us that, in the aggregate, constitute 50% or
more of the total interests in our capital and profits within a
twelve-month period. For purposes of measuring whether the 50%
threshold has been met, multiple sales of the same unit are
counted only once. A constructive termination results in the
closing of our taxable year for all unitholders. In the case of
a unitholder reporting on a taxable year other than a fiscal
year ending December 31, the closing of our taxable year
may result in more than twelve months of our taxable income or
loss being includable in such unitholders taxable income
for the year of termination. A constructive termination
occurring on a date other than December 31 will result in us
filing two tax returns (and unitholders could receive two
Schedules K-1 if the relief discussed below is not available)
for one fiscal year and the cost of the preparation of these
returns will be borne by all unitholders. However, pursuant to
an IRS relief procedure for publicly traded partnerships that
have technically terminated, the IRS may allow, among other
things, that we provide a single
Schedule K-1
for the tax year in which a termination occurs. We would be
required to make new tax elections after a termination,
including a new election under Section 754 of the Internal
Revenue Code, and a termination would result in a deferral of
our deductions for depreciation. A termination could also result
in penalties if we were unable to determine that the termination
had occurred. Moreover, a termination might either accelerate
the application of, or subject us to, any tax legislation
enacted before the termination.
Uniformity
of Units
Because we cannot match transferors and transferees of common
units and because of other reasons, we must maintain uniformity
of the economic and tax characteristics of the common units to a
purchaser of these common units. In the absence of uniformity,
we may be unable to completely comply with a number of federal
income tax requirements, both statutory and regulatory. A lack
of uniformity could result from a literal application of
Treasury
Regulation Section 1.167(c)-1(a)(6),
which is not expected to apply to a material portion of our
assets. Any non-uniformity could have a negative impact on the
value of the common units. Please read Tax
Consequences of Unit OwnershipSection 754
Election.
Our partnership agreement permits our general partner to take
positions in filing our tax returns that preserve the uniformity
of our common units even under circumstances like those
described above. These positions may include reducing for some
unitholders the depreciation, amortization or loss deductions to
which they would otherwise be entitled or reporting a slower
amortization of Section 743(b) adjustments for some
unitholders than that to which they would otherwise be entitled.
Andrews Kurth LLP is unable to opine as to validity of such
filing positions. A unitholders basis in common units is
reduced by his share of our deductions (whether or not such
deductions were claimed on an individual income tax return) so
that any position that we take that understates deductions will
overstate the unitholders basis in his common units, and
may cause the unitholder to understate gain or overstate loss on
any sale of such common units. Please read
Disposition of UnitsRecognition of Gain or
Loss and Tax Consequences of Unit
OwnershipSection 754 Election. The IRS may
challenge one or more of any positions we take to preserve the
uniformity of common units. If such a challenge were sustained,
the uniformity of common units might be affected, and, under
some circumstances, the gain from the sale of common units might
be increased without the benefit of additional deductions.
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Tax-Exempt
Organizations and Other Investors
Ownership of common units by employee benefit plans, other
tax-exempt organizations, non-resident aliens,
non-U.S. corporations
and other
non-U.S. persons
raises issues unique to those investors and, as described below,
may have substantially adverse tax consequences to them.
Prospective unitholders who are tax-exempt entities or
non-U.S. persons
should consult their tax advisor before investing in our common
units.
Employee benefit plans and most other organizations exempt from
federal income tax, including individual retirement accounts and
other retirement plans, are subject to federal income tax on
unrelated business taxable income. Virtually all of our income
allocated to a unitholder that is a tax-exempt organization will
be unrelated business taxable income and will be taxable
to it.
Non-resident aliens and foreign corporations, trusts or estates
that own common units will be considered to be engaged in
business in the United States because of the ownership of common
units. As a consequence, they will be required to file federal
tax returns to report their share of our income, gain, loss or
deduction and pay federal income tax at regular rates on their
share of our net income or gain. Moreover, under rules
applicable to publicly traded partnerships, distributions to
non-U.S. unitholders
are subject to withholding at the highest applicable effective
tax rate. Each
non-U.S. unitholder
must obtain a taxpayer identification number from the IRS and
submit that number to our transfer agent on a
Form W-8BEN
or applicable substitute form in order to obtain credit for
these withholding taxes. A change in applicable law may require
us to change these procedures.
In addition, because a foreign corporation that owns common
units will be treated as engaged in a United States trade or
business, that corporation may be subject to the United States
branch profits tax at a rate of 30%, in addition to regular
federal income tax, on its share of our income and gain, as
adjusted for changes in the foreign corporations
U.S. net equity, which is effectively connected
with the conduct of a United States trade or business. That tax
may be reduced or eliminated by an income tax treaty between the
United States and the country in which the foreign corporate
unitholder is a qualified resident. In addition,
this type of unitholder is subject to special information
reporting requirements under Section 6038C of the Internal
Revenue Code.
A foreign unitholder who sells or otherwise disposes of a unit
will be subject to U.S. federal income tax on gain realized
from the sale or disposition of that unit to the extent the gain
is effectively connected with a U.S. trade or business of
the foreign unitholder. Under a ruling published by the IRS,
interpreting the scope of effectively connected
income, a foreign unitholder would be considered to be
engaged in a trade or business in the U.S. by virtue of the
U.S. activities of the partnership, and part or all of that
unitholders gain would be effectively connected with that
unitholders indirect U.S. trade or business.
Moreover, under the Foreign Investment in Real Property Tax Act,
a foreign unitholder generally will be subject to
U.S. federal income tax upon the sale or disposition of a
unit if (i) he owned (directly or constructively applying
certain attribution rules) more than 5% of our common units at
any time during the five-year period ending on the date of such
disposition and (ii) 50% or more of the fair market value
of all of our assets consisted of U.S. real property
interests at any time during the shorter of the period during
which such unitholder held the common units or the
5-year
period ending on the date of disposition. Currently, more than
50% of our assets consist of U.S. real property interests
and we do not expect that to change in the foreseeable future.
Therefore, foreign unitholders may be subject to federal income
tax on gain from the sale or disposition of their common units.
Administrative
Matters
Information Returns and Audit Procedures
We intend to furnish to each unitholder, within 90 days
after the close of each taxable year, specific tax information,
including a
Schedule K-1,
which describes his share of our income, gain,
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loss and deduction for our preceding taxable year. In preparing
this information, which will not be reviewed by counsel, we will
take various accounting and reporting positions, some of which
have been mentioned earlier, to determine each unitholders
share of income, gain, loss and deduction. We cannot assure our
unitholders that those positions will yield a result that
conforms to the requirements of the Internal Revenue Code,
Treasury Regulations or administrative interpretations of the
IRS. Neither we, nor Andrews Kurth LLP can assure prospective
unitholders that the IRS will not successfully contend in court
that those positions are impermissible. Any challenge by the IRS
could negatively affect the value of the common units.
The IRS may audit our federal income tax information returns.
Adjustments resulting from an IRS audit may require each
unitholder to adjust a prior years tax liability, and
possibly may result in an audit of his return. Any audit of a
unitholders return could result in adjustments not related
to our returns as well as those related to our returns.
Partnerships generally are treated as separate entities for
purposes of U.S. federal income tax audits, judicial review
of administrative adjustments by the IRS and tax settlement
proceedings. The tax treatment of partnership items of income,
gain, loss and deduction are determined in a partnership
proceeding rather than in separate proceedings with the
partners. The Internal Revenue Code requires that one partner be
designated as the Tax Matters Partner for these
purposes. Our partnership agreement designates our general
partner as our Tax Matters Partner.
The Tax Matters Partner will make some elections on our behalf
and on behalf of unitholders. In addition, the Tax Matters
Partner can extend the statute of limitations for assessment of
tax deficiencies against unitholders for items in our returns.
The Tax Matters Partner may bind a unitholder with less than a
1% profits interest in us to a settlement with the IRS unless
that unitholder elects, by filing a statement with the IRS, not
to give that authority to the Tax Matters Partner. The Tax
Matters Partner may seek judicial review, by which all the
unitholders are bound, of a final partnership administrative
adjustment and, if the Tax Matters Partner fails to seek
judicial review, judicial review may be sought by any unitholder
having at least a 1% interest in profits or by any group of
unitholders having in the aggregate at least a 5% interest in
profits. However, only one action for judicial review will go
forward, and each unitholder with an interest in the outcome may
participate in that action.
A unitholder must file a statement with the IRS identifying the
treatment of any item on his federal income tax return that is
not consistent with the treatment of the item on our return.
Intentional or negligent disregard of this consistency
requirement may subject a unitholder to substantial penalties.
Nominee Reporting
Persons who hold an interest in us as a nominee for another
person are required to furnish to us:
(1) the name, address and taxpayer identification number of
the beneficial owner and the nominee;
(2) a statement regarding whether the beneficial owner is:
(a) a person that is not a U.S. person;
(b) a
non-U.S. government,
an international organization or any wholly owned agency or
instrumentality of either of the foregoing; or
(c) a tax-exempt entity;
(3) the amount and description of common units held,
acquired or transferred for the beneficial owner; and
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(4) specific information including the dates of
acquisitions and transfers, means of acquisitions and transfers,
and acquisition cost for purchases, as well as the amount of net
proceeds from sales.
Brokers and financial institutions are required to furnish
additional information, including whether they are
U.S. persons and specific information on common units they
acquire, hold or transfer for their own account. A penalty of
$100 per failure, up to a maximum of $1,500,000 per calendar
year, is imposed by the Internal Revenue Code for failure to
report that information to us. The nominee is required to supply
the beneficial owner of the common units with the information
furnished to us.
Accuracy-Related Penalties
An additional tax equal to 20% of the amount of any portion of
an underpayment of tax that is attributable to one or more
specified causes, including negligence or disregard of rules or
regulations, substantial understatements of income tax and
substantial valuation misstatements, is imposed by the Internal
Revenue Code. No penalty will be imposed, however, for any
portion of an underpayment if it is shown that there was a
reasonable cause for the underpayment of that portion and that
the taxpayer acted in good faith regarding the underpayment of
that portion.
For individuals, a substantial understatement of income tax in
any taxable year exists if the amount of the understatement
exceeds the greater of 10% of the tax required to be shown on
the return for the taxable year or $5,000 ($10,000 for most
corporations). The amount of any understatement subject to
penalty generally is reduced if any portion is attributable to a
position adopted on the return:
(1) for which there is, or was, substantial
authority; or
(2) as to which there is a reasonable basis and the
pertinent facts of that position are disclosed on the return.
If any item of income, gain, loss or deduction included in the
distributive shares of unitholders might result in that kind of
an understatement of income for which no
substantial authority exists, we must disclose the
pertinent facts on our return. In addition, we will make a
reasonable effort to furnish sufficient information for
unitholders to make adequate disclosure on their returns and to
take other actions as may be appropriate to permit unitholders
to avoid liability for this penalty. More stringent rules apply
to tax shelters, which we do not believe includes
us, or any of our investments, plans or arrangements.
A substantial valuation misstatement exists if (a) the
value of any property, or the tax basis of any property, claimed
on a tax return is 150% or more of the amount determined to be
the correct amount of the valuation or tax basis, (b) the
price for any property or services (or for the use of property)
claimed on any such return with respect to any transaction
between persons described in Internal Revenue Code
Section 482 is 200% or more (or 50% or less) of the amount
determined under Section 482 to be the correct amount of
such price, or (c) the net Internal Revenue Code
Section 482 transfer price adjustment for the taxable year
exceeds the lesser of $5.0 million or 10% of the
taxpayers gross receipts. No penalty is imposed unless the
portion of the underpayment attributable to a substantial
valuation misstatement exceeds $5,000 ($10,000 for a corporation
other than an S Corporation or a personal holding company).
The penalty is increased to 40% in the event of a gross
valuation misstatement. We do not anticipate making any
valuation misstatements.
In addition, the 20% accuracy-related penalty also applies to
any portion of an underpayment of tax that is attributable to
transactions lacking economic substance. To the extent that such
transactions are not disclosed, the penalty imposed is increased
to 40%. Additionally, there is no reasonable cause defense to
the imposition of this penalty to such transactions.
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Reportable Transactions
If we were to engage in a reportable transaction, we
(and possibly our unitholders and others) would be required to
make a detailed disclosure of the transaction to the IRS. A
transaction may be a reportable transaction based upon any of
several factors, including the fact that it is a type of tax
avoidance transaction publicly identified by the IRS as a
listed transaction or that it produces certain kinds
of losses for partnerships, individuals, S corporations,
and trusts in excess of $2.0 million in any single tax
year, or $4.0 million in any combination of six successive
tax years. Our participation in a reportable transaction could
increase the likelihood that our federal income tax information
return (and possibly our unitholders tax return) would be
audited by the IRS. Please read Information Returns
and Audit Procedures.
Moreover, if we were to participate in a reportable transaction
with a significant purpose to avoid or evade tax, or in any
listed transaction, our unitholders may be subject to the
following additional consequences:
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accuracy-related penalties with a broader scope, significantly
narrower exceptions, and potentially greater amounts than
described in Accuracy-Related Penalties;
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for those persons otherwise entitled to deduct interest on
federal tax deficiencies, nondeductibility of interest on any
resulting tax liability; and
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in the case of a listed transaction, an extended statute of
limitations.
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We do not expect to engage in any reportable
transactions.
Recent
Legislative Developments
Both President Obamas budget proposal for the Fiscal Year
2012 and the Administrations proposed American Jobs Act of
2011 recommend changes in federal income tax laws including the
elimination of certain key U.S. federal income tax
preferences relating to oil and natural gas exploration and
development. Changes in the proposals include, but are not
limited to, (i) the repeal of the percentage depletion
allowance for oil and natural gas properties, (ii) the
elimination of current deductions for intangible drilling and
development costs, (iii) the elimination of the deduction
for certain domestic production activities, and (iv) an
extension of the amortization period for certain geological and
geophysical expenditures. It is unclear whether these or similar
changes will be enacted and, if enacted, how soon any such
changes could become effective. The passage of any legislation
as a result of these proposals or any other similar changes in
U.S. federal income tax laws could eliminate or postpone
certain tax deductions that are currently available with respect
to oil and natural gas exploration and development, and any such
change could increase the taxable income allocable to our
unitholders and negatively impact the value of an investment in
our common units.
In addition, the Obama Administration is considering, and, in
the last Congressional session, the U.S. House of
Representatives passed legislation that would have provided for
substantive changes to the definition of qualifying income and
the treatment of certain types of income earned from profits
interests in partnerships. It is possible that these legislative
efforts could result in changes to the existing federal income
tax laws that affect publicly traded partnerships. As previously
proposed, we do not believe any such legislation would affect
our tax treatment as a partnership. However, the proposed
legislation could be modified in a way that could affect us. We
are unable to predict whether any of these changes, or other
proposals, will ultimately be enacted. Any such changes could
negatively impact the value of an investment in our common units.
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State,
Local and Other Tax Considerations
In addition to U.S. federal income taxes, unitholders will
be subject to other taxes, including state and local income
taxes, unincorporated business taxes, and estate, inheritance or
intangibles taxes that may be imposed by the various
jurisdictions in which we conduct business or own property or in
which the unitholder is a resident. We currently conduct
business or own property in Oklahoma and Colorado, each of which
imposes personal income taxes on individuals. These states also
impose an income tax on corporations and other entities.
Moreover, we may also own property or do business in other
states in the future that impose income or similar taxes on
nonresident individuals. Although an analysis of those various
taxes is not presented here, each prospective unitholder should
consider their potential impact on his investment in us. A
unitholder may be required to file state income tax returns and
to pay state income taxes in any state in which we do business
or own property, and such unitholder may be subject to penalties
for failure to comply with those requirements. In some states,
tax losses may not produce a tax benefit in the year incurred
and also may not be available to offset income in subsequent
taxable years. Some of the states may require us, or we may
elect, to withhold a percentage of income from amounts to be
distributed to a unitholder who is not a resident of the state.
Withholding, the amount of which may be greater or less than a
particular unitholders income tax liability to the state,
generally does not relieve a nonresident unitholder from the
obligation to file an income tax return. Amounts withheld may be
treated as if distributed to unitholders for purposes of
determining the amounts distributed by us. Please read
Tax Consequences of Unit
OwnershipEntity-Level Collections of Unitholder
Taxes. Based on current law and our estimate of our future
operations, we anticipate that any amounts required to be
withheld will not be material.
It is the responsibility of each unitholder to investigate the
legal and tax consequences, under the laws of pertinent states
and localities, of his investment in us. Accordingly, each
prospective unitholder is urged to consult, and depend on, his
own tax counsel or other advisor with regard to those matters.
Further, it is the responsibility of each unitholder to file all
tax returns that may be required of him. Andrews Kurth LLP has
not rendered an opinion on the state, local or
non-U.S. tax
consequences of an investment in us.
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INVESTMENT
IN MID-CON ENERGY PARTNERS, LP BY EMPLOYEE BENEFIT
PLANS
An investment in us by an employee benefit plan is subject to
additional considerations because the investments of these plans
are subject to the fiduciary responsibility and prohibited
transaction provisions of ERISA and the restrictions imposed by
Section 4975 of the Internal Revenue Code and provisions
under any federal, state, local,
non-U.S. or
other laws or regulations that are similar to such provisions of
the Internal Revenue Code or ERISA (collectively, Similar
Laws). For these purposes the term employee benefit
plan includes, but is not limited to, qualified pension,
profit-sharing and stock bonus plans, Keogh plans, simplified
employee pension plans and tax deferred annuities or individual
retirement accounts or annuities (IRAs) established
or maintained by an employer or employee organization, and
entities whose underlying assets are considered to include
plan assets of such plans, accounts and arrangements
(collectively, Employee Benefit Plans). Among other
things, consideration should be given to:
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whether the investment is prudent under
Section 404(a)(1)(B) of ERISA and any other applicable
Similar Laws;
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whether in making the investment, the plan will satisfy the
diversification requirements of Section 404(a)(1)(C) of
ERISA and any other applicable Similar Laws;
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whether the investment will result in recognition of unrelated
business taxable income by the plan and, if so, the potential
after-tax investment return. Please read Material Tax
ConsequencesTax-Exempt Organizations and Other
Investors; and
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whether making such an investment will comply with the
delegation of control and prohibited transaction provisions of
ERISA, the Internal Revenue Code and any other applicable
Similar Laws.
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The person with investment discretion with respect to the assets
of an Employee Benefit Plan, often called a fiduciary, should
determine whether an investment in us is authorized by the
appropriate governing instrument and is a proper investment for
the plan.
Section 406 of ERISA and Section 4975 of the Internal
Revenue Code prohibit Employee Benefit Plans, and IRAs that are
not considered part of an Employee Benefit Plan, from engaging,
either directly or indirectly, in specified transactions
involving plan assets with parties that, with
respect to the plan, are parties in interest under
ERISA or disqualified persons under the Internal
Revenue Code unless an exemption is available. A party in
interest or disqualified person who engages in a non-exempt
prohibited transaction may be subject to excise taxes and other
penalties and liabilities under ERISA and the Internal Revenue
Code. In addition, the fiduciary of the ERISA plan that engaged
in such a non-exempt prohibited transaction may be subject to
penalties and liabilities under ERISA and the Internal Revenue
Code.
In addition to considering whether the purchase of common units
is a prohibited transaction, a fiduciary should consider whether
the plan will, by investing in us, be deemed to own an undivided
interest in our assets, with the result that our general partner
would also be a fiduciary of such plan and our operations would
be subject to the regulatory restrictions of ERISA, including
its prohibited transaction rules, as well as the prohibited
transaction rules of the Internal Revenue Code, ERISA and any
other applicable Similar Laws.
The Department of Labor regulations and Section 3(42) of
ERISA provide guidance with respect to whether, in certain
circumstances, the assets of an entity in which Employee Benefit
Plans acquire equity interests would be deemed plan
assets. Under these rules, an entitys assets would
not be considered to be plan assets if, among other
things:
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the equity interests acquired by the Employee Benefit Plan are
publicly offered securitiesi.e., the equity interests are
widely held by 100 or more investors independent of the
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193
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issuer and each other, are freely transferable and are
registered under certain provisions of the federal securities
laws;
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the entity is an operating company,i.e., it is
primarily engaged in the production or sale of a product or
service, other than the investment of capital, either directly
or through a majority-owned subsidiary or subsidiaries; or
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there is no significant investment by benefit plan
investors, which is generally defined to mean that less
than 25% of the value of each class of equity interest,
disregarding any such interests held by our general partner, its
affiliates and certain persons, is held by the Employee Benefit
Plans.
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Our assets should not be considered plan assets
under these regulations because it is expected that the
investment will satisfy the requirements in the first two bullet
points above.
In light of the serious penalties imposed on persons who engage
in prohibited transactions or other violations, plan fiduciaries
contemplating a purchase of common units should consult with
their own counsel regarding the consequences under ERISA, the
Internal Revenue Code and other Similar Laws.
194
UNDERWRITING
RBC Capital Markets is acting as book-running manager of the
offering and as representative of the underwriters named below.
Subject to the terms and conditions stated in the underwriting
agreement dated the date of this prospectus, the underwriters
set forth below have agreed to purchase from us the number of
common units set forth opposite its name.
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Number of
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Underwriter
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Common Units
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RBC Capital Markets, LLC
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Raymond James & Associates, Inc.
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Wells Fargo Securities, LLC
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Robert W. Baird & Co. Incorporated
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Oppenheimer & Co. Inc.
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Total
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5,400,000
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The underwriting agreement provides that the underwriters
obligations to purchase the common units depend on the
satisfaction of the conditions contained in the underwriting
agreement and that if any of our common units are purchased by
the underwriters, all of our common units must be purchased. The
conditions contained in the underwriting agreement include the
condition that all the representations and warranties made by us
to the underwriters are true, that there has been no material
adverse change in the condition of us or in the financial
markets and that we deliver to the underwriters customary
closing documents.
The following table shows the underwriting fees to be paid to
the underwriters by us in connection with this offering. These
amounts are shown assuming both no exercise and full exercise of
the underwriters option to purchase additional common
units. This underwriting fee is the difference between the
initial price to the public and the amount the underwriters pay
to us to purchase the common units. On a per common unit basis,
the underwriting fee is % of the
initial price to the public.
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Paid by Us
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No Exercise
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Full Exercise
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Per common unit
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$
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$
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Total
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$
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$
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We estimate that total expenses of the offering, other than
underwriting discounts, a structuring fee and commissions, will
be approximately $3.0 million. We will pay RBC Capital
Markets, LLC a structuring fee equal to 0.375% of the gross
proceeds of this offering for the evaluation, analysis and
structuring of our partnership.
We have been advised by the underwriters that the underwriters
propose to offer our common units directly to the public at the
initial price to the public set forth on the cover page of this
prospectus and to dealers (who may include the underwriters) at
this price to the public less a concession not in excess of
$ per common unit. The
underwriters may allow, and the dealers may reallow, a
concession not in excess of $ per
common unit to certain brokers and dealers. After the offering,
the underwriters may change the offering price and other selling
terms.
We have agreed to indemnify the underwriters against certain
liabilities, including liabilities under the Securities Act or
to contribute to payments that may be required to be made with
respect to these liabilities.
We have granted to the underwriters an option to purchase up to
an aggregate of 810,000 additional common units at the initial
price to the public less the underwriting discount set forth on
the cover page of this prospectus exercisable solely to cover
over-allotments, if any. Such option may be exercised in whole
or in part at any time until 30 days after the date of this
prospectus. If
195
this option is exercised, each underwriter will be committed,
subject to satisfaction of the conditions specified in the
underwriting agreement, to purchase a number of additional
common units proportionate to the underwriters initial
commitment as indicated in the preceding table, and we will be
obligated, pursuant to the option, to sell these common units to
the underwriters.
We, our general partner and certain of its affiliates, including
the directors and executive officers of our general partner have
agreed that we will not, directly or indirectly, offer, sell,
short sell, contract to sell, pledge or otherwise dispose
of any common units or securities convertible into or
exchangeable or exercisable for common units, or enter into any
derivative transaction with similar effect, for a period of
180 days after the date of this prospectus without the
prior written consent of RBC Capital Markets, LLC. The
restrictions described in this paragraph do not apply to:
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the sale of common units to the underwriters;
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restricted common units issued by us under the long-term
incentive program or upon the exercise of options issued under
the long-term incentive program; or
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certain transfers to affiliates and certain bona fide gifts.
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The 180-day
restricted period described in the preceding paragraphs will be
extended if:
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during the last 17 days of the
180-day
restricted period we issue an earnings release or material news
or a material event relating to us occurs; or
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prior to the expiration of the
180-day
restricted period, we announce that we will release earnings
results during the
16-day
period beginning on the last day of the
180-day
period;
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in which case the restrictions described in the preceding
paragraph will continue to apply until the expiration of the
18-day
period beginning on the issuance of the earnings release or the
occurrence of the material news or material event.
RBC Capital Markets, LLC, in its sole discretion, may release
the common units subject to
lock-up
agreements in whole or in part at any time with or without
notice. When determining whether or not to release common units
from lock-up
agreements, RBC Capital Markets, LLC will consider, among other
factors, the unitholders reasons for requesting the
release, the number of common units for which the release is
being requested and market conditions at the time. However, RBC
Capital Markets, LLC has informed us that, as of the date of
this prospectus, there are no agreements between them and any
party that would allow such party to transfer any common units,
nor do they have any intention at this time of releasing any of
the common units subject to the
lock-up
agreements, prior to the expiration of the
lock-up
period.
Our partnership agreement requires that all common unitholders
be Eligible Holders. As used herein, an Eligible Holder means a
person or entity qualified to hold an interest in oil and gas
leases on federal lands. As of the date hereof, Eligible Holder
means: (1) a citizen of the United States; (2) a
corporation organized under the laws of the United States or of
any state thereof; (3) a public body, including a
municipality; (4) an association of United States citizens,
such as a partnership or limited liability company, organized
under the laws of the United States or of any state thereof, but
only if such association does not have any direct or indirect
foreign ownership, other than foreign ownership of stock in a
parent corporation organized under the laws of the United States
or of any state thereof; or (5) a limited partner whose
nationality, citizenship or other related status would not, in
the determination of our general partner, create a substantial
risk of cancellation or forfeiture of any property in which we
or our subsidiary has an interest. For the avoidance of doubt,
onshore mineral leases or any direct or indirect interest
therein may be acquired and held by aliens only through stock
ownership, holding or control in a corporation organized under
the laws of the United States or of any state thereof.
196
In connection with this offering, the underwriters may engage in
stabilizing transactions, over-allotment transactions, syndicate
covering transactions and penalty bids in accordance with
Regulation M under the Securities Exchange Act of 1934.
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Stabilizing transactions permit bids to purchase the underlying
security so long as the stabilizing bids do not exceed a
specified maximum.
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Over-allotment transactions involve sales by the underwriters of
the common units in excess of the number of common units the
underwriters are obligated to purchase, which creates a
syndicate short position. The short position may be either a
covered short position or a naked short position. In a covered
short position, the number of common units over-allotted by the
underwriters is not greater than the number of common units they
may purchase in their option to purchase additional common
units. In a naked short position, the number of common units
involved is greater than the number of common units in the
underwriters option to purchase additional common units.
The underwriters may close out any short position by either
exercising their option
and/or
purchasing common units in the open market.
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Syndicate covering transactions involve purchases of the common
units in the open market after the distribution has been
completed in order to cover syndicate short positions. In
determining the source of the common units to close out the
short position, the underwriters will consider, among other
things, the price of common units available for purchase in the
open market as compared to the price at which they may purchase
common units through their option. If the underwriters sell more
common units than could be covered by their option to purchase
additional common units, which we refer to in this prospectus as
a naked short position, the position can only be closed out by
buying common units in the open market. A naked short position
is more likely to be created if the underwriters are concerned
that there could be downward pressure on the price of the common
units in the open market after pricing that could adversely
affect investors who purchase in the offering.
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Penalty bids permit the representatives to reclaim a selling
concession from a syndicate member when the common units
originally sold by the syndicate member are purchased in a
stabilizing or syndicate covering transaction to cover syndicate
short positions.
Similar to other purchase transactions, the underwriters
purchases to cover the syndicate short sales may have the effect
of raising or maintaining the market price of the common units
or preventing or retarding a decline in the market price of the
common units. As a result, the price of the common units may be
higher than the price that might otherwise exist in the open
market.
These stabilizing transactions, syndicate covering transactions
and penalty bids may have the effect of raising or maintaining
the market price of our common units or preventing or retarding
a decline in the market price of the common units. As a result,
the price of the common units may be higher than the price that
might otherwise exist in the open market. These transactions may
be effected on the NASDAQ Global Market or otherwise and, if
commenced, may be discontinued at any time.
Neither we nor any of the underwriters make any representation
or prediction as to the direction or magnitude of any effect
that the transactions described above may have on the price of
the common units. In addition, neither we nor any of the
underwriters make any representation that the underwriters will
engage in these stabilizing transactions or that any
transaction, if commenced, will not be discontinued without
notice.
We have been approved to list our common units on the NASDAQ
Global Market under the symbol MCEP.
197
The underwriters may, from time to time, engage in transactions
with and perform services for us in the ordinary course of their
business for which they may receive customary fees and
reimbursement of expenses. Additionally, affiliates of certain
of the underwriters will serve as lenders under our new credit
facility. An affiliate of Wells Fargo Securities, LLC will serve
as the transfer agent and registrar for the common units.
Because the Financial Industry Regulatory Authority views our
common units as interests in a direct participation program,
this offering is being made in compliance with Rule 2310 of
the FINRA rules. Investor suitability with respect to the common
units will be judged similarly to the suitability with respect
to other securities that are listed for trading on a national
securities exchange.
No sales to accounts over which any underwriter exercises
discretionary authority in excess of 5% of the units offered by
them may be made without the prior written approval of the
customer.
A prospectus in electronic format may be made available on the
Internet sites or through other online services maintained by
one or more of the underwriters
and/or
selling group members participating in this offering, or by
their affiliates. In those cases, prospective investors may view
offering terms online and, depending upon the particular
underwriter or selling group member, prospective investors may
be allowed to place orders online. The underwriters may agree
with us to allocate a specific number of common units for sale
to online brokerage account holders. Any such allocation for
online distributions will be made by the underwriters on the
same basis as other allocations.
Other than the prospectus in electronic format, information
contained in any other web site maintained by an underwriter or
selling group member is not part of this prospectus or the
registration statement of which this prospectus forms a part,
has not been endorsed by us and should not be relied on by
investors in deciding whether to purchase any units. The
underwriters and selling group members are not responsible for
information contained in web sites that they do not maintain.
Offering
Price Determination
Prior to this offering, there has been no public market for the
common units. The initial public offering price was determined
by negotiation between us and the underwriters. The principal
factors considered in determining the public offering price
included the following:
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the information set forth in this prospectus and otherwise
available to the underwriters;
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our history and prospects and the history and prospects for the
industry in which we will compete;
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the ability of our management;
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our prospects for future cash flow;
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the present state of our development and our current financial
condition;
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market conditions for initial public offerings and the general
condition of the securities markets at the time of this
offering; and
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the recent market prices of, and the demand for, publicly traded
units of generally comparable entities.
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198
VALIDITY
OF THE COMMON UNITS
The validity of the common units will be passed upon for us by
GableGotwals, Tulsa, Oklahoma. Certain tax matters will be
passed upon for us by Andrews Kurth LLP. Certain legal matters
in connection with the common units offered by us will be passed
upon for the underwriters by Latham & Watkins LLP,
Houston, Texas.
199
EXPERTS
The audited balance sheet of Mid-Con Energy Partners, LP as of
July 29, 2011 included in this prospectus and elsewhere in
the registration statement has been so included in reliance on
the report of Grant Thornton LLP, independent registered public
accountants, upon the authority of said firm as experts in
auditing and accounting in giving said report.
The audited financial statements of Mid-Con Energy Corporation
and the audited combined financial statements of Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC included in this
prospectus and elsewhere in the registration statement have been
so included in reliance upon the reports of Grant Thornton LLP,
independent registered public accountants, upon the authority of
said firm as experts in auditing and accounting in giving said
reports.
Estimated quantities of our proved oil and natural gas reserves
and the net present value of such reserves as of
December 31, 2010 and September 30, 2011 set forth in
this prospectus are based upon reserve reports prepared by our
internal reservoir engineers and audited by Cawley,
Gillespie & Associates, Inc.
200
WHERE YOU
CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement on
Form S-l
regarding our common units. This prospectus, which constitutes
part of the registration statement, does not contain all of the
information set forth in the registration statement. For further
information regarding us and our common units offered in this
prospectus, we refer you to the full registration statement,
including its exhibits and schedules, filed under the Securities
Act. The full registration statement, of which this prospectus
forms a part, including its exhibits and schedules, may be
inspected and copied at the public reference room maintained by
the SEC at 100 F Street, NE, Room 1580,
Washington, D.C. 20549. Copies of these materials may
also be obtained from the SEC at prescribed rates by writing to
the public reference room maintained by the SEC at
100 F Street, NE, Room 1580,
Washington, D.C. 20549. The registration statement, of
which this prospectus forms a part, can also be downloaded from
the SECs web site on the Internet at
http://www.sec.gov.
You may obtain information on the operation of the public
reference room by calling the SEC at
1-800-SEC-0330.
We intend to furnish or make available to our unitholders annual
reports containing our audited financial statements and furnish
or make available quarterly reports containing our unaudited
interim financial information, including the information
required by
Form 10-Q,
for the first three fiscal quarters of each of our fiscal years.
Additionally, we intend to file other periodic reports with the
SEC, as required by the Securities Exchange Act of 1934.
201
FORWARD-LOOKING
STATEMENTS
This prospectus contains forward-looking statements that are
subject to a number of risks and uncertainties, many of which
are beyond our control, which may include statements about our:
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business strategies;
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ability to replace the reserves we produce through acquisitions
and the development of our properties;
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oil and natural gas reserves;
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technology;
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realized oil and natural gas prices;
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production volumes;
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lease operating expenses;
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general and administrative expenses;
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future operating results;
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cash flow and liquidity;
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availability of production equipment;
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availability of oil field labor;
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capital expenditures;
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availability and terms of capital;
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marketing of oil and natural gas;
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general economic conditions;
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competition in the oil and natural gas industry;
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effectiveness of risk management activities;
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environmental liabilities;
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counterparty credit risk;
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governmental regulation and taxation;
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developments in oil producing and natural gas producing
countries; and
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plans, objectives, expectations and intentions.
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These types of statements, other than statements of historical
fact included in this prospectus, are forward-looking
statements. These forward-looking statements may be found in
Prospectus Summary, Risk Factors,
Our Cash Distribution Policy and Restrictions on
Distributions, Managements Discussion and
Analysis of Financial Condition and Results of Operations,
Business and Properties and other sections of this
prospectus. In some cases, you can identify forward-looking
statements by terminology such as may,
will, could, should,
expect, plan, project,
intend, anticipate, believe,
estimate, predict,
potential, pursue, target,
continue, the negative of such terms or other
comparable terminology.
202
The forward-looking statements contained in this prospectus are
largely based on our expectations, which reflect estimates and
assumptions made by our management. These estimates and
assumptions reflect our best judgment based on currently known
market conditions and other factors. Although we believe such
estimates and assumptions to be reasonable, they are inherently
uncertain and involve a number of risks and uncertainties that
are beyond our control. In addition, managements
assumptions about future events may prove to be inaccurate. All
readers are cautioned that the forward-looking statements
contained in this prospectus are not guarantees of future
performance, and we cannot assure any reader that such
statements will be realized or that the forward-looking events
and circumstances will occur. Actual results may differ
materially from those anticipated or implied in the
forward-looking statements due to factors described in
Risk Factors and elsewhere in this prospectus. All
forward-looking statements speak only as of the date of this
prospectus. We do not intend to update or revise any
forward-looking statements as a result of new information,
future events or otherwise. These cautionary statements qualify
all forward-looking statements attributable to us or persons
acting on our behalf.
203
INDEX TO
FINANCIAL STATEMENTS
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Page
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MID-CON ENERGY PARTNERS, LP
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Unaudited Pro Forma
Condensed Financial Statements:
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Introduction
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F-2
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Unaudited Pro Forma Condensed Balance Sheet as of
September 30, 2011
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F-3
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Unaudited Pro Forma Condensed Statement of Operations for the
Nine Months Ended September 30, 2011
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F-4
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Unaudited Pro Forma Condensed Statement of Operations for the
Twelve Months Ended December 31, 2010
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F-5
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Notes to Unaudited Pro Forma Condensed Financial Statements
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F-6
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Historical Balance Sheet:
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Report of Independent Registered Public Accounting Firm
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F-9
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Balance Sheet as of July 29, 2011
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F-10
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Note to Balance Sheet
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F-11
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PREDECESSOR
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Unaudited Historical
Combined Financial Statements as of December 31, 2010 and
September 30, 2011 and for the Nine Months Ended
September 30, 2010 and 2011:
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Unaudited Combined Balance Sheets
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F-12
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Unaudited Combined Statements of Operations
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F-13
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Unaudited Combined Statements of Members Equity
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F-14
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Unaudited Combined Statements of Cash Flows
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F-15
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Notes to Unaudited Combined Financial Statements
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F-16
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Historical Combined
Financial Statements as of December 31, 2009 and 2010 and
for the period from inception (July 1, 2009) to
December 31, 2009 and for the year ended December 31,
2010:
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Report of Independent Registered Public Accounting Firm
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F-27
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Combined Balance Sheets
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F-28
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Combined Statements of Operations
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F-29
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Combined Statements of Members Equity
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F-30
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Combined Statements of Cash Flows
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F-31
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Notes to Combined Financial Statements
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F-32
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Historical Consolidated
Financial Statements for the years ended June 30, 2008 and
2009:
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Report of Independent Registered Public Accounting Firm
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F-52
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Consolidated Statements of Operations
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F-53
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Consolidated Statements of Stockholders Equity
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F-54
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Consolidated Statements of Cash Flows
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F-55
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Notes to Consolidated Financial Statements
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F-56
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F-1
Mid-Con
Energy Partners, LP
Unaudited
Pro Forma Condensed Financial Statements
Introduction
The following unaudited pro forma condensed financial statements
of Mid-Con Energy Partners, LP (the Partnership) are
derived from the audited and unaudited historical combined
results of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
(collectively, the predecessor). The pro forma
condensed financial statements give pro forma effect to
formation and offering related transactions described in
Note 1 to these financial statements. The unaudited pro
forma condensed financial statements have been prepared on the
basis that the Partnership will be treated as a partnership for
federal income tax purposes. The unaudited pro forma condensed
financial statements should be read in conjunction with the
notes accompanying these unaudited pro forma condensed financial
statements and with the audited and unaudited historical
combined financial statements and related notes of the
predecessor found elsewhere in this prospectus.
The pro forma adjustments to the audited historical financial
statements are based upon currently available information and
certain estimates and assumptions. The actual effect of the
transactions discussed in the accompanying notes ultimately may
differ from the unaudited pro forma adjustments included herein.
However, management believes that the assumptions utilized to
prepare the pro forma adjustments provide a reasonable basis for
presenting the significant effects of the transactions as
currently contemplated and that the unaudited pro forma
adjustments are factually supportable, give appropriate effect
to the expected impact of events that are directly attributable
to the transactions, and reflect those items expected to have a
continuing impact on the Partnership.
The unaudited pro forma condensed financial statements of the
Partnership are not necessarily indicative of the results that
actually would have occurred if the Partnership had completed
the transactions described above on the dates indicated or that
could be achieved in the future.
F-2
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Mid-Con
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Offering and
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Energy
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Predecessor
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Other
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Pro Forma,
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Historical
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Adjustments
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As Adjusted
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(in thousands)
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ASSETS
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Current Assets:
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Cash and cash equivalents
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$
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186
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$
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29,790
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(a)
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$
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108,000
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(b)
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1,936
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(c)
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(139,912
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)
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(d)
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Accounts receivable:
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|
|
Oil and natural gas sales
|
|
|
3,091
|
|
|
|
|
|
|
|
|
|
|
|
3,091
|
|
Affiliate
|
|
|
355
|
|
|
|
|
|
(355
|
)
|
|
(d)
|
|
|
|
|
Other
|
|
|
1,042
|
|
|
|
|
|
(1,021
|
)
|
|
(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21
|
)
|
|
(k)
|
|
|
|
|
Derivative financial instruments
|
|
|
3,980
|
|
|
|
|
|
|
|
|
|
|
|
3,980
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
8,654
|
|
|
|
|
|
(1,583
|
)
|
|
|
|
|
7,071
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and Equipment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties, successful efforts method:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
83,639
|
|
|
|
|
|
6,000
|
|
|
(j)
|
|
|
89,639
|
|
Unproved properties
|
|
|
162
|
|
|
|
|
|
|
|
|
|
|
|
162
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(8,589
|
)
|
|
|
|
|
(469
|
)
|
|
(j)
|
|
|
(9,058
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
75,212
|
|
|
|
|
|
5,531
|
|
|
|
|
|
80,743
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
300
|
|
|
|
|
|
(300
|
)
|
|
(e)
|
|
|
|
|
Derivative Financial Instruments
|
|
|
4,516
|
|
|
|
|
|
47
|
|
|
(j)
|
|
|
4,563
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
88,682
|
|
|
|
|
$
|
3,695
|
|
|
|
|
$
|
92,377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
1,795
|
|
|
|
|
$
|
|
|
|
|
|
$
|
1,795
|
|
Accrued liabilities
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
30
|
|
Revenue payable
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
1,835
|
|
|
|
|
|
|
|
|
|
|
|
1,835
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt
|
|
|
15,210
|
|
|
|
|
|
29,790
|
|
|
(a)
|
|
|
45,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligations
|
|
|
1,682
|
|
|
|
|
|
|
|
|
|
|
|
1,682
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners Capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contributed capital
|
|
|
71,891
|
|
|
|
|
|
108,000
|
|
|
(b)
|
|
|
43,860
|
|
|
|
|
|
|
|
|
|
|
(141,309
|
)
|
|
(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(300
|
)
|
|
(e)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,578
|
|
|
(j)
|
|
|
|
|
Notes receivable from officers, directors and employees
|
|
|
(1,936
|
)
|
|
|
|
|
1,936
|
|
|
(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
69,955
|
|
|
|
|
|
(26,095
|
)
|
|
|
|
|
43,860
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
88,682
|
|
|
|
|
$
|
3,695
|
|
|
|
|
$
|
92,377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these pro
forma financial statements.
F-3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Con
|
|
|
|
|
|
|
|
|
|
Mid-Con
|
|
|
|
|
|
Offering and
|
|
|
|
|
|
Energy
|
|
|
|
Predecessor
|
|
|
Disposed
|
|
|
Energy
|
|
|
|
|
|
Other
|
|
|
|
|
|
Pro Forma,
|
|
|
|
Historical
|
|
|
Assets
|
|
|
Pro Forma
|
|
|
|
|
|
Adjustments
|
|
|
|
|
|
As Adjusted
|
|
|
|
(in thousands)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
25,068
|
|
|
$
|
(721
|
)(f)
|
|
$
|
24,347
|
|
|
|
|
|
|
$
|
693
|
(j)
|
|
|
|
|
|
$
|
25,040
|
|
Natural gas sales
|
|
|
974
|
|
|
|
|
|
|
|
974
|
|
|
|
|
|
|
|
4
|
(j)
|
|
|
|
|
|
|
978
|
|
Realized gain (loss) on derivatives, net
|
|
|
(799
|
)
|
|
|
|
|
|
|
(799
|
)
|
|
|
|
|
|
|
(76
|
)(j)
|
|
|
|
|
|
|
(875
|
)
|
Unrealized gain (loss) on derivatives, net
|
|
|
9,400
|
|
|
|
|
|
|
|
9,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
34,643
|
|
|
|
(721
|
)
|
|
|
33,922
|
|
|
|
|
|
|
|
621
|
|
|
|
|
|
|
|
34,543
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
5,951
|
|
|
|
(583
|
)(f)
|
|
|
5,368
|
|
|
|
|
|
|
|
232
|
(j)
|
|
|
|
|
|
|
5,600
|
|
Oil and gas production taxes
|
|
|
1,116
|
|
|
|
(46
|
)(f)
|
|
|
1,070
|
|
|
|
|
|
|
|
49
|
(j)
|
|
|
|
|
|
|
1,119
|
|
Dry holes and abandonments of unproved properties
|
|
|
772
|
|
|
|
|
|
|
|
772
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
772
|
|
Geological and geophysical
|
|
|
171
|
|
|
|
(171
|
)(f)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
4,318
|
|
|
|
(338
|
)(g)
|
|
|
3,980
|
|
|
|
|
|
|
|
148
|
(j)
|
|
|
|
|
|
|
4,128
|
|
Accretion of discount on asset retirement obligations
|
|
|
55
|
|
|
|
|
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55
|
|
General and administrative
|
|
|
552
|
|
|
|
|
|
|
|
552
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
552
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
12,935
|
|
|
|
(1,138
|
)
|
|
|
11,797
|
|
|
|
|
|
|
|
429
|
|
|
|
|
|
|
|
12,226
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
21,708
|
|
|
|
417
|
|
|
|
22,125
|
|
|
|
|
|
|
|
192
|
|
|
|
|
|
|
|
22,317
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income and other
|
|
|
160
|
|
|
|
|
|
|
|
160
|
|
|
|
|
|
|
|
(58
|
)(h)
|
|
|
|
|
|
|
102
|
|
Interest expense
|
|
|
(378
|
)
|
|
|
|
|
|
|
(378
|
)
|
|
|
|
|
|
|
(635
|
)(i)
|
|
|
|
|
|
|
(1,013
|
)
|
Gain on sale of assets
|
|
|
1,559
|
|
|
|
(1,559
|
)(f)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation
|
|
|
(1,671
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,671
|
)
|
Other revenue and expense, net
|
|
|
576
|
|
|
|
(576
|
)(f)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expenses)
|
|
|
246
|
|
|
|
(2,135
|
)
|
|
|
(1,889
|
)
|
|
|
|
|
|
|
978
|
|
|
|
|
|
|
|
(2,582
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
21,954
|
|
|
$
|
(1,718
|
)
|
|
$
|
20,236
|
|
|
|
|
|
|
$
|
1,170
|
|
|
|
|
|
|
$
|
19,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Computation of net income per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
395
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
19,340
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of limited partner units outstanding
(basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these pro
forma financial statements.
F-4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Con
|
|
|
|
|
|
|
|
|
|
Mid-Con
|
|
|
|
|
|
Offering and
|
|
|
|
|
|
Energy
|
|
|
|
Predecessor
|
|
|
Disposed
|
|
|
Energy
|
|
|
|
|
|
Other
|
|
|
|
|
|
Pro Forma,
|
|
|
|
Historical
|
|
|
Assets
|
|
|
Pro Forma
|
|
|
|
|
|
Adjustments
|
|
|
|
|
|
As Adjusted
|
|
|
|
(in thousands)
|
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
16,853
|
|
|
$
|
(1,337
|
)(f)
|
|
$
|
15,516
|
|
|
|
|
|
|
$
|
770
|
(j)
|
|
|
|
|
|
$
|
16,286
|
|
Natural gas sales
|
|
|
1,418
|
|
|
|
(26
|
)(f)
|
|
|
1,392
|
|
|
|
|
|
|
|
5
|
(j)
|
|
|
|
|
|
|
1,397
|
|
Realized gain (loss) on derivatives, net
|
|
|
(90
|
)
|
|
|
|
|
|
|
(90
|
)
|
|
|
|
|
|
|
(10
|
)(j)
|
|
|
|
|
|
|
(100
|
)
|
Unrealized gain (loss) on derivatives, net
|
|
|
(707
|
)
|
|
|
|
|
|
|
(707
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(707
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
17,474
|
|
|
|
(1,363
|
)
|
|
|
16,111
|
|
|
|
|
|
|
|
765
|
|
|
|
|
|
|
|
16,876
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
6,237
|
|
|
|
(1,449
|
)(f)
|
|
|
4,788
|
|
|
|
|
|
|
|
253
|
(j)
|
|
|
|
|
|
|
5,041
|
|
Oil and gas production taxes
|
|
|
822
|
|
|
|
(81
|
)(f)
|
|
|
741
|
|
|
|
|
|
|
|
56
|
(j)
|
|
|
|
|
|
|
797
|
|
Dry holes and abandonments of unproved properties
|
|
|
1,418
|
|
|
|
(904
|
)(f)
|
|
|
514
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
514
|
|
Geological and geophysical
|
|
|
394
|
|
|
|
(394
|
)(f)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
5,851
|
|
|
|
(2,837
|
)(g)
|
|
|
3,014
|
|
|
|
|
|
|
|
313
|
(j)
|
|
|
|
|
|
|
3,327
|
|
Accretion of discount on asset retirement obligations
|
|
|
127
|
|
|
|
(64
|
)(f)
|
|
|
63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
63
|
|
General and administrative
|
|
|
982
|
|
|
|
|
|
|
|
982
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
982
|
|
Impairment of proved oil and gas properties
|
|
|
1,886
|
|
|
|
(626
|
)(f)
|
|
|
1,260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
17,717
|
|
|
|
(6,355
|
)
|
|
|
11,362
|
|
|
|
|
|
|
|
622
|
|
|
|
|
|
|
|
11,984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(243
|
)
|
|
|
4,992
|
|
|
|
4,749
|
|
|
|
|
|
|
|
143
|
|
|
|
|
|
|
|
4,892
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income and other
|
|
|
218
|
|
|
|
|
|
|
|
218
|
|
|
|
|
|
|
|
(92
|
)(h)
|
|
|
|
|
|
|
126
|
|
Interest expense
|
|
|
(98
|
)
|
|
|
|
|
|
|
(98
|
)
|
|
|
|
|
|
|
(1,252
|
)(i)
|
|
|
|
|
|
|
(1,350
|
)
|
Gain on sale of assets
|
|
|
354
|
|
|
|
(354
|
)(f)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other revenue and expense, net
|
|
|
847
|
|
|
|
(847
|
)(f)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expenses)
|
|
|
1,321
|
|
|
|
(1,201
|
)
|
|
|
120
|
|
|
|
|
|
|
|
(1,344
|
)
|
|
|
|
|
|
|
(1,224
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
1,078
|
|
|
$
|
3,791
|
|
|
$
|
4,869
|
|
|
|
|
|
|
$
|
(1,201
|
)
|
|
|
|
|
|
$
|
3,668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Computation of net income per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,595
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of limited partner units outstanding
(basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these pro
forma financial statements.
F-5
NOTES TO
UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS
The unaudited pro forma condensed balance sheet of the
Partnership as of September 30, 2011 is based on the
unaudited historical combined balance sheet of the predecessor
and includes pro forma adjustments to give effect to the
formation and the offering as described below as if they
occurred on September 30, 2011.
The unaudited pro forma condensed statement of operations of the
Partnership is based on the unaudited historical combined
statement of operations of the predecessor for the nine months
ended September 30, 2011 and the audited historical
combined statement of operations of the predecessor for the year
ended December 31, 2010 and includes pro forma adjustments
to give effect to the transactions described below as if they
occurred on January 1, 2010.
The unaudited pro forma condensed financial statements give pro
forma effect to:
|
|
|
|
|
the sale by the predecessor as of June 30, 2011 of certain
oil and natural gas properties representing less than 1% of its
proved reserves by value, as calculated using the standardized
measure, as of September 30, 2011, and certain subsidiaries
that do not own oil and natural gas reserves, including Mid-Con
Energy Operating, Inc. (collectively, the Disposed
Assets), to Mid-Con Energy III, LLC and Mid-Con Energy IV,
LLC (collectively, the Mid-Con Affiliates) for
aggregate consideration of $7.5 million;
|
|
|
|
|
|
the merger of the predecessor with the Partnerships wholly
owned subsidiary (the Merger) in exchange for
aggregate consideration of 12,240,000 common units and
$121.2 million in cash;
|
|
|
|
|
|
the issuance to Mid-Con Energy GP, LLC, the Partnerships
general partner, of 360,000 general partner units, representing
a 2.0% general partner interest in the Partnership in exchange
for a contribution from our general partner;
|
|
|
|
|
|
the issuance and sale by the Partnership to the public of
5,400,000 common units (the Offering) and the
application of the net proceeds as described in Use of
Proceeds;
|
|
|
|
|
|
the Partnerships borrowing of approximately
$45.0 million under its new credit facility and the
application of the proceeds as described in Use of
Proceeds; and
|
|
|
|
our acquisition of additional working interests in the Cushing
Field from J&A Oil Company and Charles R. Olmstead
immediately prior to the closing of this offering.
|
The Merger has been accounted for as a combination of entities
under common control, whereby the assets and liabilities sold
and contributed will be recorded based on the predecessors
historical cost.
The historical balance sheet at September 30, 2011 of the
predecessor reflects the sale of the Disposed Assets. Because
the sale was effective as of June 30, 2011, no pro forma
adjustments to the historical balance sheet of the predecessor
are necessary to reflect the sale. However, the historical
statements of operations of the predecessor for the year ended
December 31, 2010 and the nine months ended
September 30, 2011 include the results of operations
attributable to the Disposed Assets. Accordingly, the
Partnerships unaudited pro forma condensed statements of
operations for the year ended December 31, 2010 and the
nine months ended September 30, 2011 include adjustments to
reflect the sale of the Disposed Assets.
The Partnerships unaudited pro forma condensed statements
of operations do not reflect the incremental general and
administrative expenses of approximately $3.0 million that
the Partnership expects to incur annually as a result of being a
publicly traded partnership.
F-6
NOTES TO
UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS
(continued)
|
|
2.
|
Pro Forma
Adjustments and Assumptions
|
Unaudited
pro forma condensed balance sheet
(a) Pro forma adjustment to reflect the cash proceeds from
borrowings by the Partnership of $45.0 million under its
new revolving credit facility. Pro forma adjustment reflects
additional amount to reflect the new credit facility.
(b) Pro forma adjustment to reflect gross cash proceeds of
approximately $108.0 million from the issuance and sale of
5,400,000 common units in the offering at an assumed
initial public offering of $20.00 per unit.
(c) Pro forma adjustment to record the net proceeds from
the payment of the notes receivable of the predecessors
members.
(d) Pro forma adjustment to record the use of the net
proceeds from the offering and borrowings under the
Partnerships new credit facility, after underwriting
discounts and commissions, a structuring fee and estimated
offering and borrowing expenses of approximately
$10.6 million, to repay $15.2 million in outstanding
indebtedness under the predecessors credit facilities and
to make a $121.2 million cash distribution to the owners of
the predecessor.
(e) Pro forma adjustment to record retirement of interest
on notes receivable from members.
Unaudited
pro forma statements of operations
(f) Pro forma adjustment to reflect the revenues and direct
operating expenses excluding the Disposed Assets. These
adjustments are based on the actual results of the Disposed
Assets. Historical lease operating statements by individual
asset were used as the basis for the revenues and direct lease
operating expenses.
(g) Pro forma adjustment to reflect the depreciation,
depletion and amortization expenses associated with the Disposed
Assets. The calculations based on the actual allocated costs of
the Disposed Assets and the associated production and reserves
as if the sale of the Disposed Assets had occurred on
January 1, 2010.
(h) Pro forma adjustment to reflect interest income on the
notes receivables from officers, directors and employees from
the issuances of the predecessors units.
(i) Pro forma adjustment to reflect interest expense and
amortization of deferred financing costs on $45.0 million
of borrowings by the Partnership under a new credit facility
assuming an interest rate of approximately 3.0%. A one-eighth
percentage point change in the interest rate would change pro
forma interest expense by less than $42,000 for the nine months
ended September 30, 2011.
(j) Pro forma adjustments to reflect the acquisition of
working interests in the Cushing Field from J&A Oil
Company, LLC and Charles R. Olmstead prior to the closing of the
Offering.
(k) Pro forma adjustments to reflect issuance of
predecessors units.
|
|
3.
|
Pro Forma
Net Income Per Limited Partner Unit
|
Pro forma net income per limited partner unit is determined by
dividing the pro forma net income available to the holders of
common units, after deducting the general partners 2.0%
interest in pro forma net income, by the number of common units
expected to be outstanding at the closing of the Offering. For
purposes of this calculation, management assumed the aggregate
F-7
NOTES TO
UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS
(continued)
number of common units was $17,640,000. All units were assumed
to have been outstanding since January 1, 2010.
|
|
4.
|
Pro Forma
Standardized Measure of Discounted Future Net Cash
Flow
|
Standardized
Measure of Future Net Cash Flow
The table below reflects the pro forma standardized measure of
discounted future net cash flow related to the
Partnerships interest in proved reserves as of
December 31, 2010:
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Future cash flow
|
|
$
|
523,095
|
|
Future production costs
|
|
|
(149,591
|
)
|
Future development costs
|
|
|
(26,802
|
)
|
|
|
|
|
|
Future net cash flow
|
|
|
346,702
|
|
10% discount for estimated timing of cash flow
|
|
|
(164,563
|
)
|
|
|
|
|
|
Standardized measure of discounted future net cash flow
|
|
$
|
182,139
|
|
|
|
|
|
|
The principal changes in the pro forma standardized measure of
discounted future net cash flow attributable to the
Partnerships proved reserves as of December 31, 2010
are as follows:
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Standardized measure of discounted future net cash flow,
beginning of period
|
|
$
|
98,036
|
|
Changes in the year resulting from:
|
|
|
|
|
Sales, less production costs
|
|
|
(11,379
|
)
|
Revisions of previous quantity estimates
|
|
|
3,964
|
|
Extensions and discoveries, and improved recovery
|
|
|
16,562
|
|
Net changes in prices and production costs
|
|
|
41,030
|
|
Changes in estimated future development costs
|
|
|
(5,232
|
)
|
Previously estimated development costs incurred during the period
|
|
|
9,343
|
|
Purchase of minerals in place
|
|
|
22,330
|
|
Accretion of discount
|
|
|
9,804
|
|
Timing differences and other
|
|
|
(2,319
|
)
|
|
|
|
|
|
Standardized measure of discounted future net cash flow, end of
period
|
|
$
|
182,139
|
|
|
|
|
|
|
F-8
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors
Mid-Con Energy GP, LLC
We have audited the accompanying balance sheet of Mid-Con Energy
Partners, LP (a Delaware limited partnership) as of
July 29, 2011. This financial statement is the
responsibility of the Partnerships management. Our
responsibility is to express an opinion on this financial
statement based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statement is
free of material misstatement. The Partnership is not required
to have, nor were we engaged to perform, an audit of its
internal control over financial reporting. Our audit included
consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Partnerships internal control
over financial reporting. Accordingly, we express no such
opinion. An audit also includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audit provides a reasonable basis for our opinion.
In our opinion, the balance sheet referred to above presents
fairly, in all material respects, the financial position of
Mid-Con Energy Partners, LP as of July 29, 2011, in
conformity with accounting principles generally accepted in the
United States of America.
Tulsa, Oklahoma
August 12, 2011
F-9
Mid-Con
Energy Partners, LP
Balance
Sheet
July 29,
2011
|
|
|
|
|
Assets:
|
|
|
|
|
Cash
|
|
$
|
1,000
|
|
|
|
|
|
|
Total Assets
|
|
$
|
1,000
|
|
|
|
|
|
|
Partners Capital:
|
|
|
|
|
Limited Partners Capital
|
|
$
|
980
|
|
General Partners Capital
|
|
|
20
|
|
|
|
|
|
|
Total Partners Capital
|
|
$
|
1,000
|
|
|
|
|
|
|
The accompanying note is an integral part of this balance
sheet.
F-10
|
|
1.
|
Organization
and Operations
|
Mid-Con Energy Partners, LP (the Partnership) is a
Delaware limited partnership formed on July 29, 2011 to
own, operate, acquire, exploit and develop producing oil and
natural gas properties in the Mid-Continent region of the United
States. In connection with its formation, the Partnership issued
(a) a 2.0% general partner interest to Mid-Con Energy GP,
LLC, its general partner, and (b) a 98.0% limited partner
interest to Mr. S. Craig George, its organizational limited
partner.
Mid-Con Energy GP, LLC, as general partner, contributed $20 and
S. Craig George, as the organizational limited partner,
contributed $980 to the Partnership as of July 29, 2011.
The accompanying balance sheet reflects the financial position
of the Partnership immediately subsequent to this initial
capitalization. There have been no other transactions involving
the Partnership as of July 29, 2011.
F-11
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Combined
Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2010
|
|
|
2011
|
|
|
|
(unaudited, in thousands)
|
|
|
|
(as restated,
|
|
|
|
|
|
|
see Note 9)
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
222
|
|
|
$
|
186
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
|
2,134
|
|
|
|
3,091
|
|
Joint operations and other
|
|
|
1,548
|
|
|
|
1,042
|
|
Due to affiliates
|
|
|
|
|
|
|
355
|
|
Certificate of depositgovernment bond
|
|
|
150
|
|
|
|
|
|
Inventory
|
|
|
771
|
|
|
|
|
|
Prepaids and other
|
|
|
147
|
|
|
|
|
|
Derivative financial instruments
|
|
|
|
|
|
|
3,980
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
4,972
|
|
|
|
8,654
|
|
|
|
|
|
|
|
|
|
|
Property and Equipment:
|
|
|
|
|
|
|
|
|
Oil and gas properties, successful efforts method:
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
57,364
|
|
|
|
83,639
|
|
Unproved properties
|
|
|
446
|
|
|
|
162
|
|
Other property and equipment
|
|
|
2,324
|
|
|
|
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(8,478
|
)
|
|
|
(8,589
|
)
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
51,656
|
|
|
|
75,212
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
239
|
|
|
|
300
|
|
Derivative Financial Instruments
|
|
|
|
|
|
|
4,516
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
56,867
|
|
|
$
|
88,682
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS EQUITY
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
2,785
|
|
|
$
|
1,795
|
|
Accrued liabilities
|
|
|
399
|
|
|
|
30
|
|
Revenue payable
|
|
|
182
|
|
|
|
10
|
|
Advance billings and other
|
|
|
1,864
|
|
|
|
|
|
Current portion of long-term debt
|
|
|
5,354
|
|
|
|
|
|
Derivative financial instruments
|
|
|
904
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
11,488
|
|
|
|
1,835
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt
|
|
|
159
|
|
|
|
15,210
|
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligations
|
|
|
2,148
|
|
|
|
1,682
|
|
|
|
|
|
|
|
|
|
|
Members Equity:
|
|
|
|
|
|
|
|
|
Contributed capital
|
|
|
52,923
|
|
|
|
56,284
|
|
Notes receivable from officers, directors and employees
|
|
|
(1,833
|
)
|
|
|
(1,936
|
)
|
(Accumulated deficit) retained earnings
|
|
|
(8,018
|
)
|
|
|
15,607
|
|
|
|
|
|
|
|
|
|
|
Total members equity
|
|
|
43,072
|
|
|
|
69,955
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and members equity
|
|
$
|
56,867
|
|
|
$
|
88,682
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these combined
balance sheets.
F-12
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Combined
Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2010
|
|
|
2011
|
|
|
|
(unaudited, in thousands)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
11,390
|
|
|
$
|
25,068
|
|
Natural gas sales
|
|
|
1,104
|
|
|
|
974
|
|
Realized loss on derivatives, net
|
|
|
(87
|
)
|
|
|
(799
|
)
|
Unrealized gain on derivatives, net
|
|
|
182
|
|
|
|
9,400
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
12,589
|
|
|
|
34,643
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
4,654
|
|
|
|
5,951
|
|
Oil and gas production taxes
|
|
|
522
|
|
|
|
1,116
|
|
Dry holes and abandonments of unproved properties
|
|
|
1,053
|
|
|
|
772
|
|
Geological and geophysical
|
|
|
253
|
|
|
|
171
|
|
Depreciation, depletion and amortization
|
|
|
4,743
|
|
|
|
4,318
|
|
Accretion of discount on asset retirement obligations
|
|
|
95
|
|
|
|
55
|
|
General and administrative
|
|
|
708
|
|
|
|
552
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
12,028
|
|
|
|
12,935
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
561
|
|
|
|
21,708
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest income and other
|
|
|
208
|
|
|
|
160
|
|
Interest expense
|
|
|
(59
|
)
|
|
|
(378
|
)
|
Gain on sale of assets
|
|
|
354
|
|
|
|
1,559
|
|
Stock-based compensation
|
|
|
|
|
|
|
(1,671
|
)
|
Other revenue and expense, net
|
|
|
501
|
|
|
|
576
|
|
|
|
|
|
|
|
|
|
|
Total other income (expenses)
|
|
|
1,004
|
|
|
|
246
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,565
|
|
|
$
|
21,954
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these combined
financial statements.
F-13
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Combined
Statements of Members Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivable
|
|
|
|
|
|
|
|
|
|
|
|
|
from Officers,
|
|
|
|
|
|
Total
|
|
|
|
Contributed
|
|
|
Directors and
|
|
|
Accumulated
|
|
|
Members
|
|
|
|
Capital
|
|
|
Employees
|
|
|
Deficit
|
|
|
Equity
|
|
|
|
(unaudited, in thousands)
|
|
|
Balance at December 31, 2010 (as restated, see Note 9)
|
|
$
|
52,923
|
|
|
$
|
(1,833
|
)
|
|
$
|
(8,018
|
)
|
|
$
|
43,072
|
|
Contribution
|
|
|
3,365
|
|
|
|
(106
|
)
|
|
|
|
|
|
|
3,259
|
|
Repurchase of member units
|
|
|
(4
|
)
|
|
|
3
|
|
|
|
|
|
|
|
(1
|
)
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
1,671
|
|
|
|
1,671
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
21,954
|
|
|
|
21,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2011
|
|
$
|
56,284
|
|
|
$
|
(1,936
|
)
|
|
$
|
15,607
|
|
|
$
|
69,955
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these combined
financial statements.
F-14
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Combined
Statements of Cash Flow
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
|
2010
|
|
|
2011
|
|
|
|
(unaudited, in thousands)
|
|
|
Cash Flows From Operating Activities:
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,565
|
|
|
$
|
21,954
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
4,743
|
|
|
|
4,318
|
|
Accretion of discount on asset retirement obligations
|
|
|
95
|
|
|
|
55
|
|
Dry holes and abandonments of unproved properties
|
|
|
1,053
|
|
|
|
772
|
|
Unrealized loss (gain) on derivative instruments, net
|
|
|
(182
|
)
|
|
|
(9,400
|
)
|
Gain on sale of assets
|
|
|
(354
|
)
|
|
|
(1,559
|
)
|
Stock-based compensation
|
|
|
|
|
|
|
1,671
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(733
|
)
|
|
|
(1,498
|
)
|
Prepaids and other
|
|
|
582
|
|
|
|
270
|
|
Other assets
|
|
|
(108
|
)
|
|
|
(104
|
)
|
Inventory
|
|
|
(324
|
)
|
|
|
(27
|
)
|
Accounts payable
|
|
|
2,114
|
|
|
|
(1,987
|
)
|
Accrued liabilities
|
|
|
(49
|
)
|
|
|
167
|
|
Revenue payable
|
|
|
112
|
|
|
|
42
|
|
Advance billings and other
|
|
|
1,755
|
|
|
|
(120
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
10,269
|
|
|
|
14,554
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities:
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties
|
|
|
(10,716
|
)
|
|
|
(21,370
|
)
|
Additions to other property and equipment
|
|
|
(640
|
)
|
|
|
(679
|
)
|
Proceeds from sale of other property and equipment
|
|
|
607
|
|
|
|
1,219
|
|
Proceeds from sale of property and equipment to affiliate
|
|
|
|
|
|
|
4,000
|
|
Proceeds from sale of subsidiary, net of cash sold
|
|
|
|
|
|
|
2,095
|
|
Acquisitions of oil and natural gas properties
|
|
|
(5,173
|
)
|
|
|
(10,146
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(15,922
|
)
|
|
|
(24,881
|
)
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities:
|
|
|
|
|
|
|
|
|
Proceeds from credit facilities
|
|
|
7,100
|
|
|
|
17,850
|
|
Payments on credit facilities
|
|
|
(1,900
|
)
|
|
|
(7,900
|
)
|
Borrowings on note payable
|
|
|
|
|
|
|
412
|
|
Payments on note payable
|
|
|
(63
|
)
|
|
|
(84
|
)
|
Issue/repurchase member units, net
|
|
|
(4
|
)
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
5,133
|
|
|
|
10,291
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
|
(520
|
)
|
|
|
(36
|
)
|
Beginning Cash and Cash Equivalents
|
|
|
763
|
|
|
|
222
|
|
|
|
|
|
|
|
|
|
|
Ending Cash and Cash Equivalents
|
|
$
|
243
|
|
|
$
|
186
|
|
|
|
|
|
|
|
|
|
|
Supplemental Cash Flow Information:
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
40
|
|
|
$
|
340
|
|
|
|
|
|
|
|
|
|
|
Non-Cash Investing and Financing Activities:
|
|
|
|
|
|
|
|
|
Accrued capital expendituresoil and gas properties
|
|
$
|
1,167
|
|
|
$
|
1,421
|
|
|
|
|
|
|
|
|
|
|
Accounts and notes receivable from officers, directors and
employees
|
|
$
|
|
|
|
$
|
106
|
|
|
|
|
|
|
|
|
|
|
Deferred gain on sale of property and equipment to affiliate
|
|
$
|
|
|
|
$
|
3,224
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these combined
financial statements.
F-15
|
|
1.
|
Organization
and Nature of Operations
|
Mid-Con Energy, I LLC and Mid-Con Energy II, LLC (collectively,
with subsidiaries of Mid-Con Energy II, LLC, the
predecessor) are Delaware limited liability
companies. The predecessors principal business is the
acquisition, development and production of existing oil and
natural gas properties in the Mid-Continent region of the United
States. The predecessor uses secondary oil recovery techniques,
such as waterflooding, to increase production from mature oil
fields. Mid-Con Energy II, LLCs wholly owned subsidiaries
are RDT Properties, Inc. (RDT) and ME3 Oilfield
Service, LLC (ME3). RDT is the sole operator of
mineral properties owned by the predecessor, and ME3 provides
oil field construction and maintenance services, as well as oil
and water transportation services, to the predecessor and to
third parties.
On June 30, 2011, Mid-Con Energy III, LLC, an affiliate of
our predecessor, purchased RDT, ME3 and certain oil and gas
properties from the predecessor. Because this was a transaction
of companies under common control, the excess of the cash that
our predecessor received over the book value of the net assets
transferred to Mid-Con Energy III, LLC was recorded as a capital
contribution and no gain was recognized. The accompanying
balance sheet as of September 30, 2011, reflects the sale
of these subsidiaries and properties. The results of operations
for these subsidiaries and properties are included in the
accompanying statements of operations and cash flows up to the
date of the sale.
In connection with the closing of the initial public offering of
common units of Mid-Con Energy Partners, LP (the
Partnership), the predecessor will merge with and
into a wholly owned subsidiary of the Partnership in exchange
for a combination of common units issued and cash consideration
paid to the predecessors owners.
|
|
2.
|
Summary
of Significant Accounting Policies
|
Basis of presentation and principles of combination
The accompanying combined financial statements were derived from
the historical accounting records of the predecessor and reflect
the historical financial position, results of operations and
cash flow for the periods described herein. All intercompany
transactions and account balances have been eliminated. The
accompanying combined financial statements have been prepared in
accordance with accounting principles generally accepted in the
United States of America (GAAP). The predecessor
operates oil and natural gas properties as one business segment:
the exploration, development and production of oil and natural
gas. The predecessors management evaluates performance
based on one business segment as there are not different
economic environments within the operation of the oil and
natural gas properties.
The accompanying combined financial statements of the
predecessor have not been audited, except that the combined
balance sheet at December 31, 2010 is derived from the
predecessors audited combined financial statements. In the
opinion of management, the accompanying combined financial
statements reflect all adjustments necessary to present fairly
the predecessors financial position at September 30,
2011, and its results of operations and cash flow for the nine
months ended September 30, 2010 and 2011. All such
adjustments are of a normal recurring nature. The results for
interim periods are not necessarily indicative of annual results.
Certain disclosures have been condensed or omitted from these
combined financial statements. Accordingly, these combined
financial statements should be read with the audited combined
financial statements and notes included elsewhere in this
prospectus.
F-16
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
September 30, 2011
(Unaudited) (continued)
Use of estimates
Preparation of financial statements in conformity with GAAP
requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities, the
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues
and expenses during the reporting periods. Actual results could
differ from these estimates. Depletion of oil and gas properties
is determined using estimates of proved oil and gas reserves.
There are numerous uncertainties inherent in the estimation of
quantities of proved reserves and in the projection of future
rates of production and the timing of development expenditures.
Similarly, evaluations for impairment of proved and unproved oil
and gas properties are subject to numerous uncertainties
including, among others, estimates of future recoverable
reserves and commodity price outlooks. Other significant
estimates include, but are not limited to, asset retirement
obligations, fair value of business combinations and fair value
of derivative financial instruments.
Accounts receivable
The predecessor sells oil and natural gas to various customers
and participates with other parties in the drilling, completion
and operation of oil and gas wells. The predecessors joint
interest and oil and gas sales receivables related to these
operations are generally unsecured. Accounts receivable for
joint interest billings are recorded as amounts billed to
customers less an allowance for doubtful accounts. Amounts are
considered past due after 30 days. The predecessor
determines joint interest operations accounts receivable
allowances based on managements assessment of the
creditworthiness of the joint interest owners and the
predecessors ability to realize the receivables through
netting of anticipated future production revenues. The
predecessor had no allowance for doubtful accounts at
December 31, 2010 and September 30, 2011 and there
were no provisions for bad debts or write-offs of accounts
receivable for the nine months ended September 30, 2010 or
2011.
Revenue recognition
The predecessor uses the sales method of accounting for crude
oil and natural gas revenues. Under this method, revenues are
recognized based on the predecessors share of actual
proceeds from oil and gas sold to purchasers. Natural gas
revenues would not have been significantly altered for the
period presented had the entitlements method of recognizing
natural gas revenues been utilized. If reserves are not
sufficient to recover natural gas overtake positions, a
liability is recorded. The predecessor had no significant
natural gas imbalances at December 31, 2010 or
September 30, 2011.
Oil and natural gas properties
The predecessor utilizes the successful efforts method of
accounting for its oil and gas properties. Under this method all
costs associated with productive wells and nonproductive
development wells are capitalized, while nonproductive
exploration costs are expensed. Capitalized costs relating to
proved properties are depleted using the
units-of-production
method based on proved reserves on a field basis. The
depreciation of capitalized production equipment is based on the
units-of-production
method using proved developed reserves on a field basis. The
predecessor had no exploratory wells in progress and no
capitalized exploratory well costs pending determination of
reserves at December 31, 2010 or September 30, 2011.
Capitalized costs of individual properties abandoned or retired
are charged to accumulated depletion, depreciation and
amortization. Proceeds from sales of individual properties are
F-17
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
September 30, 2011
(Unaudited) (continued)
credited to property costs. No gain or loss is recognized until
the entire amortization base (field) is sold or abandoned.
Costs of significant nonproducing properties and wells in the
process of being drilled are excluded from depletion until such
time as the proved reserves are established or impairment is
determined. Costs of significant development projects are
excluded from depreciation until the related project is
completed. The predecessor capitalizes interest, if debt is
outstanding, on expenditures for significant development
projects until such projects are ready for their intended use.
At December 31, 2010 and September 30, 2011, the
predecessor had no capitalized interest.
The predecessor reviews its long-lived assets to be held and
used, including proved oil and gas properties accounted for
under the successful efforts method of accounting, whenever
events or circumstances indicate that the carrying value of
those assets may not be recoverable. The impairment provision is
based on the excess of carrying value over fair value. Fair
value is defined as the present value of the estimated future
net revenues from production of total proved and risk-adjusted
probable and possible oil and gas reserves over the economic
life of the reserves based on the predecessors
expectations of future oil and gas prices and costs. The
predecessor reviews its oil and gas properties by amortization
base (field) or by individual well for those wells not
constituting part of an amortization base. The predecessor did
not recognize any impairments of proved oil and gas properties
for the nine months ended September 30, 2010 or 2011.
Unproved oil and gas properties are each periodically assessed
for impairment by comparing their costs to their estimated
values on a
project-by-project
basis. The estimated value is affected by the results of
exploration activities, future drilling plans, commodity price
outlooks, planned future sales or expiration of all or a portion
of leases on such projects. If the quantity of potential
reserves determined by such evaluations is not sufficient to
fully recover the cost invested in each project, the predecessor
recognizes an impairment loss at that time. The predecessor
recognized approximately $1.1 million and $0.8 million
as abandonment expense for the nine months ended
September 30, 2010 and 2011, related to its unproved oil
and gas properties.
Other property and equipment
Other property and equipment is stated at historical cost and is
comprised of software, vehicles, office equipment, and field
service equipment. Costs incurred for normal repairs and
maintenance are charged to expense as incurred, unless they
extend the useful life of the asset. Depreciation is calculated
using the straight-line method based on useful lives of the
assets ranging from three to fifteen years and is included in
the accumulated depreciation, depletion and amortization totals.
Depreciation expense related to other property and equipment for
the nine months ended September 30, 2010 and 2011 totaled
approximately $0.7 million and $0.3 million,
respectively. All of the other property and equipment was sold
to Mid-Con Energy III, LLC at June 30, 2011.
Derivatives and hedging
All derivative instruments are recorded on the balance sheet as
either assets or liabilities at fair value. Derivative
instruments that do not meet specific hedge accounting criteria
must be adjusted to fair value through net income. Effective
changes in the fair value of derivative instruments that are
accounted for as cash flow hedges are recognized in other
accumulated comprehensive income in members equity until
such time as the hedged items are recognized in net income.
Ineffective portions of a derivative instruments change in
fair value are immediately recognized in net income.
F-18
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
September 30, 2011
(Unaudited) (continued)
None of the predecessors derivatives held during 2010 and
2011 were designated as hedges for financial statement purposes;
therefore, the adjustments to fair value are included in net
income. Realized and unrealized gains and losses on derivatives
are included in cash flow from operating activities.
Inventory
Inventory consists primarily of oilfield equipment and is valued
at the lower of cost or market. No excess or obsolete reserve
has been recorded at December 31, 2010. All of the
predecessors inventory was sold to Mid-Con Energy III, LLC
at June 30, 2011.
Other revenue and expense, net
The predecessor receives fees for the operation of jointly-owned
oil and gas properties and records such reimbursements as
reductions of other revenue and expense, net. Such fees totaled
approximately $2.4 million and $2.1 million for the
nine months ended September 30, 2010 and 2011, respectively.
Income taxes
The entities comprising the predecessor are two limited
liability companies, and, as such, their earnings or losses for
federal and state income tax purposes are generally included in
the tax returns of the individual unitholders of the
predecessor. Earnings or losses for financial statement purposes
may differ significantly from those reported to the individual
unitholders for income tax purposes as a result of differences
between the tax basis and financial reporting basis of assets
and liabilities and the taxable income allocation requirements
under the limited liability agreements of the predecessor.
The predecessor evaluates uncertain tax positions for
recognition and measurement in the financial statements. To
recognize a tax position, the predecessor determines whether it
is more likely than not that the tax positions will be sustained
upon examination, including resolution of any related appeals or
litigation, based on the technical merits of the position. A tax
position that meets the more likely than not threshold is
measured to determine the amount of benefit to be recognized in
the financial statements. The amount of tax benefit recognized
with respect to any tax position is measured as the largest
amount of benefit that is greater than 50% likely of being
realized upon settlement. The predecessor had no uncertain tax
positions that required recognition in the financial statements
at December 31, 2010 or September 30, 2011. Any
interest or penalties would be recognized as a component of
income tax expense.
New accounting pronouncements
In December 2010, the FASB issued an accounting standards update
regarding disclosure of supplementary pro forma information for
business combinations. This update was issued in order to
address diversity in practice about the interpretation of the
pro forma revenue and earnings disclosure requirements. The
update requires a public entity to disclose pro forma
information for business combinations that occurred in the
current reporting period. The disclosures include pro forma
revenue and earnings of the combined entity for the current
reporting period as though the acquisition date for all business
combinations that occurred during the year had been as of the
beginning of the annual reporting period. If comparative
financial statements are presented, the pro forma revenue and
earnings of the combined entity for the comparable prior
reporting period should be reported as though the acquisition
date for all business combinations that occurred during the
current year had been as of the beginning of the comparable
prior
F-19
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
September 30, 2011
(Unaudited) (continued)
annual reporting period. In practice, some preparers have
presented the pro forma information in their comparative
financial statements as if the business combination that
occurred in the current reporting period had occurred as of the
beginning of each of the current and prior annual reporting
periods. Other preparers have disclosed the pro forma
information as if the business combination occurred at the
beginning of the prior annual reporting period only, and carried
forward the related adjustments, if applicable, through the
current reporting period. The predecessor plans to adopt the
updated rules in relation to all future business combinations.
In January 2010, the FASB issued an accounting standards update
for improving disclosure about fair value measurements. This
amendment provides guidance that clarifies and requires new
disclosures about fair value measurements. The clarifications
and requirement to disclose the amounts and reasons for
significant transfers between Level 1 and Level 2, as
well as significant transfers in and out of Level 3 of the
fair value hierarchy, were adopted by the predecessor in 2010.
Note 4Fair Value Measurements reflects the amended
disclosure requirements. The new guidance also requires that
purchases, sales, issuances, and settlements be presented on a
gross basis in the Level 3 reconciliation and that
requirement is effective for fiscal years beginning after
December 15, 2010 and for interim periods within those
years, with early adoption permitted. Since this new guidance
only amends the disclosures requirements, it did not impact the
predecessors statement of financial position, statement of
operations, or cash flow statement.
On June 30, 2011, the predecessor acquired two waterflood
units, the War Party I and II Units, for a purchase price
of $7.2 million. The predecessor is currently engaged in a
workover program to return a number of inactive wells in these
units to production, optimize producing well rates and increase
injection. The predecessor expects that this program will be
substantially completed by October 31, 2011.
|
|
4.
|
Fair
Value Measurement
|
The carrying amounts reported in the balance sheet for cash,
accounts receivable, accounts payable and derivative financial
instruments approximate their fair values. The recorded values
of the predecessors credit facilities approximate fair
value as the interest rate is variable and the terms of the
credit facilities are similar to what the predecessor believes
comparable companies would receive.
The predecessor accounts for its oil and gas commodity
derivatives at fair value. The fair value of derivative
financial instruments is determined utilizing the New York
Mercantile Exchange (NYMEX) closing prices for the
contract period.
The predecessor has categorized its financial instruments, based
on the priority of inputs to the valuation technique, into a
three-level fair value hierarchy. The fair value hierarchy gives
the highest priority to quoted prices in active markets for
identical assets or liabilities (Level 1) and the
lowest priority to unobservable inputs (Level 3).
F-20
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
September 30, 2011
(Unaudited) (continued)
Financial assets and liabilities recorded in the balance sheet
are categorized based on the inputs to the valuation techniques
as follows:
Level 1Financial assets and liabilities for
which values are based on unadjusted quoted prices for identical
assets or liabilities in an active market that management has
the ability to access.
Level 2Financial assets and liabilities for
which values are based on quoted prices in markets that are not
active or model inputs that are observable either directly or
indirectly for substantially the full term of the asset or
liability.
Level 3Financial assets and liabilities for
which values are based on prices or valuation techniques that
require inputs that are both unobservable and significant to the
overall fair value measurement. These inputs reflect
managements own assumptions about the assumptions a market
participant would use in pricing the asset or liability.
When the inputs used to measure fair value fall within different
levels of the hierarchy in a liquid environment, the level
within which the fair value measurement is categorized is based
on the lowest level input that is significant to the fair value
measurement in its entirety. Changes in the observability of
valuation inputs may result in a reclassification for certain
financial assets or liabilities. The following presents the
predecessors fair value hierarchy for assets and
liabilities measured at fair value on September 30, 2011
and December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
|
(in thousands)
|
|
|
September 30, 2011
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets and Liabilities Measured as Fair Value on a Recurring
Basis
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instrumentsasset
|
|
$
|
|
|
|
$
|
8,496
|
|
|
$
|
|
|
Assets and Liabilities Measured at Fair Value on a Nonrecurring
Basis
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
$
|
|
|
|
$
|
|
|
|
$
|
503
|
|
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets and Liabilities Measured at Fair Value on a Recurring
Basis
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instrumentsliability
|
|
$
|
|
|
|
$
|
904
|
|
|
$
|
|
|
Assets and Liabilities Measured at Fair Value on a Nonrecurring
Basis
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
$
|
|
|
|
$
|
|
|
|
$
|
319
|
|
Impairment of proved oil and gas properties
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,886
|
|
Assets and Liabilities Measured at Fair Value on a
Nonrecurring Basis
Certain assets and liabilities are reported at fair value on a
nonrecurring basis in the predecessors combined balance
sheet.
The predecessor estimates the fair value of the asset retirement
obligations based on discounted cash flow projections using
numerous estimates, assumptions and judgments regarding such
factors as the existence of a legal obligation for an ARO;
amounts and timing of
F-21
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
September 30, 2011
(Unaudited) (continued)
settlements; the credit-adjusted risk-free rate to be used; and
inflation rates. See Note 5 for a summary of changes in
AROs.
The predecessor reviews its long-lived assets to be held and
used, including proved oil and natural gas properties, whenever
events or circumstances indicate that the carrying value of
those assets may not be recoverable. An impairment loss is
indicated if the sum of the expected undiscounted future net
cash flows is less than the carrying amount of the assets. In
this circumstance, the predecessor recognizes an impairment loss
for the amount by which the carrying amount of the asset exceeds
the estimated fair value of the asset and reduces the carrying
amount of the asset. Estimating future cash flows involves the
use of judgments, including estimation of the proved oil and
natural gas reserve quantities, timing of development and
production, expected future commodity prices, capital
expenditures and production costs.
|
|
5.
|
Asset
Retirement Obligations
|
Asset retirement obligations are recorded as a liability at
their estimated present value at the various assets
inception, with the offsetting charge to oil and gas properties.
Periodic accretion of the discounted estimated liability is
recorded in the statement of operations. The discounted
capitalized cost is amortized to expense through the
depreciation calculation over the life of the assets based on
proved developed reserves.
The predecessors asset retirement obligations primarily
represent the estimated present value of the amount the
predecessor will incur to plug, abandon and remediate its
producing properties at the end of their production lives, in
accordance with applicable state laws. The predecessor has
determined its asset retirement obligations by calculating the
present value of estimated cash flow related to the liability.
The following is a reconciliation of the asset retirement
obligation at September 30, 2010 and 2011 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2011
|
|
|
|
(in thousands)
|
|
|
Asset retirement obligations at December 31
|
|
$
|
1,736
|
|
|
$
|
2,148
|
|
Liabilities incurred for new wells
|
|
|
78
|
|
|
|
311
|
|
Disposition of wells
|
|
|
|
|
|
|
(1,024
|
)
|
Revision in estimates
|
|
|
60
|
|
|
|
192
|
|
Accretion expense
|
|
|
96
|
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations at September 30
|
|
$
|
1,970
|
|
|
$
|
1,682
|
|
|
|
|
|
|
|
|
|
|
|
|
6.
|
Derivative
Financial Instruments
|
The predecessor is exposed to commodity price risk and considers
it prudent to periodically reduce the predecessors
exposure to cash flow variability resulting from commodity price
change fluctuations. Accordingly, the predecessor enters into
derivative instruments to manage its exposure to commodity price
fluctuations and fluctuations in location differences between
published index prices and the NYMEX futures prices.
At December 31, 2010 and September 30, 2011 the
predecessors open positions consisted of crude oil price
collar contracts and crude oil price swap contracts. Under
commodity swap agreements, the predecessor exchanges a stream of
payments over time according to specified terms with another
counterparty. In a typical commodity swap agreement, the
predecessor agrees
F-22
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
September 30, 2011
(Unaudited) (continued)
to pay an adjustable or floating price tied to an agreed upon
index for the oil commodity and in return receives a fixed price
based on notional quantities. A collar is a combination of a put
purchased by a party and a call option sold by the same party.
In a typical collar transaction, if the floating price based on
a market index is below the floor price, the predecessor
receives from the counterparty an amount equal to this
difference multiplied by the specified volume, effectively a put
option. If the floating price exceeds the floor price and is
less than the ceiling price, no payment is required by either
party. If the floating price exceeds the ceiling price, the
predecessor must pay the counterparty an amount equal to the
difference multiplied by the specific quantity, effectively a
call option.
The predecessor elected not to designate any positions as cash
flow hedges for accounting purposes and, accordingly, recorded
the net change in the
mark-to-market
valuation of these derivative contracts in the statement of
operations. Pursuant to the accounting standard that permits
netting of assets and liabilities where the right of offset
exists, the predecessor presents the fair value of derivative
financial instruments on a net basis.
At September 30, 2011 the predecessor had the following
commodity derivative open positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement
|
|
|
|
|
|
Instrument
|
|
Total
|
|
NYMEX
|
|
|
Months Outstanding
|
|
Price
|
|
Floor
|
|
Ceiling
|
|
Type
|
|
Bbls
|
|
Index
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Oct-Dec 2011
|
|
$
|
83.25
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
9,000
|
|
|
WTI
|
|
$
|
25
|
|
Oct-Dec 2011
|
|
$
|
86.75
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
9,000
|
|
|
WTI
|
|
|
63
|
|
Oct-Dec 2011
|
|
$
|
85.30
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
6,000
|
|
|
WTI
|
|
|
31
|
|
Oct-Dec 2011
|
|
$
|
89.55
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
9,000
|
|
|
WTI
|
|
|
93
|
|
Oct-Dec 2011
|
|
$
|
100.25
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
18,000
|
|
|
WTI
|
|
|
464
|
|
Jan-Dec 2012
|
|
$
|
104.28
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
72,000
|
|
|
WTI
|
|
|
1,588
|
|
Jan-Dec 2012
|
|
$
|
100.00
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
96,000
|
|
|
WTI
|
|
|
1,727
|
|
Jan-Dec 2012
|
|
|
|
|
|
$
|
100.00
|
|
|
$
|
117.00
|
|
|
Collar
|
|
|
72,000
|
|
|
WTI
|
|
|
1,537
|
|
Jan-Dec 2013
|
|
$
|
105.80
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
72,000
|
|
|
WTI
|
|
|
1,610
|
|
Jan-Dec 2013
|
|
|
|
|
|
$
|
100.00
|
|
|
$
|
111.00
|
|
|
Collar
|
|
|
72,000
|
|
|
WTI
|
|
|
1,358
|
|
At September 30, 2011, the predecessor recorded the
estimated fair value of the derivative contracts as
$4.5 million as a long-term asset and $4.0 million as
a short term asset.
The predecessors derivative contracts are secured by an
agreement with one of the predecessors purchasers;
whereby, the derivative counterparty can seek payment directly
from the predecessors purchaser on the predecessors
oil production under the contract, should the predecessor be in
default of the contract.
A certain officer and member of the predecessor is entitled to,
or responsible for, as applicable, 10% of the receivable or
payable, respectively, on the monthly settlement from or to, as
applicable, the derivative counterparty.
Membership
Units
In June 2011, certain employees of the predecessor purchased a
total of 5,770 Class C Units of Mid-Con Energy I, LLC.
The employees paid a purchase price of $10 per unit, consisting
of 25% cash and a full recourse note for the remaining 75%. The
aggregate amount of the notes was
F-23
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
September 30, 2011
(Unaudited) (continued)
$43,000. In September 2011, certain employees of the predecessor
purchased a total of 8,400 Class B Units of Mid-Con Energy
I, LLC. The employees paid a purchase price of $10 per unit,
consisting of 25% cash and a full recourse note for the
remaining 75%. The aggregate amount of the notes was $63,000.
The units are subject to a restricted period of four years,
beginning on the date the individual began serving as an
employee of the predecessor. During the restricted period, the
employee may not sell, transfer, pledge, exchange or otherwise
dispose of the units. The units vest ratably over the restricted
period. All awards immediately vest upon a change of control of
the predecessor. If the individuals employment or service
to the predecessor is terminated prior to vesting, the
individual has no further rights to the unvested units and the
predecessor has the right to repurchase any or all of the vested
and unvested units.
In June 2011, certain employees of the predecessor were granted
a total of 13,160 non-vested Class C Units of Mid-Con
Energy II, LLC. In September 2011, certain employees
of the predecessor were granted a total of 16,350 non-vested
Class B Units of Mid-Con Energy II, LLC. These unit awards are
subject to a restricted period of four years, beginning on the
date the individual began serving as an employee of the
predecessor. During the restricted period, the employees may not
sell, transfer, pledge, exchange or otherwise dispose of the
units. The units vest ratably over the restricted period. All
awards immediately vest upon a change of control of the
predecessor. If the employees employment or service to the
predecessor is terminated prior to vesting, that person has no
further rights to the Class C units.
The following is an analysis of non-vested Class C Units
for the nine month ended September 30, 2011:
|
|
|
|
|
Beginning non-vested Class C Units outstanding
|
|
|
35,254
|
|
Awards granted
|
|
|
13,160
|
|
Awards cancelled
|
|
|
|
|
Awards vested
|
|
|
|
|
|
|
|
|
|
Ending non-vested Class C Units outstanding
|
|
|
49,414
|
|
|
|
|
|
|
|
|
|
|
|
Beginning non-vested Class B Units outstanding
|
|
|
745,674
|
|
Awards granted
|
|
|
16,350
|
|
Awards cancelled
|
|
|
|
|
Awards vested
|
|
|
|
|
|
|
|
|
|
Ending non-vested Class B Units outstanding
|
|
|
762,024
|
|
|
|
|
|
|
Notes
Receivable from Officers, Directors and Employees
At September 30, 2011, the predecessor had notes receivable
from various officers, directors and employees totaling
$2.1 million, including accrued interest. The maturity date
of the notes is defined as the earlier of the date upon which
the predecessor or any successor to the predecessor registers
any class of its stock under Section 12 of the Securities
Exchange Act of 1934 (the Exchange Act); is required
to file periodic reports under Section 15(d) of the
Exchange Act; the date a registration statement filed under the
Securities Act of 1933 is declared effective; or April 2,
2013 for Mid-Con Energy I, LLC units and June 15, 2016
for Mid-Con Energy II, LLC units. The stated annual interest
rate on all notes is 6%. Interest is compounded annually. All
accrued and unpaid interest on the notes is due and payable at
maturity. All such notes receivable were originally issued in
conjunction with purchases of the predecessors membership
F-24
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
September 30, 2011
(Unaudited) (continued)
units by the predecessors officers, directors and
employees. Performance of the predecessors officers,
directors and employees obligations under these
notes is secured by security interests granted by each of them
to the predecessor in all of the membership units purchased.
Additionally, the predecessor has full recourse against the
assets of the predecessors officers, directors and
employees for collection of amounts due upon the occurrence of a
default that is not remedied.
Debt at December 31, 2010 and September 30, 2011
consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2010
|
|
|
2011
|
|
|
|
(in thousands)
|
|
Revolving credit facilities
|
|
$
|
5,260
|
|
|
$
|
15,210
|
|
Term loans
|
|
|
253
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,513
|
|
|
|
15,210
|
|
Less: Current portion
|
|
|
5,354
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
159
|
|
|
$
|
15,210
|
|
|
|
|
|
|
|
|
|
|
The predecessor has a borrowing capacity of $22.0 million
under two revolving credit facilities with a financial
institution. The total borrowing base is also
$22.0 million, re-determined semi-annually based on the
predecessors oil and natural gas reserves. Interest is
payable monthly and charged at the financial institutions
prime rate (4% at September 30, 2011). The
predecessors oil properties located in southern Oklahoma
are pledged as security under the agreements. The predecessor
had approximately $5.3 million and $15.2 million
borrowed against their credit facilities at December 31,
2010 and September 30, 2011, respectively. Any amounts
outstanding are due at maturity in December 2013. There
were no outstanding letters of credit as of December 31,
2010 or September 30, 2011.
During 2009, the predecessor entered into a variable rate term
loan for approximately $350,000. The loan bears interest at New
York Prime Rate (3.25% at June 30, 2011) and matures on
October 9, 2013. During 2011, the predecessor entered into
an additional variable rate term loan for approximately
$400,000. The loan bears interest at Wall Street Journal Prime
rate plus 1% (5.5% at June 30, 2011) and matures on
February 9, 2015. These term loans were assumed by Mid-Con
Energy III, LLC on June 30, 2011 in connection with the
transfer of ME3 from the predecessor to
Mid-Con
Energy III, LLC.
During September 2011, our auditors identified mathematical
errors that existed in the calculation of depreciation,
depletion and amortization and impairment of proved oil and gas
properties for all periods prior to 2011. Our auditors also
determined that a clerical error resulted in expensing of
certain geological and geophysical costs by Mid-Con
Energy I, LLC in the six months ended December 31,
2009, that had previously been expensed by the predecessor,
Mid-Con Energy Corporation, during the fiscal year ended
June 30, 2009.
F-25
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
September 30, 2011
(Unaudited) (continued)
Management has restated the combined financial statements to
correct these errors. The following tables reflect the impact of
the restatement on the predecessors combined balance
sheets at December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
|
As Previously
|
|
|
|
|
|
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
As Restated
|
|
|
|
(in thousands)
|
|
|
Combined Balance Sheet:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
57,873
|
|
|
$
|
(509
|
)
|
|
$
|
57,364
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(8,795
|
)
|
|
|
317
|
|
|
|
(8,478
|
)
|
Total property and equipment, net
|
|
|
51,848
|
|
|
|
(192
|
)
|
|
|
51,656
|
|
Total assets
|
|
|
57,059
|
|
|
|
(192
|
)
|
|
|
56,867
|
|
Contributed capital
|
|
|
52,933
|
|
|
|
(10
|
)
|
|
|
52,923
|
|
Accumulated deficit
|
|
|
(7,836
|
)
|
|
|
(182
|
)
|
|
|
(8,018
|
)
|
Total members equity
|
|
|
43,264
|
|
|
|
(192
|
)
|
|
|
43,072
|
|
Total liabilities and members equity
|
|
|
57,059
|
|
|
|
(192
|
)
|
|
|
56,867
|
|
F-26
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors
Mid-Con Energy GP, LLC
We have audited the accompanying combined balance sheets of
Mid-Con Energy I, LLC (a Delaware limited liability
company) and Mid-Con Energy II, LLC (a Delaware limited
liability company) and subsidiaries as of December 31, 2009
and 2010, and the related combined statements of operations,
members equity and cash flow for the period from inception
(July 1, 2009) to December 31, 2009 and for the
year ended December 31, 2010. These financial statements
are the responsibility of the Companies management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. The Companies are not required to
have, nor were we engaged to perform audits of their internal
control over financial reporting. Our audits included
consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Companies internal control
over financial reporting. Accordingly, we express no such
opinion. An audit also includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the combined financial statements referred to
above present fairly, in all material respects, the combined
financial position of Mid-Con Energy I, LLC and Mid-Con
Energy II, LLC and subsidiaries as of December 31, 2009 and
2010, and the results of their operations and their cash flow
for the period from inception (July 1, 2009) to
December 31, 2009 and for the year ended December 31,
2010, in conformity with accounting principles generally
accepted in the United States of America.
As discussed in Note 12, the accompanying financial
statements have been restated to correct misstatements.
/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
August 12, 2011, except for Note 12, as to which the
date is October 5, 2011
F-27
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
|
(as restated,
|
|
|
|
see Note 12)
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
763
|
|
|
$
|
222
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
|
1,321
|
|
|
|
2,134
|
|
Joint operations and other
|
|
|
913
|
|
|
|
1,548
|
|
Certificate of depositgovernment bond
|
|
|
150
|
|
|
|
150
|
|
Inventory
|
|
|
259
|
|
|
|
771
|
|
Prepaids and other
|
|
|
751
|
|
|
|
147
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
4,157
|
|
|
|
4,972
|
|
|
|
|
|
|
|
|
|
|
Property and Equipment:
|
|
|
|
|
|
|
|
|
Oil and gas properties, successful efforts method:
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
37,069
|
|
|
|
57,364
|
|
Unproved properties
|
|
|
397
|
|
|
|
446
|
|
Other property and equipment
|
|
|
1,482
|
|
|
|
2,324
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(2,726
|
)
|
|
|
(8,478
|
)
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
36,222
|
|
|
|
51,656
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
117
|
|
|
|
239
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
40,496
|
|
|
$
|
56,867
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS EQUITY
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
404
|
|
|
$
|
2,785
|
|
Accrued liabilities
|
|
|
392
|
|
|
|
399
|
|
Revenue payable
|
|
|
136
|
|
|
|
182
|
|
Advance billings and other
|
|
|
489
|
|
|
|
1,864
|
|
Current portion of long-term debt
|
|
|
94
|
|
|
|
5,354
|
|
Derivative financial instruments
|
|
|
222
|
|
|
|
904
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
1,737
|
|
|
|
11,488
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt
|
|
|
243
|
|
|
|
159
|
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligations
|
|
|
1,737
|
|
|
|
2,148
|
|
|
|
|
|
|
|
|
|
|
Members Equity:
|
|
|
|
|
|
|
|
|
Contributed capital
|
|
|
47,073
|
|
|
|
52,923
|
|
Notes receivable from officers, directors and employees
|
|
|
(1,198
|
)
|
|
|
(1,833
|
)
|
Accumulated deficit
|
|
|
(9,096
|
)
|
|
|
(8,018
|
)
|
|
|
|
|
|
|
|
|
|
Total members equity
|
|
|
36,779
|
|
|
|
43,072
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and members equity
|
|
$
|
40,496
|
|
|
$
|
56,867
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these combined
balance sheets.
F-28
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
Inception
|
|
|
Year
|
|
|
|
(July 1, 2009) to
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
|
(as restated, see Note 12)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
5,729
|
|
|
$
|
16,853
|
|
Natural gas sales
|
|
|
743
|
|
|
|
1,418
|
|
Realized loss on derivatives, net
|
|
|
(350
|
)
|
|
|
(90
|
)
|
Unrealized loss on derivatives, net
|
|
|
(147
|
)
|
|
|
(707
|
)
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
5,975
|
|
|
|
17,474
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
2,431
|
|
|
|
6,237
|
|
Oil and gas production taxes
|
|
|
269
|
|
|
|
822
|
|
Dry holes and abandonments of unproved properties
|
|
|
|
|
|
|
1,418
|
|
Geological and geophysical
|
|
|
|
|
|
|
394
|
|
Depreciation, depletion and amortization
|
|
|
2,552
|
|
|
|
5,851
|
|
Accretion of discount on asset retirement obligations
|
|
|
58
|
|
|
|
127
|
|
General and administrative
|
|
|
704
|
|
|
|
982
|
|
Impairment of proved oil and gas properties
|
|
|
9,208
|
|
|
|
1,886
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
15,222
|
|
|
|
17,717
|
|
|
|
|
|
|
|
|
|
|
Loss from operations
|
|
|
(9,247
|
)
|
|
|
(243
|
)
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest income and other
|
|
|
35
|
|
|
|
218
|
|
Interest expense
|
|
|
(2
|
)
|
|
|
(98
|
)
|
Gain on sale of assets
|
|
|
|
|
|
|
354
|
|
Other revenue and expense, net
|
|
|
118
|
|
|
|
847
|
|
|
|
|
|
|
|
|
|
|
Total other income (expenses)
|
|
|
151
|
|
|
|
1,321
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(9,096
|
)
|
|
$
|
1,078
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these combined
financial statements.
F-29
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivable
|
|
|
|
|
|
|
|
|
|
|
|
|
from Officers,
|
|
|
|
|
|
Total
|
|
|
|
Contributed
|
|
|
Directors and
|
|
|
Accumulated
|
|
|
Members
|
|
|
|
Capital
|
|
|
Employees
|
|
|
Deficit
|
|
|
Equity
|
|
|
|
(in thousands)
|
|
|
|
(as restated, see Note 12)
|
|
|
Beginning LLC Balances at July 1, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Con Energy I, LLC
|
|
$
|
41,992
|
|
|
$
|
(552
|
)
|
|
$
|
|
|
|
$
|
41,440
|
|
Mid-Con Energy II, LLC
|
|
|
6,580
|
|
|
|
(646
|
)
|
|
|
|
|
|
|
5,934
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48,572
|
|
|
|
(1,198
|
)
|
|
|
|
|
|
|
47,374
|
|
Distributions
|
|
|
(1,499
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,499
|
)
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
(9,096
|
)
|
|
|
(9,096
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009:
|
|
|
47,073
|
|
|
|
(1,198
|
)
|
|
|
(9,096
|
)
|
|
|
36,779
|
|
Contributions
|
|
|
10,646
|
|
|
|
(646
|
)
|
|
|
|
|
|
|
10,000
|
|
Distributions
|
|
|
(4,785
|
)
|
|
|
|
|
|
|
|
|
|
|
(4,785
|
)
|
Repurchase of member units
|
|
|
(15
|
)
|
|
|
11
|
|
|
|
|
|
|
|
(4
|
)
|
Other
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
1,078
|
|
|
|
1,078
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010:
|
|
$
|
52,923
|
|
|
$
|
(1,833
|
)
|
|
$
|
(8,018
|
)
|
|
$
|
43,072
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these combined
financial statements.
F-30
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
Inception
|
|
|
Year
|
|
|
|
(July 1, 2009) to
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
|
(as restated, see Note 12)
|
|
|
Cash Flows From Operating Activities:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(9,096
|
)
|
|
$
|
1,078
|
|
Adjustments to reconcile net income (loss) to net cash provided
by (used in) operating activities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
2,552
|
|
|
|
5,851
|
|
Accretion of discount on asset retirement obligations
|
|
|
58
|
|
|
|
127
|
|
Dry holes and abandonments of unproved properties
|
|
|
|
|
|
|
1,418
|
|
Impairment of proved oil and gas properties
|
|
|
9,208
|
|
|
|
1,886
|
|
Unrealized loss on derivative instruments, net
|
|
|
147
|
|
|
|
707
|
|
Gain on sale of assets
|
|
|
|
|
|
|
(354
|
)
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(198
|
)
|
|
|
(1,473
|
)
|
Prepaids and other
|
|
|
(649
|
)
|
|
|
539
|
|
Other assets
|
|
|
(100
|
)
|
|
|
(134
|
)
|
Inventory
|
|
|
37
|
|
|
|
(512
|
)
|
Accounts payable
|
|
|
(381
|
)
|
|
|
1,172
|
|
Accrued liabilities
|
|
|
(418
|
)
|
|
|
7
|
|
Revenue payable
|
|
|
5
|
|
|
|
46
|
|
Advance billings and other
|
|
|
(200
|
)
|
|
|
1,440
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
965
|
|
|
|
11,798
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities:
|
|
|
|
|
|
|
|
|
Additions to oil and gas properties
|
|
|
(3,639
|
)
|
|
|
(15,936
|
)
|
Additions to other property and equipment
|
|
|
(734
|
)
|
|
|
(922
|
)
|
Proceeds from sale of other property and equipment
|
|
|
|
|
|
|
608
|
|
Acquisitions of oil and natural gas properties
|
|
|
(645
|
)
|
|
|
(6,484
|
)
|
Other
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(5,018
|
)
|
|
|
(22,726
|
)
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities:
|
|
|
|
|
|
|
|
|
Proceeds from line of credit
|
|
|
|
|
|
|
15,760
|
|
Payments on line of credit
|
|
|
|
|
|
|
(10,500
|
)
|
Borrowings on note payable
|
|
|
351
|
|
|
|
10
|
|
Payments on note payable
|
|
|
(16
|
)
|
|
|
(94
|
)
|
Members contribution
|
|
|
|
|
|
|
10,000
|
|
Distributions paid
|
|
|
(1,499
|
)
|
|
|
(4,785
|
)
|
Repurchase member units
|
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(1,164
|
)
|
|
|
10,387
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
|
(5,217
|
)
|
|
|
(541
|
)
|
|
|
|
|
|
|
|
|
|
Beginning Cash and Cash Equivalents
|
|
|
5,980
|
|
|
|
763
|
|
|
|
|
|
|
|
|
|
|
Ending Cash and Cash Equivalents
|
|
$
|
763
|
|
|
$
|
222
|
|
|
|
|
|
|
|
|
|
|
Supplemental Cash Flow Information:
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
2
|
|
|
$
|
95
|
|
|
|
|
|
|
|
|
|
|
Non-Cash Investing and Financing Activities:
|
|
|
|
|
|
|
|
|
Accrued capital expendituresoil and gas properties
|
|
$
|
178
|
|
|
$
|
1,209
|
|
|
|
|
|
|
|
|
|
|
Notes receivable from officers, directors and employees
|
|
$
|
|
|
|
$
|
635
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these combined
financial statements.
F-31
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010
|
|
1.
|
Organization
and Nature of Operations
|
Mid-Con Energy, I LLC and Mid-Con Energy II, LLC (collectively,
with their subsidiaries of
Mid-Con
Energy II, LLC, the predecessor) are Delaware
limited liability companies. The predecessors principal
business is the acquisition, development and production of
existing oil and natural gas properties in the Mid-Continent
region of the United States. The predecessor uses secondary oil
recovery techniques, such as waterflooding to increase
production from mature oil fields. Mid-Con Energy II, LLCs
wholly owned subsidiaries are RDT Properties, Inc.
(RDT) and ME3 Oilfield Service, LLC
(ME3). RDT is the sole operator of mineral
properties owned by the predecessor and ME3 provides oil field
construction and maintenance services, as well as oil and water
transportation services, to the predecessor and third parties.
On June 30, 2009, Mid-Con Energy Corporation and its
subsidiaries (collectively, the Corporation),
reorganized to form the predecessor. As a result of this
reorganization, the mineral properties were transferred to the
predecessor, along with the related accounts receivable,
accounts payable and cash. RDT and ME3 were transferred to
Mid-Con Energy II, LLC. The reorganization also resulted in
issuance of notes receivable from certain officers, directors
and shareholders, for the purchase of membership units.
In connection with the closing of the initial public offering of
common units of Mid-Con Energy Partners, LP (the
Partnership), the predecessor will merge with and
into a wholly owned subsidiary of the Partnership in exchange
for a combination of common units issued and cash consideration
paid to the predecessors owners.
|
|
2.
|
Summary
of Significant Accounting Policies
|
Basis of
presentation and principles of combination
The accompanying combined financial statements were derived from
the historical accounting records of the predecessor and reflect
the historical financial position, results of operations and
cash flow for the periods described herein. All intercompany
transactions and account balances have been eliminated.
In the reorganization of the Corporation into the predecessor,
the majority owner of the Corporation became the majority owner
in the predecessor and made additional cash contributions to the
predecessor. Therefore, management of the predecessor determined
that the reorganization constituted a transaction between
entities under common control. In comparison to the purchase
method of accounting, whereby the purchase price for the asset
acquisition would have been allocated to identifiable assets and
liabilities of the predecessor based upon their fair values with
any excess treated as goodwill, transfers between entities under
common control require that assets and liabilities be recognized
by the acquirer at carrying value at the date of transfer, with
any difference between the purchase price and the net book value
of the assets recognized as an adjustment to members
equity.
In addition to the cash contributions from the majority owner,
in the reorganization of the Corporation into the predecessor,
certain officers and directors of the predecessor purchased
Class A Units in consideration of full recourse notes
payable to the predecessor (see Note 6.) The predecessor also
recognized an increase to equity of approximately $0.5 million
related to elimination of deferred tax balances of the
Corporation. As discussed below, as limited liability companies,
the earnings or losses of the predecessor for federal and some
state income tax purposes will generally be included in the tax
returns of the individual unitholders of the predecessor.
F-32
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
The accompanying combined financial statements have been
prepared in accordance with accounting principles generally
accepted in the United States of America (GAAP). The
predecessor operates oil and natural gas properties as one
business segment: the exploration, development and production of
oil and natural gas. The predecessors management evaluates
performance based on one business segment as there are not
different economic environments within the operation of the oil
and natural gas properties.
Use of
estimates
Preparation of financial statements in conformity with GAAP
requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities, the
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues
and expenses during the reporting periods. Actual results could
differ from these estimates. Depletion of oil and gas properties
is determined using estimates of proved oil and gas reserves.
There are numerous uncertainties inherent in the estimation of
quantities of proved reserves and in the projection of future
rates of production and the timing of development expenditures.
Similarly, evaluations for impairment of proved and unproved oil
and gas properties are subject to numerous uncertainties
including, among others, estimates of future recoverable
reserves and commodity price outlooks. Other significant
estimates include, but are not limited to, asset retirement
obligations, purchase price allocations and fair value of
derivative financial instruments.
Cash and cash equivalents
The predecessor considers all cash on hand, depository accounts
held by banks and money market accounts with an original
maturity of three months or less to be cash equivalents.
Accounts receivable
The predecessor sells oil and natural gas to various customers
and participates with other parties in the drilling, completion
and operation of oil and gas wells. The predecessors joint
interest and oil and gas sales receivables related to these
operations are generally unsecured. Accounts receivable for
joint interest billings are recorded as amounts billed to
customers less an allowance for doubtful accounts. Amounts are
considered past due after 30 days. The predecessor
determines joint interest operations accounts receivable
allowances based on managements assessment of the
creditworthiness of the joint interest owners and the
predecessors ability to realize the receivables through
netting of anticipated future production revenues. The
predecessor had no allowance for doubtful accounts at
December 31, 2009 or 2010, and there were no provisions for
bad debts or write-offs of accounts receivable for the periods
then ended.
Revenue recognition
The predecessor uses the sales method of accounting for crude
oil and natural gas revenues. Under this method, revenues are
recognized based on the predecessors shares of actual
proceeds from oil and gas sold to purchasers. Natural gas
revenues would not have been significantly altered for the
period presented had the entitlements method of recognizing
natural gas revenues been utilized. If reserves are not
sufficient to recover natural gas overtake positions, a
liability is recorded. The predecessor had no significant
natural gas imbalances at December 31, 2009 or 2010.
F-33
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
Oil and natural gas properties
The predecessor utilizes the successful efforts method of
accounting for its oil and gas properties. Under this method all
costs associated with productive wells and nonproductive
development wells are capitalized, while nonproductive
exploration costs are expensed. Capitalized costs relating to
proved properties are depleted using the
units-of-production
method based on proved reserves on a field basis. The
depreciation of capitalized production equipment is based on the
units-of-production
method using proved developed reserves on a field basis. The
predecessor had no exploratory wells in progress and no
capitalized exploratory well costs pending determination of
reserves at December 31, 2009 and 2010.
Capitalized costs of individual properties abandoned or retired
are charged to accumulated depreciation, depletion and
amortization. Proceeds from sales of individual properties are
credited to property costs. No gain or loss is recognized until
the entire amortization base (field) is sold or abandoned.
Costs of significant nonproducing properties and wells in the
process of being drilled are excluded from depletion until such
time as the proved reserves are established or impairment is
determined. Costs of significant development projects are
excluded from depreciation until the related project is
completed. The predecessor capitalizes interest, if debt is
outstanding, on expenditures for significant development
projects until such projects are ready for their intended use.
At December 31, 2009 and December 31, 2010, the
predecessor had no significant amount of capitalized interest.
The predecessor reviews its long-lived assets to be held and
used, including proved oil and gas properties accounted for
under the successful efforts method of accounting, whenever
events or circumstances indicate that the carrying value of
those assets may not be recoverable. The impairment provision is
based on the excess of carrying value over fair value. Fair
value is defined as the present value of the estimated future
net revenues from production of total proved and risk-adjusted
probable and possible oil and gas reserves over the economic
life of the reserves based on the predecessors
expectations of future oil and gas prices and costs. The
predecessor reviews its oil and gas properties by amortization
base (field) or by individual well for those wells not
constituting part of an amortization base.
The predecessor recognized approximately $9.2 million
restated and $1.9 million restated as impairment charges
against earnings for the periods ended December 31, 2009
and 2010, respectively, related to its proved oil and gas
properties due to a significant decline in estimated proved and
probable reserves values. These non-cash charges are included in
the Impairment of proved oil and gas properties line
item in the accompanying statements of operations. The fair
value of the properties was measured by estimated cash flow
reported in the audited reserve report. This report was based
upon future oil and natural gas prices, which are based on
observable inputs adjusted for basis differentials, which are
Level 3 inputs in the fair value hierarchy described in
Note 3. The fair values of proved properties are measured
using valuation techniques consistent with the income approach,
converting future cash flow to a single discounted amount.
Significant inputs used to determine the fair values of proved
properties include estimates of reserves, future operating and
development costs, future commodity prices and market-based
weighted average cost of capital rate. The underlying commodity
prices embedded in the Corporations estimated cash flow
are the product of a process that begins with New York
Mercantile Exchange (NYMEX) forward curve pricing,
adjusted for estimated location and quality differentials, as
well as other factors that management believes will impact
realizable prices. Furthermore, significant assumptions in
valuing the proved reserves included
F-34
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
the reserve quantities, anticipated drilling and operating
costs, anticipated production taxes, future expected oil and
natural gas prices. Cash flow estimates for the impairment
testing excluded derivative instruments used to mitigate the
risk of lower future oil and natural gas prices. The impairments
were caused by below expected performance for some of the
waterflood units and other producing properties and revisions to
the future expected drilling schedules. These impairments have
no impact on the predecessor cash flow, liquidity
position, or debt covenants.
Unproved oil and gas properties are each periodically assessed
for impairment by comparing their costs to their estimated
values on a
project-by-project
basis. The estimated value is affected by the results of
exploration activities, future drilling plans, commodity price
outlooks, planned future sales or expiration of all or a portion
of leases on such projects. If the quantity of potential
reserves determined by such evaluations is not sufficient to
fully recover the cost invested in each project, the predecessor
recognizes an impairment loss at that time. The predecessor had
no abandonments for the period from inception (July 1,
2009) to December 31, 2009. The predecessor recognized
approximately $1.4 million as abandonment expenses for the
year ended December 31, 2010, related to its unproved oil
and gas properties.
In January 2010, the Financial Accounting Standards Board
(FASB) issued an accounting standards update that
aligns the oil and natural gas reserve estimation and disclosure
requirements of GAAP with the requirements in the final rule,
Modernization of the Oil and Gas Reporting Requirements,
issued in December 31, 2008 by the United States Securities
and Exchange Commission (SEC) and effective for
fiscal years ending on or after December 31, 2009. The new
rules are intended to provide investors with a more meaningful
and comprehensive understanding of oil and natural gas reserves,
which should help investors evaluate the relative value of oil
and natural gas companies. The new rules permit the use of new
technologies to determine proved reserves estimates if those
technologies have been demonstrated empirically to lead to
reliable conclusions about reserve volume estimates. The new
rules will also allow, but not require, companies to disclose
their probable and possible reserves to investors in documents
filed with the SEC. In addition, the new disclosure requirements
require companies to: (i) report the independence and
qualifications of its reserves preparer or auditor;
(ii) file reports when a third party is relied upon to
prepare reserves estimates or conduct a reserves audit; and
(iii) report oil and natural gas reserves using an average
price based upon the prior
12-month
period rather than a year-end price. The predecessor adopted the
updated requirements as of December 31, 2009, which had the
effect of adding 307 MBoe of proved reserves. See reserves
information in Note 11.
Oil and gas property is stated at cost less accumulated
depletion, depreciation and impairment and consisted of the
following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
|
(as restated,
|
|
|
|
see Note 12)
|
|
|
Oil and gas properties
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
37,069
|
|
|
$
|
57,364
|
|
Unproved properties
|
|
|
397
|
|
|
|
446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37,466
|
|
|
|
57,810
|
|
Less: Accumulated depletion, depreciation and amortization
|
|
|
2,358
|
|
|
|
7,521
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties, net
|
|
$
|
35,108
|
|
|
$
|
50,289
|
|
|
|
|
|
|
|
|
|
|
F-35
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
Other
property and equipment
Other property and equipment is stated at historical cost and is
comprised of software, vehicles, office equipment, and field
service equipment. Costs incurred for normal repairs and
maintenance are charged to expense as incurred, unless they
extend the useful life of the asset. Depreciation is calculated
using the straight-line method based on useful lives of the
assets ranging from three to fifteen years and is included in
the accumulated depletion, depreciation and amortization totals.
Depreciation expense related to other property and equipment for
the periods ended December 31, 2009 and 2010 totaled
$0.2 million and $0.6 million, respectively. Other
property and equipment consist of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Land
|
|
$
|
19
|
|
|
$
|
19
|
|
Leasehold improvements (15 years)
|
|
|
33
|
|
|
|
33
|
|
Hardware and software (3-5 years)
|
|
|
249
|
|
|
|
282
|
|
Furniture and fixtures (5 years)
|
|
|
88
|
|
|
|
88
|
|
Machinery and equipment (5 years)
|
|
|
1,073
|
|
|
|
1,882
|
|
Field building (15 years)
|
|
|
20
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,482
|
|
|
|
2,324
|
|
Less: accumulated depreciation
|
|
|
368
|
|
|
|
957
|
|
|
|
|
|
|
|
|
|
|
Other property, plant and equipment, net
|
|
$
|
1,114
|
|
|
$
|
1,367
|
|
|
|
|
|
|
|
|
|
|
Asset
retirement obligations
The predecessor has obligations under its lease agreements and
federal regulations to remove equipment and restore land at the
end of oil and natural gas production operations. These asset
retirement obligations (ARO) are primarily
associated with plugging and abandoning wells. Determining the
future restoration and removal requires management to make
estimates and judgments because most of the removal obligations
are many years in the future and contracts and regulations often
have vague descriptions of what constitutes removal. Asset
removal technologies and costs are constantly changing, as are
regulatory, political, environmental, safety and public
relations considerations. The predecessor is required to record
the fair value of a liability for an ARO in the period in which
it is incurred with a corresponding increase in the carrying
amount of the related long-lived asset. The predecessor
typically incurs this liability upon acquiring or drilling a
well. Over time, the liability is accreted each period toward
its future value and the capitalized cost is depleted as a
component of development costs. Upon settlement of the
liability, a gain or loss is recognized to the extent the actual
costs differ from the recorded liability.
Inherent to the present value calculation are numerous
estimates, assumptions and judgments, including the ultimate
settlement amounts, inflation factors, credit adjusted risk-free
rates, timing of settlement and changes in the legal,
regulatory, environmental and political environments. To the
extent future revisions to these assumptions impact the present
value of the abandonment liability, management will make
corresponding adjustments to both the ARO and the related oil
and natural gas property asset balance. Increases in the
discounted
F-36
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
retirement obligation liability and related oil and natural gas
assets resulting from the passage of time will be reflected as
additional accretion and depreciation expense in the combined
statements of operations.
Derivatives
and hedging
All derivative instruments are recorded on the balance sheet as
either assets or liabilities at fair value. Derivative
instruments that do not meet specific hedge accounting criteria
must be adjusted to fair value through net income. Effective
changes in the fair value of derivative instruments that are
accounted for as cash flow hedges are recognized in other
accumulated comprehensive income in members equity until
such time as the hedged items are recognized in net income.
Ineffective portions of a derivative instruments change in
fair value are immediately recognized in net income.
None of the predecessors derivatives held during 2010 and
2009 were designated as hedges for financial statement purposes;
therefore, the adjustments to fair value are included in net
income. Realized and unrealized gains and losses on derivatives
are shown separately in the statement of operations and are
included in cash flow from operating activities.
Inventory
Inventory consists primarily of oilfield equipment and is valued
at the lower of cost or market. No excess or obsolete reserve
has been recorded at December 31, 2009, or
December 31, 2010.
Deferred
financing costs
Costs incurred in connection with the execution or modification
of the predecessors credit facilities were expensed as
incurred based on the immateriality of costs.
Other
noncurrent assets
The predecessor has accrued interest receivable related to notes
receivable from officers, directors and employees, which is
classified as other noncurrent assets on the combined balance
sheet.
Other
revenue and expense, net
The predecessor receives fees for the operation of jointly-owned
oil and gas properties and records such reimbursements as
reductions of other revenue and expense, net. Such fees totaled
$1.2 million and $3.1 million for the period from
inception (July 1, 2009) to December 31, 2009,
and the year ended December 31, 2010, respectively.
Unit-based
compensation
The cost of employee services received in exchange for equity
instruments is measured based on the grant-date fair value of
compensation expense over the requisite service period (often
the vesting period). Awards subject to performance criteria vest
when it is probable that the performance criteria will be met.
Compensation for these awards is recorded upon vesting, based on
their grant-date fair value. Generally, no compensation expense
is recognized for equity instruments that do not vest. The
unit-based compensation expense was not significant for either
of the periods presented.
F-37
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
Income taxes
The entities comprising the predecessor are two limited
liability companies, and, as such, their earnings or losses for
federal and some state income tax purposes will generally be
included in the tax returns of the individual unitholders of the
predecessor. Earnings or losses for financial statement purposes
may differ significantly from those reported to the individual
unitholders for income tax purposes as a result of differences
between the tax basis and financial reporting basis of assets
and liabilities and the taxable income allocation requirements
under the limited liability agreement of the predecessor.
The predecessor evaluates uncertain tax positions for
recognition and measurement in the financial statements. To
recognize a tax position, the predecessor determines whether it
is more likely than not that the tax positions will be sustained
upon examination, including resolution of any related appeals or
litigation, based on the technical merits of the position. A tax
position that meets the more likely than not threshold is
measured to determine the amount of benefit to be recognized in
the financial statements. The amount of tax benefit recognized
with respect to any tax position is measured as the largest
amount of benefit that is greater than 50% likely of being
realized upon settlement. The predecessor had no uncertain tax
positions that required recognition in the financial statements
at December 31, 2009 or 2010. Any interest or penalties
would be recognized as a component of income tax expense.
New Accounting Pronouncements
In December 2010, the FASB issued an accounting standards update
regarding disclosure of supplementary pro forma information for
business combinations. This update was issued in order to
address diversity in practice about the interpretation of the
pro forma revenue and earnings disclosure requirements. The
update requires a public entity to disclose pro forma
information for business combinations that occurred in the
current reporting period. The disclosures include pro forma
revenue and earnings of the combined entity for the current
reporting period as though the acquisition date for all business
combinations that occurred during the year had been as of the
beginning of the annual reporting period. If comparative
financial statements are presented, the pro forma revenue and
earnings of the combined entity for the comparable prior
reporting period should be reported as though the acquisition
date for all business combinations that occurred during the
current year had been as of the beginning of the comparable
prior annual reporting period. In practice, some preparers have
presented the pro forma information in their comparative
financial statements as if the business combination that
occurred in the current reporting period had occurred as of the
beginning of each of the current and prior annual reporting
periods. Other preparers have disclosed the pro forma
information as if the business combination occurred at the
beginning of the prior annual reporting period only, and carried
forward the related adjustments, if applicable, through the
current reporting period. The predecessor plans to adopt the
updated rules in relation to all future business combinations.
In January 2010, the FASB issued an accounting standards update
for improving disclosure about fair value measurements. This
amendment to the disclosure requirements provides guidance that
clarifies and requires new disclosures about fair value
measurements. The clarifications and requirement to disclose the
amounts and reasons for significant transfers between
Level 1 and Level 2, as well as significant transfers
in and out of Level 3 of the fair value hierarchy, were
adopted by the predecessor in the last quarter of 2010.
Note 3Fair Value Measurements reflects the
amended disclosure requirements. The new guidance also requires
that purchases, sales, issuances, and settlements be presented
gross in the Level 3 reconciliation and that requirement is
effective for fiscal years beginning after December 15,
2010 and for
F-38
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
interim periods within those years, with early adoption
permitted. Since this new guidance only amends the disclosures
requirements, it did not impact the statement of financial
position, statement of operations, or cash flow statement.
|
|
3.
|
Fair
Value Measurement
|
The carrying amounts reported in the balance sheet for cash,
accounts receivable, accounts payable and derivative financial
instruments approximate their fair values. The recorded values
of the predecessors credit facilities approximate fair
value as the interest rate is variable and the terms of the
credit facilities are similar to what the predecessor believes
comparable companies would receive.
The predecessor accounts for its oil and gas commodity
derivatives at fair value. The fair value of derivative
financial instruments is determined utilizing the NYMEX closing
prices for the contract period.
The predecessor has categorized their financial instruments,
based on the priority of inputs to the valuation technique, into
a three-level fair value hierarchy. The fair value hierarchy
gives the highest priority to quoted prices in active markets
for identical assets or liabilities (Level 1) and the
lowest priority to unobservable inputs (Level 3).
Financial assets and liabilities recorded in the balance sheet
are categorized based on the inputs to the valuation techniques
as follows:
Level 1Financial assets and liabilities for
which values are based on unadjusted quoted prices for identical
assets or liabilities in an active market that management has
the ability to access.
Level 2Financial assets and liabilities for
which values are based on quoted prices in markets that are not
active or model inputs that are observable either directly or
indirectly for substantially the full term of the asset or
liability.
Level 3Financial assets and liabilities for
which values are based on prices or valuation techniques that
require inputs that are both unobservable and significant to the
overall fair value measurement. These inputs reflect
managements own assumptions about the assumptions a market
participant would use in pricing the asset or liability.
When the inputs used to measure fair value fall within different
levels of the hierarchy in a liquid environment, the level
within which the fair value measurement is categorized is based
on the lowest level input that is significant to the fair value
measurement in its entirety. Changes in the observability of
valuation inputs may result in a reclassification for certain
financial assets
F-39
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
or liabilities. The following presents the predecessors
fair value hierarchy for assets and liabilities measured at fair
value on December 31, 2009 and December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
(in thousands)
|
|
|
(as restated, see Note 12)
|
|
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets and Liabilities Measured at Fair Value on a Recurring
Basis
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instrumentsliability
|
|
$
|
|
|
|
$
|
222
|
|
|
$
|
|
|
Assets and Liabilities Measured at Fair Value on a Nonrecurring
Basis
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,679
|
|
Impairment of proved oil and gas properties
|
|
$
|
|
|
|
$
|
|
|
|
$
|
9,208
|
|
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets and Liabilities Measured at Fair Value on a Recurring
Basis
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instrumentsliability
|
|
$
|
|
|
|
$
|
904
|
|
|
$
|
|
|
Assets and Liabilities Measured at Fair Value on a Nonrecurring
Basis
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
$
|
|
|
|
$
|
|
|
|
$
|
319
|
|
Impairment of proved oil and gas properties
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,886
|
|
Assets and Liabilities Measured at Fair Value on a
Nonrecurring Basis
Certain assets and liabilities are reported at fair value on a
nonrecurring basis in the predecessors combined balance
sheet.
The predecessor estimates the fair value of the asset retirement
obligations based on discounted cash flow projections using
numerous estimates, assumptions and judgments regarding such
factors as the existence of a legal obligation for an ARO;
amounts and timing of settlements; the credit-adjusted risk-free
rate to be used; and inflation rates. See Note 4 for a
summary of changes in asset retirement obligations.
The predecessor reviews its long-lived assets to be held and
used, including proved oil and natural gas properties, whenever
events or circumstances indicate that the carrying value of
those assets may not be recoverable. An impairment loss is
indicated if the sum of the expected undiscounted future net
cash flows is less than the carrying amount of the assets. In
this circumstance, the predecessor recognizes an impairment loss
for the amount by which the carrying amount of the asset exceeds
the estimated fair value of the asset and reduces the carrying
amount of the asset. Estimating future cash flows involves the
use of judgments, including estimation of the proved oil and
natural gas reserve quantities, timing of development and
production, expected future commodity prices, capital
expenditures and production costs.
|
|
4.
|
Asset
Retirement Obligations
|
Asset retirement obligations are recorded as a liability at
their estimated present value at the various assets
inception, with the offsetting charge to oil and gas properties.
Periodic accretion of the discounted estimated liability is
recorded in the statement of operations. The discounted
capitalized cost is amortized to expense through the
depreciation calculation over the life of the assets based on
proved developed reserves.
F-40
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
The predecessors asset retirement obligations primarily
represent the estimated present value of the amount the
predecessor will incur to plug, abandon and remediate its
producing properties at the end of its production lives, in
accordance with applicable state laws. The predecessor has
determined their asset retirement obligations by calculating the
present value of estimated cash flows related to the liability.
The following is a reconciliation of the asset retirement
obligations at December 31, 2010 and 2009 (in thousands):
|
|
|
|
|
Asset retirement obligations at July 1, 2009
|
|
$
|
1,569
|
|
Liabilities incurred for new wells
|
|
|
115
|
|
Revision in estimates
|
|
|
(5
|
)
|
Accretion expense
|
|
|
58
|
|
|
|
|
|
|
Asset retirement obligations at December 31, 2009
|
|
|
1,737
|
|
Liabilities incurred for new wells
|
|
|
265
|
|
Disposition of wells
|
|
|
(35
|
)
|
Revision in estimates
|
|
|
54
|
|
Accretion expense
|
|
|
127
|
|
|
|
|
|
|
Asset retirement obligations at December 31, 2010
|
|
$
|
2,148
|
|
|
|
|
|
|
|
|
5.
|
Derivative
Financial Instruments
|
The predecessor is exposed to oil commodity price risk and
considers it prudent to periodically reduce its exposure to cash
flow variability resulting from commodity price change
fluctuations. Accordingly the predecessor enters into derivative
instruments to manage its exposure to commodity price
fluctuations, and fluctuations in location differences between
published index prices and the NYMEX futures prices.
At December 31, 2009 and 2010, the predecessors open
positions consisted of crude oil price collar contracts and
crude oil price swap contracts. Under commodity swap agreements,
the predecessor exchanges a stream of payments over time
according to specified terms with another counterparty. In a
typical commodity price swap agreement, the predecessor agrees
to pay an adjustable or floating price tied to an agreed upon
index for the oil commodity and in return receives a fixed price
based on notional quantities. A collar is a combination of a put
purchased by a party and a call option sold by the same party.
In a typical collar transaction, if the floating price based on
a market index is below the floor price, the predecessor
receives from the counterparty an amount equal to this
difference multiplied by the specified volume, effectively a put
option. If the floating price exceeds the floor price and is
less than the ceiling price, no payment is required by either
party. If the floating price exceeds the ceiling price, the
predecessor must pay the counterparty an amount equal to the
difference multiplied by the specific quantity, effectively a
call option.
The predecessor elected not to designate any positions as cash
flow hedges for accounting purposes and, accordingly, recorded
the net change in the
mark-to-market
valuation of these derivative contracts in the statement of
operations. The predecessor recorded its derivative activities
on a
mark-to-market
or fair value basis. Pursuant to the accounting standard that
permits netting of assets and liabilities where the right of
offset exists, the predecessor presents the fair value of
derivative financial instruments on a net basis.
F-41
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
At December 31, 2009 the predecessor had the following
commodity derivative open positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement
|
|
|
|
|
|
|
|
|
Instrument
|
|
Total
|
|
|
NYMEX
|
|
|
|
|
Months Outstanding
|
|
Price
|
|
|
Floor
|
|
|
Ceiling
|
|
|
Type
|
|
Bbls
|
|
|
Index
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
Jan 2010 Dec 2010
|
|
|
|
|
|
$
|
72.50
|
|
|
$
|
83.00
|
|
|
Collar
|
|
|
5,000
|
|
|
|
WTI
|
|
|
$
|
(184
|
)
|
Jan 2011 June 2011
|
|
$
|
77.45
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
2,000
|
|
|
|
WTI
|
|
|
|
(38
|
)
|
At December 31, 2010 the predecessor had the following
commodity derivative open positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement
|
|
|
|
|
|
|
|
|
Instrument
|
|
Total
|
|
|
NYMEX
|
|
|
|
|
Months Outstanding
|
|
Price
|
|
|
Floor
|
|
|
Ceiling
|
|
|
Type
|
|
Bbls
|
|
|
Index
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
Jan 2011 Dec 2011
|
|
$
|
83.25
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
18,000
|
|
|
|
WTI
|
|
|
$
|
(357
|
)
|
Jan 2011 Dec 2011
|
|
$
|
86.75
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
12,000
|
|
|
|
WTI
|
|
|
|
(227
|
)
|
Jan 2011 Dec 2011
|
|
$
|
85.30
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
12,000
|
|
|
|
WTI
|
|
|
|
(183
|
)
|
Jan 2011 Dec 2011
|
|
$
|
89.55
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
18,000
|
|
|
|
WTI
|
|
|
|
(137
|
)
|
At December 31, 2010 and 2009, the predecessor recorded the
estimated fair value of $0.9 million and $0.2 million,
respectively, for these swaps and collars as current liabilities
on the balance sheet.
The predecessors derivative contracts are secured by an
agreement with one of the predecessors purchasers;
whereby, the derivative counterparty can seek payment directly
from the predecessors purchaser on the predecessors
oil production under the contract, should the predecessor be in
default of the contract.
A certain officer and unitholder of the predecessor is entitled
to, or responsible for, as applicable, 10% of the receivable or
payable, respectively, on the monthly settlement from or to, as
applicable, the derivative counterparty.
Membership Units
On July 1, 2009, Mid-Con Energy I, LLC issued
Class A Units, Class B Units and Class C Units.
Class A and Class B Units have voting rights.
Class C Units are not entitled to voting rights. At
December 31, 2010, 332,500 Class A Units, 384,022,
Class B Units and 31,437 Class C Units were issued and
outstanding. The Class B Units and the Class C Units
will be allocated value upon all Class A Unitholders
recouping their investment, plus 6%.
On July 1, 2009, Mid-Con Energy II, LLC issued Class A
Units, Class B Units and Class C Units. Class A
and Class B Units have voting rights. Class C Units
are not entitled to voting rights. At December 31, 2010,
212,926 Class A Units, 745,674 Class B Units and
51,406 Class C Units were issued and outstanding. The
Class B Units and the Class C Units will be allocated
value upon all Class A Unitholders recouping their
investment, plus 6%.
F-42
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
Upon formation of Mid-Con Energy I, LLC and Mid-Con Energy
II, LLC, certain officers and directors purchased 6,463
Class A Units of Mid-Con Energy II, LLC at $100 per unit in
consideration of full recourse notes totaling approximately
$0.6 million.
In 2010, Mid-Con Energy II, LLC sold an additional 100,000
Class A Units for $100 per unit. At that time, the officers
and directors holding Class A Units of Mid-Con Energy II,
LLC purchased an additional 6,463 Class A Units at $100 per
unit in consideration of full recourse notes totaling
approximately $0.6 million.
In 2009, certain employees of the predecessor were granted a
total of 51,406 non-vested Class C Units of Mid-Con Energy
II, LLC. These unit awards are subject to a restricted period of
four years, beginning on the date of grant. During the
restricted period, the employees may not sell, transfer, pledge,
exchange or otherwise dispose of the units. The units vest
ratably over the restricted period. All awards immediately vest
upon a change of control, of the predecessor. If the
employees employment or service to the predecessor is
terminated prior to vesting, that person has no further rights
to the Class C Units. No unit awards were granted in 2010.
The following is an analysis of non-vested Class C Units
for 2009 and 2010:
|
|
|
|
|
|
|
|
|
|
|
Period from Inception
|
|
|
|
|
|
|
(July 1, 2009) to
|
|
|
Year Ended
|
|
|
|
December 31, 2009
|
|
|
December 31, 2010
|
|
|
Beginning non-vested Class C Units outstanding
|
|
|
|
|
|
|
51,406
|
|
Awards granted
|
|
|
51,406
|
|
|
|
|
|
Awards cancelled
|
|
|
|
|
|
|
(4,400
|
)
|
Awards vested
|
|
|
|
|
|
|
(11,752
|
)
|
|
|
|
|
|
|
|
|
|
Ending non-vested Class C Units outstanding
|
|
|
51,406
|
|
|
|
35,254
|
|
|
|
|
|
|
|
|
|
|
Notes Receivable from Officers, Directors and Employees
In the aggregate at December 31, 2009 and 2010, the
predecessor had notes receivable from officers, directors and
employees of $1.2 million and $1.8 million,
respectively, plus accrued interest of $0.1 million and
$0.2 million, respectively. The notes mature at the earlier
of the date upon which the predecessor or any successor to the
predecessor registers any class of its membership units under
Section 12 of the Securities Exchange Act of 1934 (the
Exchange Act); is required to file periodic reports
under Section 15(d) of the Exchange Act; the date a
registration statement filed under the Securities Act of 1933 is
declared effective; or April 2, 2013 for Mid-Con
Energy I, LLC units and June 15, 2016 for Mid-Con
Energy II, LLC units. The stated annual interest rate on all
notes is 6%. Interest is compounded annually. All accrued and
unpaid interest on the notes is due and payable at maturity. All
such notes receivable were originally issued in conjunction with
purchases of the predecessors membership units by the
predecessors officers, directors and employees.
Performance of the predecessors officers, directors and
employees obligations under these notes is secured by security
interests granted by each of them to the predecessor in all of
the membership units purchased. Additionally, the predecessor
has full recourse against the assets of the predecessors
officers, directors and employees for collection of amounts due
upon the occurrence of a default that is not remedied.
F-43
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
Debt at December 31, 2009 and 2010 consisted of the
following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
Revolving credit facilities
|
|
$
|
|
|
|
$
|
5,260
|
|
Term loan
|
|
|
337
|
|
|
|
253
|
|
|
|
|
|
|
|
|
|
|
|
|
|
337
|
|
|
|
5,513
|
|
Less: Current portion
|
|
|
94
|
|
|
|
5,354
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
243
|
|
|
$
|
159
|
|
|
|
|
|
|
|
|
|
|
The predecessor has borrowing capacity of $17 million under
two revolving credit facilities with a financial institution.
The total borrowing base is also $17 million, re-determined
semi-annually based on the predecessors oil and natural
gas reserves. Interest is payable monthly and charged at LIBOR,
at the financial institutions prime rate, or 4.0%,
whichever is greatest. The predecessors oil properties
located in southern Oklahoma are pledged as security under the
agreements. The predecessor had approximately $5.3 million
borrowed against the lines of credit at December 31, 2010.
There were no outstanding letters of credit as of
December 31, 2010. The predecessor had no outstanding
borrowings and no outstanding letters of credit at
December 31, 2009. The revolving credit facility matures at
December 31, 2011.
During 2009, the predecessor entered into a variable rate term
loan for approximately $350,000. The loan bears interest at New
York Prime Rate (3.25% at December 31, 2010) and
matures on October 9, 2013. Payments due on the term loan
are approximately $87,000 in 2011, $90,000 in 2012 and $76,000
in 2013.
Financial instruments which potentially subject the predecessor
to credit risk consist principally of cash balances, accounts
receivable and derivative financial instruments. The predecessor
maintains cash and cash equivalents in bank deposit accounts
which, at times, may exceed the federally insured limits. The
predecessor has not experienced any significant losses from such
investments.
For the six months ended December 31, 2009, purchases by a
subsidiary of Sunoco Logistics Partners L.P. (Sunoco
Logistics), ScissorTail Energy, LLC and Teppco Crude Oil,
LLC accounted for 78%, 11% and 5%, respectively of the
predecessors total sales revenues. These purchasers
represented 74%, 12% and 3%, respectively, of the outstanding
oil and natural gas accounts receivable for the six months ended
December 31, 2009.
For the year ended December 31, 2010, purchases by Sunoco
Logistics, ScissorTail Energy, LLC and Teppco Crude Oil, LLC
accounted for 76%, 8% and 5%, respectively of the
predecessors total sales revenues. These purchasers
represented 83%, 9% and 6%, respectively, of the outstanding oil
and natural gas accounts receivable for the year ended
December 31, 2010.
Management believes that the loss of any one purchaser would not
have an adverse effect on the ability of the predecessor to sell
its oil and gas production because management believes market
conditions are such that the predecessors could sell to other
purchasers at market-based
F-44
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
prices. The predecessor has not experienced any significant
losses due to uncollectible accounts receivable from these
purchasers.
|
|
9.
|
Commitments
and Contingencies
|
In the normal course of business, the predecessor enters into
contracts that contain a variety of representations and
warranties and provide general indemnifications. The
predecessors maximum exposure under these arrangements is
unknown as this would involve future claims that may be made
against the predecessor that have not yet occurred. The
predecessor does not expect to suffer any material losses in
connection with these contracts.
Various federal, state and local laws and regulations covering,
among other things, the release of waste materials into the
environment and state and local taxes affect the
predecessors operations and costs. Management believes the
predecessor is in substantial compliance with applicable
federal, state and local laws, and management expects that the
ultimate resolution of any claims or legal proceedings
instituted against the predecessor will not have a material
effect on its financial position or results of operations.
The predecessor is party to a non-cancelable operating lease for
office space for its office in Tulsa, Oklahoma. Rent expense was
approximately $0.1 million and $0.2 million for the
periods ended December 31, 2009 and 2010. Future minimum
lease commitments under this lease at December 31, 2010,
are approximately $90,000 per year in 2011 and 2012.
|
|
10.
|
Defined
Contribution Plans
|
The predecessor maintains a 401(k) contribution plan (the
Plan). Employees must be 21 years of age or
older and have worked for 90 days to be eligible to
participate. Employees may contribute 15% of their compensation
up to the annual IRS limitation. The predecessor makes
contributions of 3% of an employees pay and employees are
100% vested at all times. For the period from inception
(July 1, 2009) to December 31, 2009, and the year
ended December 31, 2010, the predecessor contributed
approximately $44,000 and $107,000, respectively, to the Plan.
|
|
11.
|
Supplemental
Oil and Gas Disclosures
|
Costs
Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities
Costs incurred in the acquisition and development of oil and gas
assets are presented below for the period from inception
(July 1, 2009) through December 31, 2009 and for
the year ended December 31, 2010 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
642
|
|
|
$
|
6,483
|
|
Unproved
|
|
|
4
|
|
|
|
1
|
|
Exploration
|
|
|
|
|
|
|
912
|
|
Development
|
|
|
3,099
|
|
|
|
16,843
|
|
Asset retirement obligations
|
|
|
101
|
|
|
|
353
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
$
|
3,846
|
|
|
$
|
24,592
|
|
|
|
|
|
|
|
|
|
|
F-45
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
Net
Proved Oil and Gas Reserves(Unaudited)
The predecessors proved oil and gas reserves as of
December 31, 2009 were prepared by the predecessors
reservoir engineers. The predecessors proved oil and gas
reserves as of December 31, 2010 were audited by Cawley,
Gillespie & Associates, Inc., independent third party
petroleum consultants. In accordance with the updated SEC
regulations, reserves at December 31, 2010 and 2009 were
estimated using the unweighted arithmetic average
first-day-of-the-month
price for the preceding 12month period for oil and natural
gas. Reserve estimates are inherently imprecise and that
estimates of new discoveries are more imprecise than those of
producing oil and natural gas properties. Accordingly, the
estimates are expected to change as future information becomes
available. An analysis of the change in estimated quantities of
oil and gas reserves, all of which are located within the United
States, for the period from inception (July 1,
2009) through December 31, 2009 and for the year ended
December 31, 2010, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from Inception (July 1, 2009)
|
|
|
|
to December 31, 2009
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
MBoe
|
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
4,868
|
|
|
|
916
|
|
|
|
5,021
|
|
Revisions of previous estimates
|
|
|
1,293
|
|
|
|
29
|
|
|
|
1,298
|
|
Extensions, discoveries and other additions
|
|
|
113
|
|
|
|
4
|
|
|
|
114
|
|
Purchases of minerals in place
|
|
|
12
|
|
|
|
|
|
|
|
12
|
|
Production
|
|
|
(87
|
)
|
|
|
(140
|
)
|
|
|
(110
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
|
6,199
|
|
|
|
809
|
|
|
|
6,335
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
2,489
|
|
|
|
834
|
|
|
|
2,628
|
|
End of period
|
|
|
2,513
|
|
|
|
809
|
|
|
|
2,649
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
2,379
|
|
|
|
82
|
|
|
|
2,393
|
|
End of period
|
|
|
3,686
|
|
|
|
|
|
|
|
3,686
|
|
F-46
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31, 2010
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
MBoe
|
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
6,199
|
|
|
|
809
|
|
|
|
6,335
|
|
Revisions of previous estimates
|
|
|
(469
|
)
|
|
|
728
|
|
|
|
(347
|
)
|
Extensions, discoveries and other additions
|
|
|
765
|
|
|
|
|
|
|
|
765
|
|
Purchases of minerals in place
|
|
|
740
|
|
|
|
|
|
|
|
740
|
|
Production
|
|
|
(228
|
)
|
|
|
(191
|
)
|
|
|
(260
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
|
7,007
|
|
|
|
1,346
|
|
|
|
7,231
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
2,513
|
|
|
|
809
|
|
|
|
2,649
|
|
End of year
|
|
|
3,601
|
|
|
|
1,346
|
|
|
|
3,825
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
3,686
|
|
|
|
|
|
|
|
3,686
|
|
End of year
|
|
|
3,406
|
|
|
|
|
|
|
|
3,406
|
|
The tables above include changes in estimated quantities of oil
and natural gas reserves shown in MBoe equivalents at a rate of
six Mcf per Boe.
The change in quantities of proved reserves during the period
from July 1, 2009 through December 31, 2010 is due to
(i) increases in oil prices during this time period,
(ii) acquisitions of third party interests in existing
waterflood units, (iii) infill drilling in our Battle
Springs and Highlands waterflood units which resulted in an
upward revision of oil in place and therefore recoverable
reserves, and (iv) production responses from our existing
waterflood units that exceeded earlier projections.
Estimates of economically recoverable oil and natural gas
reserves and of future net revenues are based upon a number of
variable factors and assumptions, all of which are to some
degree subjective and may vary considerably from actual results.
Therefore, actual production, revenues, development and
operating expenditures may not occur as estimated. The reserve
data are estimates only, are subject to many uncertainties and
are based on data gained from production histories and on
assumptions as to geologic formations and other matters. Actual
quantities of oil and natural gas may differ materially from the
amounts estimated.
Standardized
Measure of Discounted Future Net Cash
Flow(Unaudited)
The estimates of future cash flow and future production and
development costs as of December 31, 2010 and 2009 are
based on the unweighted arithmetic average
first-day-of-the-month
price for the preceding
12-month
period. Estimated future production of proved reserves and
estimated future production and development costs of proved
reserves are based on current costs and economic conditions. No
future income tax expenses are computed because the predecessor
entities are pass-through entities for federal income tax
purposes. Prices used were $61.18 and $79.43 per Bbl of oil and
$3.83 and $4.37 per Mcf of natural gas for December 31,
2009 and 2010, respectively. These prices were adjusted by lease
for quality, transportation fees, location differentials,
marketing bonuses or deductions or other factors affecting the
price received at the wellhead. Average adjusted prices used
were $54.92 and $74.26 per Bbl of oil and
F-47
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
$3.91 and $7.36 per Mcf of natural gas for December 31,
2009 and 2010, respectively. Adjusted natural gas price includes
the sale of associated natural gas liquids. All wellhead prices
are held flat over the life of the properties for all reserve
categories. The estimated future net cash flow is then
discounted at a rate of 10%.
The standardized measure of discounted future net cash flow does
not purport to be, nor should it be interpreted to represent,
the fair market value of the proved oil and natural gas reserves
of the predecessor. An estimate of fair value would take into
account, among other things, the recovery of reserves not
presently classified as proved, the value of unproved
properties, and consideration of expected future economic and
operating conditions. The disclosures shown are based on
estimates of proved reserve quantities and future production
schedules which are inherently imprecise and subject to
revision, and the 10% discount rate is arbitrary. In addition,
costs and prices as of the measurement date are used in the
determinations, and no value may be assigned to probable or
possible reserves.
The standardized measure of discounted future net cash flow
relating to proved oil and natural gas reserves is as follows at
December 31:
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Future cash inflows
|
|
$
|
343,595
|
|
|
$
|
529,309
|
|
Future production costs
|
|
|
(109,344
|
)
|
|
|
(152,913
|
)
|
Future development costs
|
|
|
(26,447
|
)
|
|
|
(26,802
|
)
|
|
|
|
|
|
|
|
|
|
Future net cash flow
|
|
|
207,804
|
|
|
|
349,594
|
|
10% discount for estimated timing of cash flow
|
|
|
(102,004
|
)
|
|
|
(165,932
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flow
|
|
$
|
105,800
|
|
|
$
|
183,662
|
|
|
|
|
|
|
|
|
|
|
In the foregoing determination of future cash inflows, sales
prices used for oil and natural gas for December 31, 2010
and 2009 were estimated using the average price during the
12-month
period, determined as the unweighted arithmetic average of the
first-day-of-the-month
price for each month in such period. Future costs of developing
and producing the proved oil and reserves reported at the end of
each year shown were based on costs determined at each such
year-end, assuming the continuation of existing economic
conditions.
F-48
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
Changes in the standardized measure of discounted future net
cash flow relating to proved oil and gas reserves for the
periods form inception (July 1, 2009) to
December 31, 2009 and for the year ended December 31,
2010 are as follows:
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Standardized measure of discounted future net cash flow,
beginning of period
|
|
$
|
77,880
|
|
|
$
|
105,800
|
|
Changes in the year resulting from:
|
|
|
|
|
|
|
|
|
Sales, less production costs
|
|
|
(3,772
|
)
|
|
|
(11,212
|
)
|
Revisions of previous quantity estimates
|
|
|
24,394
|
|
|
|
(9,278
|
)
|
Extensions, discoveries and improved recovery
|
|
|
280
|
|
|
|
16,562
|
|
Net change in prices and production costs
|
|
|
(16,860
|
)
|
|
|
44,773
|
|
Net change in income taxes
|
|
|
36,447
|
|
|
|
|
|
Changes in estimated future development costs
|
|
|
(11,081
|
)
|
|
|
(2,170
|
)
|
Previously estimated development costs incurred during the period
|
|
|
2,212
|
|
|
|
9,242
|
|
Purchases of minerals in place
|
|
|
161
|
|
|
|
22,330
|
|
Accretion of discount
|
|
|
11,433
|
|
|
|
10,580
|
|
Timing differences and other
|
|
|
(15,294
|
)
|
|
|
(2,965
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flow, end of
year
|
|
$
|
105,800
|
|
|
$
|
183,662
|
|
|
|
|
|
|
|
|
|
|
During September 2011, our auditors identified mathematical
errors that existed in the calculation of depreciation,
depletion and amortization and impairment of proved oil and gas
properties for all periods prior to 2011. Our auditors also
determined that a clerical error resulted in expensing of
certain geological and geophysical costs by Mid-Con
Energy I, LLC in the six months ended December 31,
2009, that had previously been expensed by the predecessor,
Mid-Con Energy Corporation, during the fiscal year ended
June 30, 2009.
Management has restated the combined financial statements to
correct these errors. The following tables reflect the impact of
the restatement on the predecessors combined balance
sheets at December 31, 2009 and 2010 and the
predecessors combined statements of operations
F-49
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
and cash flow for the periods from inception (July 1,
2009) to December 31, 2009 and for the year ended
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
As Previously
|
|
|
|
|
|
|
Reported
|
|
Adjustments
|
|
As Restated
|
|
|
(in thousands)
|
|
Combined Balance Sheet:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
37,523
|
|
|
$
|
(454
|
)
|
|
$
|
37,069
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(2,677
|
)
|
|
|
(49
|
)
|
|
|
(2,726
|
)
|
Total property and equipment, net
|
|
|
36,725
|
|
|
|
(503
|
)
|
|
|
36,222
|
|
Total assets
|
|
|
40,999
|
|
|
|
(503
|
)
|
|
|
40,496
|
|
Contributed capital
|
|
|
47,083
|
|
|
|
(10
|
)
|
|
|
47,073
|
|
Accumulated deficit
|
|
|
(8,603
|
)
|
|
|
(493
|
)
|
|
|
(9,096
|
)
|
Total members equity
|
|
|
37,282
|
|
|
|
(503
|
)
|
|
|
36,779
|
|
Total liabilities and members equity
|
|
|
40,999
|
|
|
|
(503
|
)
|
|
|
40,496
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
As Previously
|
|
|
|
|
|
|
Reported
|
|
Adjustments
|
|
As Restated
|
|
|
(in thousands)
|
|
Combined Balance Sheet:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
57,873
|
|
|
$
|
(509
|
)
|
|
$
|
57,364
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(8,795
|
)
|
|
|
317
|
|
|
|
(8,478
|
)
|
Total property and equipment, net
|
|
|
51,848
|
|
|
|
(192
|
)
|
|
|
51,656
|
|
Total assets
|
|
|
57,059
|
|
|
|
(192
|
)
|
|
|
56,867
|
|
Contributed capital
|
|
|
52,933
|
|
|
|
(10
|
)
|
|
|
52,923
|
|
Accumulated deficit
|
|
|
(7,836
|
)
|
|
|
(182
|
)
|
|
|
(8,018
|
)
|
Total members equity
|
|
|
43,264
|
|
|
|
(192
|
)
|
|
|
43,072
|
|
Total liabilities and members equity
|
|
|
57,059
|
|
|
|
(192
|
)
|
|
|
56,867
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from Inception (July 1, 2009) to
December 31, 2009
|
|
|
As Previously
|
|
|
|
|
|
|
Reported
|
|
Adjustments
|
|
As Restated
|
|
|
(in thousands)
|
|
Combined Statement of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Geological and geophysical expense
|
|
$
|
979
|
|
|
$
|
(979
|
)
|
|
$
|
|
|
Depreciation, depletion and amortization
|
|
|
2,503
|
|
|
|
49
|
|
|
|
2,552
|
|
Impairment of proved oil and gas properties
|
|
|
7,785
|
|
|
|
1,423
|
|
|
|
9,208
|
|
Total operating costs and expenses
|
|
|
14,729
|
|
|
|
493
|
|
|
|
15,222
|
|
Loss from operations
|
|
|
(8,754
|
)
|
|
|
(493
|
)
|
|
|
(9,247
|
)
|
Net loss
|
|
|
(8,603
|
)
|
|
|
(493
|
)
|
|
|
(9,096
|
)
|
F-50
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
December 31, 2009 and 2010(continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2010
|
|
|
As Previously
|
|
|
|
|
|
|
Reported
|
|
Adjustments
|
|
As Restated
|
|
|
(in thousands)
|
|
Combined Statement of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
$
|
6,217
|
|
|
$
|
(366
|
)
|
|
$
|
5,851
|
|
Impairment of proved oil and gas properties
|
|
|
1,831
|
|
|
|
55
|
|
|
|
1,886
|
|
Total operating costs and expenses
|
|
|
18,028
|
|
|
|
(311
|
)
|
|
|
17,717
|
|
Loss from operations
|
|
|
(554
|
)
|
|
|
311
|
|
|
|
(243
|
)
|
Net income
|
|
|
767
|
|
|
|
311
|
|
|
|
1,078
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from Inception (July 1, 2009) to
December 31, 2009
|
|
|
As Previously
|
|
|
|
|
|
|
Reported
|
|
Adjustments
|
|
As Restated
|
|
|
(in thousands)
|
|
Combined Statement of Cash Flow:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(8,603
|
)
|
|
$
|
(493
|
)
|
|
$
|
(9,096
|
)
|
Depreciation, depletion and amortization
|
|
|
2,503
|
|
|
|
49
|
|
|
|
2,552
|
|
Impairment of proved oil and gas properties
|
|
|
7,785
|
|
|
|
1,423
|
|
|
|
9,208
|
|
Net cash provided by (used in) operating activities
|
|
|
(14
|
)
|
|
|
979
|
|
|
|
965
|
|
Additions to oil and gas properties
|
|
|
(2,660
|
)
|
|
|
(979
|
)
|
|
|
(3,639
|
)
|
Net cash used in investing activities
|
|
|
(4,039
|
)
|
|
|
(979
|
)
|
|
|
(5,018
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2010
|
|
|
As Previously
|
|
|
|
|
|
|
Reported
|
|
Adjustments
|
|
As Restated
|
|
|
(in thousands)
|
|
Combined Statement of Cash Flow:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
767
|
|
|
$
|
311
|
|
|
$
|
1,078
|
|
Depreciation, depletion and amortization
|
|
|
6,217
|
|
|
|
(366
|
)
|
|
|
5,851
|
|
Impairment of proved oil and gas properties
|
|
|
1,831
|
|
|
|
55
|
|
|
|
1,886
|
|
F-51
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors
Mid-Con Energy GP, LLC
We have audited the accompanying consolidated statements of
operations, stockholders equity and cash flow of Mid-Con
Energy Corporation (a Delaware corporation), and subsidiaries
for the years ended June 30, 2008 and 2009. These financial
statements are the responsibility of the Companys
management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. The Company is not required to
have, nor were we engaged to perform an audit of its internal
control over financial reporting. Our audit included
consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Companys internal control over
financial reporting. Accordingly, we express no such opinion. An
audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the results
of operations and cash flow of Mid-Con Energy Corporation and
subsidiaries for the years ended June 30, 2008 and 2009, in
conformity with accounting principles generally accepted in the
United States of America.
As discussed in Note 12, the accompanying financial
statements have been restated to correct misstatements.
Tulsa, Oklahoma
August 12, 2011, except for Note 12, as to which the
date is October 5, 2011
F-52
Mid-Con
Energy Corporation and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
Year Ended June 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
|
(as restated, see Note 12)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
13,667
|
|
|
$
|
10,246
|
|
Natural gas sales
|
|
|
618
|
|
|
|
2,172
|
|
Realized loss on derivatives, net
|
|
|
(804
|
)
|
|
|
(669
|
)
|
Unrealized gain (loss) on derivatives, net
|
|
|
(2,035
|
)
|
|
|
1,679
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
11,446
|
|
|
|
13,428
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
5,005
|
|
|
|
5,369
|
|
Oil and gas production taxes
|
|
|
946
|
|
|
|
631
|
|
Geological and geophysical
|
|
|
1,296
|
|
|
|
507
|
|
Depreciation, depletion and amortization
|
|
|
1,599
|
|
|
|
2,293
|
|
Accretion of discount on asset retirement obligations
|
|
|
56
|
|
|
|
78
|
|
General and administrative
|
|
|
1,871
|
|
|
|
1,767
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
10,773
|
|
|
|
10,645
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
673
|
|
|
|
2,783
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest income and other
|
|
|
115
|
|
|
|
119
|
|
Interest expense
|
|
|
(3
|
)
|
|
|
(93
|
)
|
Other revenue and expense, net
|
|
|
108
|
|
|
|
298
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
220
|
|
|
|
324
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
893
|
|
|
|
3,107
|
|
|
|
|
|
|
|
|
|
|
Income tax (expense) benefit:
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
(625
|
)
|
Deferred
|
|
|
(261
|
)
|
|
|
502
|
|
|
|
|
|
|
|
|
|
|
Total income tax (expense) benefit
|
|
|
(261
|
)
|
|
|
(123
|
)
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
632
|
|
|
$
|
2,984
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-53
Mid-Con
Energy Corporation and Subsidiaries
(as
restated, see Note 12)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Officers,
|
|
|
|
|
|
|
|
|
Retained
|
|
|
|
|
|
|
Series A
|
|
|
|
|
|
|
|
|
Additional
|
|
|
Director
|
|
|
|
|
|
|
|
|
Earnings
|
|
|
Total
|
|
|
|
Preferred Stock
|
|
|
Common Stock
|
|
|
Paid-In
|
|
|
and
|
|
|
Treasury Stock
|
|
|
(Accumulated
|
|
|
Stockholders
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Employees
|
|
|
Shares
|
|
|
Amount
|
|
|
Deficit)
|
|
|
Equity
|
|
|
|
(in thousands)
|
|
|
Balance at June 30, 2007
|
|
|
282
|
|
|
$
|
3
|
|
|
|
344
|
|
|
$
|
3
|
|
|
$
|
28,021
|
|
|
$
|
(394
|
)
|
|
|
|
|
|
$
|
|
|
|
$
|
(445
|
)
|
|
$
|
27,188
|
|
Stock issuance
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
26
|
|
|
|
(25
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Stock repurchase
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
(4
|
)
|
Excess tax expense for restricted stock grants
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
632
|
|
|
|
632
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at June 30, 2008
|
|
|
282
|
|
|
|
3
|
|
|
|
347
|
|
|
|
3
|
|
|
|
28,068
|
|
|
|
(419
|
)
|
|
|
|
|
|
|
(4
|
)
|
|
|
187
|
|
|
|
27,838
|
|
Stock issuance
|
|
|
50
|
|
|
|
|
|
|
|
72
|
|
|
|
1
|
|
|
|
5,165
|
|
|
|
(156
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,010
|
|
Stock repurchase
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
3
|
|
|
|
(38
|
)
|
|
|
|
|
|
|
(19
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,984
|
|
|
|
2,984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at June 30, 2009
|
|
|
332
|
|
|
$
|
3
|
|
|
|
419
|
|
|
$
|
4
|
|
|
$
|
33,233
|
|
|
$
|
(556
|
)
|
|
|
3
|
|
|
$
|
(42
|
)
|
|
$
|
3,171
|
|
|
$
|
35,813
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-54
Mid-Con
Energy Corporation and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended June 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
|
(as restated, see Note 12)
|
|
|
Cash Flow From Operating Activities:
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
632
|
|
|
$
|
2,984
|
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
1,599
|
|
|
|
2,293
|
|
Accretion of discount on asset retirement obligations
|
|
|
56
|
|
|
|
78
|
|
Bad debt expense
|
|
|
159
|
|
|
|
|
|
Unrealized (gain) loss on derivatives, net
|
|
|
2,035
|
|
|
|
(1,679
|
)
|
Gain on sale of assets
|
|
|
|
|
|
|
(1
|
)
|
Deferred income taxes
|
|
|
261
|
|
|
|
(502
|
)
|
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(1,255
|
)
|
|
|
373
|
|
Prepaids and other
|
|
|
(20
|
)
|
|
|
21
|
|
Other assets
|
|
|
(125
|
)
|
|
|
(54
|
)
|
Inventory
|
|
|
|
|
|
|
(299
|
)
|
Accounts payable
|
|
|
555
|
|
|
|
(549
|
)
|
Accrued liabilities
|
|
|
88
|
|
|
|
664
|
|
Revenue payable
|
|
|
82
|
|
|
|
(140
|
)
|
Advance billings and other
|
|
|
154
|
|
|
|
7,978
|
|
Derivative financial instruments
|
|
|
|
|
|
|
(232
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
4,221
|
|
|
|
10,935
|
|
|
|
|
|
|
|
|
|
|
Cash Flow From Investing Activities:
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties
|
|
|
(5,555
|
)
|
|
|
(11,008
|
)
|
Additions to other property and equipment
|
|
|
(235
|
)
|
|
|
(360
|
)
|
Acquisitions of oil and natural gas properties
|
|
|
(1,856
|
)
|
|
|
(1,080
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(7,646
|
)
|
|
|
(12,448
|
)
|
|
|
|
|
|
|
|
|
|
Cash Flow From Financing Activities:
|
|
|
|
|
|
|
|
|
Proceeds from credit facilities
|
|
|
300
|
|
|
|
12,635
|
|
Payments on credit facilities
|
|
|
(150
|
)
|
|
|
(12,785
|
)
|
Purchase of treasury stock
|
|
|
(4
|
)
|
|
|
(19
|
)
|
Proceeds from issuance of common and Series A preferred
stock
|
|
|
1
|
|
|
|
5,010
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
147
|
|
|
|
4,841
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents
|
|
|
(3,278
|
)
|
|
|
3,328
|
|
Beginning Cash and Cash Equivalents
|
|
|
3,427
|
|
|
|
149
|
|
|
|
|
|
|
|
|
|
|
Ending Cash and Cash Equivalents
|
|
$
|
149
|
|
|
$
|
3,477
|
|
|
|
|
|
|
|
|
|
|
Supplemental Cash Flow Information:
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
3
|
|
|
$
|
96
|
|
|
|
|
|
|
|
|
|
|
Non-Cash Investing and Financing Activities:
|
|
|
|
|
|
|
|
|
Accrued capital expendituresoil and gas properties
|
|
$
|
308
|
|
|
$
|
2
|
|
|
|
|
|
|
|
|
|
|
Notes receivable from officers, directors and employees
|
|
$
|
25
|
|
|
$
|
137
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-55
|
|
1.
|
Organization
and Nature of Operations
|
Mid-Con Energy Corporation (collectively, with its subsidiaries,
the Corporation) is a Delaware corporation formed on
July 1, 2004. The Corporations principal business is
the acquisition, development and production of existing oil and
natural gas properties in the Mid-Continent region of the United
States. The Corporation uses secondary oil recovery techniques,
such as waterflooding to increase production from mature fields.
The Corporations wholly owned subsidiaries are RDT
Properties, Inc. (RDT) and ME3 Oilfield Service, LLC
(ME3). RDT is the sole operator of mineral
properties owned by the Corporation and ME3 provides oil field
construction and maintenance services, as well as oil and water
transportation services, to the Corporation and to third parties.
On June 30, 2009, the Corporation and its subsidiaries,
reorganized to form two separate companies, Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC (collectively, the
predecessor). As a result of this reorganization,
the mineral properties were transferred to the predecessor,
along with the related accounts receivable, accounts payable and
cash. RDT and ME3 were transferred to Mid-Con Energy II, LLC.
The reorganization also resulted in issuance of notes receivable
from certain officers, director and shareholders, for the
purchase of ownership units. See further discussion of these
notes receivable in Note 5.
In connection with the closing of the initial public offering of
common units of Mid-Con Energy Partners, LP (the
Partnership), the predecessor will merge with and
into a wholly owned subsidiary of the Partnership in exchange
for a combination of common units issued and cash consideration
paid to the predecessors owners.
|
|
2.
|
Summary
of Significant Accounting Policies
|
Basis of presentation and principles of consolidation
The accompanying consolidated financial statements were derived
from the historical accounting records of the Corporation and
its wholly owned subsidiaries, RDT and ME3, and reflect the
historical results of operations and cash flow for the periods
described herein. All intercompany transactions and account
balances have been eliminated. The accompanying consolidated
financial statements have been prepared in accordance with
accounting principles generally accepted in the United States of
America (GAAP). The Corporation operates oil and
natural gas properties as one business segment: the exploration,
development and production of oil and natural gas. The
Corporations management evaluates performance based on one
business segment as there are not different economic
environments within the operation of the oil and natural gas
properties.
Use of estimates
Preparation of financial statements in conformity with GAAP
requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities, the
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues
and expenses during the reporting periods. Actual results could
differ from these estimates. Depletion of oil and gas properties
is determined using estimates of proved oil and gas reserves.
There are numerous uncertainties inherent in the estimation of
quantities of proved reserves and in the projection of future
rates of production and the timing of development expenditures.
Similarly, evaluations for impairment of proved and unproved oil
and gas properties are subject to numerous uncertainties
including, among others, estimates of future recoverable
reserves and commodity price outlooks. Other significant
estimates include, but are
F-56
Mid-Con
Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 (continued)
not limited to, asset retirement obligations, fair value of
business combinations and fair value of derivative financial
instruments.
Cash and cash equivalents
The Corporation considers all cash on hand, depository accounts
held by banks and money market accounts with an original
maturity of three months or less to be cash equivalents.
Accounts receivable
The Corporation sells oil and natural gas to various customers
and participates with other parties in the drilling, completion
and operation of oil and gas wells. The Corporations oil
and gas sales receivables and joint interest receivables related
to these operations are generally unsecured. Accounts receivable
for joint interest billings are recorded as amounts billed to
customers less an allowance for doubtful accounts. Amounts are
considered past due after 30 days. The Corporation
determines joint interest operations accounts receivable
allowances based on managements assessment of the
creditworthiness of the joint interest owners and the
Corporations ability to realize the receivables through
netting of anticipated future production revenues. The
Corporation had bad debt expense of $0.2 million for the
year ended June 30, 2008 and there were no provisions for
bad debts or write-offs of accounts receivable for the year then
ended June 30, 2009.
Revenue recognition
The Corporation uses the sales method of accounting for crude
oil and natural gas revenues. Under this method, revenues are
recognized based on the Corporations share of actual
proceeds from oil and gas sold to purchasers. Natural gas
revenues would not have been significantly altered for the
period presented had the entitlements method of recognizing
natural gas revenues been utilized. If reserves are not
sufficient to recover natural gas overtake positions, a
liability is recorded. The Corporation had no significant
natural gas imbalances at June 30, 2008 or 2009.
Oil and natural gas properties
The Corporation utilized the successful efforts method of
accounting for its oil and gas properties. Under this method all
costs associated with productive wells and nonproductive
development wells are capitalized, while nonproductive
exploration costs are expensed. Capitalized costs relating to
proved properties were depleted using the
units-of-production
method based on proved reserves on a field basis. The
depreciation of capitalized production equipment was based on
the
units-of-production
method using proved developed reserves on a field basis. The
Corporation had no exploratory wells in progress and no
capitalized exploratory well costs pending determination of
reserves at June 30, 2008 and 2009.
Capitalized costs of individual properties abandoned or retired
are charged to accumulated depletion, depreciation and
amortization. Proceeds from sales of individual properties are
credited to property costs. No gain or loss is recognized until
the entire amortization base (field) is sold or abandoned.
Costs of significant nonproducing properties and wells in the
process of being drilled are excluded from depletion until such
time as the proved reserves are established or impairment is
determined. Costs of significant development projects are
excluded from depreciation until the related project is
completed. The Corporation capitalizes interest, if debt is
outstanding, on expenditures for significant development
projects until such projects are ready for their intended use.
The Corporation did not capitalize any interest for the years
ended June 30, 2008 and 2009.
F-57
Mid-Con
Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 (continued)
The Corporation reviewed its long-lived assets to be held and
used, including proved oil and gas properties accounted for
under the successful efforts method of accounting, whenever
events or circumstances indicated that the carrying value of
those assets may not be recoverable. The impairment provision is
based on the excess of carrying value over fair value. Fair
value is defined as the present value of the estimated future
net revenues from production of total proved and risk-adjusted
probable and possible oil and gas reserves over the economic
life of the reserves, based on the Corporations
expectations of future oil and gas prices and costs. The
Corporation reviews its oil and gas properties by amortization
base (field) or by individual well for those wells not
constituting part of an amortization base. The Corporation did
not recognize any impairments of proved oil and gas properties
for the years ended June 30, 2008 or 2009.
Unproved oil and gas properties are each periodically assessed
for impairment by comparing their costs to their estimated
values on a
project-by-project
basis. The estimated value is affected by the results of
exploration activities, future drilling plans, commodity price
outlooks, planned future sales or expiration of all or a portion
of leases on such projects. If the quantity of potential
reserves determined by such evaluations is not sufficient to
fully recover the cost invested in each project, the Corporation
recognizes an impairment loss at that time. The Corporation did
not have any abandonments expense for the years ended
June 30, 2008 or 2009.
Other property and equipment
Other property and equipment is stated at historical cost and is
comprised of software, vehicles, office equipment, and field
service equipment. Costs incurred for normal repairs and
maintenance are charged to expense as incurred, unless they
extend the useful life of the asset. Depreciation is calculated
using the straight-line method based on useful lives of the
assets ranging from three to seven years and is included in the
accumulated depletion, depreciation and amortization totals.
Depreciation expense related to other property and equipment for
the years ended June 30, 2008 and 2009 totaled
approximately $0.1 million and $0.2 million,
respectively.
Asset retirement obligations
The Corporation has obligations under its lease agreements and
federal regulations to remove equipment and restore land at the
end of oil and natural gas production operations. These asset
retirement obligations (ARO) are primarily
associated with plugging and abandoning wells. Determining the
future restoration and removal requires management to make
estimates and judgments because most of the removal obligations
are many years in the future and contracts and regulations often
have vague descriptions of what constitutes removal. Asset
removal technologies and costs are constantly changing, as are
regulatory, political, environmental, safety and public
relations considerations. The Corporation is required to record
the fair value of a liability for an ARO in the period in which
it is incurred with a corresponding increase in the carrying
amount of the related long-lived asset. The Corporation
typically incurs this liability upon acquiring or drilling a
well. Over time, the liability is accreted each period toward
its future value and the capitalized cost is depleted as a
component of development costs. Upon settlement of the
liability, a gain or loss is recognized to the extent the actual
costs differ from the recorded liability.
Inherent to the present value calculation are numerous
estimates, assumptions and judgments, including the ultimate
settlement amounts, inflation factors, credit adjusted risk-free
rates, timing of settlement and changes in the legal,
regulatory, environmental and political environments. To the
extent future revisions to these assumptions impact the present
value of
F-58
Mid-Con
Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 (continued)
the abandonment liability, management will make corresponding
adjustments to both the ARO and the related oil and natural gas
property asset balance. Increases in the discounted retirement
obligation liability and related oil and natural gas assets
resulting from the passage of time are reflected as additional
accretion and depreciation expense in the consolidated
statements of operations.
Derivatives and hedging
All derivative instruments are recorded on the balance sheet as
either assets or liabilities at fair value. Derivative
instruments that do not meet specific hedge accounting criteria
were adjusted to fair value through net income. Effective
changes in the fair value of derivative instruments that are
accounted for as cash flow hedges are recognized in other
accumulated comprehensive income in stockholders equity
until such time as the hedged items are recognized in net
income. Ineffective portions of a derivative instruments
change in fair value are immediately recognized in net income.
None of the Corporations derivatives outstanding at
June 30, 2008 or 2009 or during the years ended
June 30, 2008 and 2009 were designated as hedges for
financial statement purposes; therefore, the adjustments to fair
value are included in net income. Realized and unrealized gains
and losses on derivatives are shown separately in the statement
of operations and were included in cash flow from operating
activities in the statement of cash flow.
Other revenue and expense, net
The Corporation receives fees for the operation of jointly-owned
oil and gas properties and records such reimbursements as
reductions of other revenue and expense, net. Such fees totaled
$1.1 million and $1.5 million for the years ended
June 30, 2008 and 2009, respectively.
Treasury stock
Treasury stock purchases are recorded at cost. Upon
reissuance, the cost of treasury stock is reduced by the average
price per share of the aggregated treasury shares held. During
the years ended June 30, 2008 and 2009, the Corporation did
not retire any treasury stock.
Income taxes
The Corporation accounts for income taxes in accordance with the
asset and liability method under which deferred tax assets and
liabilities are recognized for the future tax consequences
attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their
respective tax bases. Deferred tax assets and liabilities are
measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are
expected to be recovered or settled. The effect of deferred tax
assets and liabilities of a change in tax rate is recognized in
income in the period that includes the enactment date.
|
|
3.
|
Asset
Retirement Obligations
|
The Corporation records asset retirement obligations as
liabilities at the estimated present value at the related
assets inception, with the offsetting charge to property
costs. Periodic accretion of the discounted estimated liability
is recorded in the statement of operations. The discounted
capitalized cost is amortized to expense through the
depreciation calculation over the life of the assets based on
proved developed reserves.
F-59
Mid-Con
Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 (continued)
The Corporations asset retirement obligations primarily
represent the estimated present value of the amount the
Corporation will incur to plug, abandon and remediate its
producing properties at the end of their production lives, in
accordance with applicable state laws. The Corporation
determined its asset retirement obligation by calculating the
present value of estimated cash flow related to the liability.
The following is a reconciliation of the asset retirement
obligation for the years ended June 30, 2008 and 2009 (in
thousands):
|
|
|
|
|
Asset retirement obligations at, July 1, 2007
|
|
$
|
672
|
|
Liabilities incurred for new wells
|
|
|
48
|
|
Revision in estimates
|
|
|
174
|
|
Accretion expense
|
|
|
56
|
|
|
|
|
|
|
Asset retirement obligations at June 30, 2008
|
|
|
950
|
|
Liabilities incurred for new wells
|
|
|
70
|
|
Revision in estimates
|
|
|
471
|
|
Accretion expense
|
|
|
78
|
|
|
|
|
|
|
Asset retirement obligations at June 30, 2009
|
|
$
|
1,569
|
|
|
|
|
|
|
|
|
4.
|
Derivative
Financial Instruments
|
The Corporation is exposed to commodity price risk and considers
it prudent to periodically reduce the Corporations
exposure to cash flow variability resulting from commodity price
change fluctuations. Accordingly, the Corporation enters into
derivative instruments to manage their exposure to commodity
price fluctuations and fluctuations in location differences
between published index prices and the New York Mercantile
Exchange (NYMEX) futures prices.
Under commodity swap agreements, one party exchanges a stream of
payments over time according to specified terms with another
counterparty. In a typical commodity swap agreement, the
Corporation agrees to pay an adjustable or floating price tied
to an agreed upon index for the oil commodity and in return
receives a fixed price based on notional quantities. A collar is
a combination of a put purchased by a party and a call option
sold by the same party. In a typical collar transaction, if the
floating price based on a market index is below the floor price,
the Corporation receives from the counterparty an amount equal
to this difference multiplied by the specified volume,
effectively a put option. If the floating price exceeds the
floor price and is less than the ceiling price, no payment is
required by either party. If the floating price exceeds the
ceiling price, the Corporation must pay the counterparty an
amount equal to the difference multiplied by the specific
quantity, effectively a call option.
The Corporation elected not to designate any positions as cash
flow hedges for accounting purposes and, accordingly, recorded
the net change in the
mark-to-market
valuation of these derivative contracts in the statement of
operations.
The Corporation entered into a crude oil fixed price swap
contract for the period of January 2008 through December 2008,
with a notional amount of 5,000 barrels per month. The
Corporation received a fixed price of $73.80 per Bbl and paid
the average monthly NYMEX price. The swap was settled monthly
and marked to market at each reporting date and all unrealized
gains and losses were recognized in current earnings.
In May 2009, the Corporation entered into a crude oil fixed
price swap contract for the period of June 2009 through December
2009, with a notional amount of 5,000 barrels per month.
The Corporation receives a fixed price of $58.45 per Bbl and
pays the average monthly NYMEX price.
F-60
Mid-Con
Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 (continued)
The swap is settled monthly, marked to market at each reporting
date, and all unrealized gains and losses are recognized in
current earnings.
The Corporations derivative contracts are secured by an
agreement with one of the Corporations purchasers whereby
the derivative counterparty can seek payment directly from the
Corporations purchaser on the Corporations oil
production under the contract, should the Corporation be in
default of the contract.
A certain officer and stockholder of the Corporation is entitled
to, or responsible for, as applicable, 10% of the receivable or
payable, respectively, on the monthly settlement from or to, as
applicable, the derivative counterparty.
Preferred stock
The Corporation is authorized to issue 332,500 shares of
Series A Preferred Stock, $0.01 par value. As of
June 30, 2008 and 2009, 282,085 shares and 332,500,
respectively, were issued and outstanding. The Series A
Preferred Stock bears a 6.00% dividend payable annually in
arrears. The Corporation has the election to pay the dividend in
whole or in part in cash or in additional shares of
Series A Preferred Stock at a redemption value of $90.00
per share. Upon liquidation, the Series A Preferred Stock
is ranked senior to all other classes of shares. Dividends in
arrears at June 30, 2008 and 2009, were $4.1 million
and $6.3 million, respectively.
Common stock
The Corporation is authorized to issue 450,000 shares of
common stock, $0.01 par value and there were 346,525 and
418,851 shares issued and outstanding at June 30, 2008
and 2009, respectively.
Under the Mid-Con Energy Corporation 2006 Stock Incentive Plan
(the Stock Plan), shares of the Corporations
common stock are available for issuance to key employees and
directors of the Corporation. The Stock Plan permits the
granting of any or all of the following types of awards:
(a) stock options, (b) stock appreciation rights,
(c) restricted stock awards, (d) performance awards
and (e) stock awards and other incentive awards.
The Stock Plan is administered by the Corporations Board
of Directors (the Board). Subject to the terms of
the Stock Plan, the Board has the authority to determine plan
participants, the types and amounts of awards to be granted and
the terms, conditions and provisions of awards. Options granted
pursuant to the Stock Plan may, at the discretion of the Board,
be either incentive stock options or non-qualified stock
options. The exercise price of incentive stock options generally
may not be less than the fair market value of the common stock
on the date of grant and the term of the option may not exceed
10 years. Any stock appreciation rights granted under the
Stock Plan gives the holder the right to receive cash in an
amount equal to the difference between the fair market value of
the share of common stock on the date of exercise and the
exercise price. Non-vested stock under the Stock Plan will
generally consist of shares which may not be disposed of by
participants until certain restrictions established by the Board
lapse. The Board may require a participant to pay a stipulated
purchase price for each share of restricted stock. Restricted
stock rights under the Stock Plan will generally represent the
right to receive shares of common stock when certain
restrictions, established by the Board, lapse.
Through June 30, 2008, certain officers, directors and
employees purchased common stock of the Corporation for $10 per
share, consisting of 25% cash and a full recourse note for the
F-61
Mid-Con
Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 (continued)
remaining 75%. The purchased stock is subject to a restricted
period of four to six years, beginning on the date the
participant began serving as an employee or director of the
Corporation. During the restricted period, the individual may
not sell, transfer, pledge, exchange or otherwise dispose of the
common stock. The common stock vests ratably over the restricted
period. All common stock immediately vests upon a change of
control of the Corporation. If the individuals employment
or service to the Corporation is terminated prior to vesting,
the individual has no further rights to the common stock and the
Corporation has the right to repurchase any or all of the common
stock.
During the year ended June 30, 2008, the Corporation issued
a total of 2,575 shares of common stock to various
employees for cash consideration and purchase notes in the
aggregate principal amount of $25,750 and the Corporation
repurchased 361 shares of its common stock for an aggregate
purchase price of $3,614, none of which was retired during the
year and all of which are held in treasury.
On October 31, 2008, the Corporation completed an offering
of 50,415 units (Subscribed Units) to an
investor at a price of $100.00 per unit for aggregate
consideration of $5.0 million. Each Subscribed Unit
consists of one share of common stock, par value $0.01 per
share, of the Corporation and one share of Series A
Preferred Stock.
During the year ended June 30, 2009, the Corporation issued
a total of 10,797 common shares to various employees for
cash consideration of $27,285 and purchase notes in the
aggregate principal amount of $80,685. The Corporation
repurchased 2,933 shares of its common stock for an
aggregate purchase price of $37,928, none of which was retired
during the year and all of which are held in treasury.
Notes receivable from officers, director and employees
In the aggregate, at June 30, 2008 and 2009, the
Corporation had notes receivable from officers, a director and
employees totaling $0.4 million and $0.6 million,
respectively, including accrued interest. The maturity date of
the notes is defined as the earlier of the date upon which the
Corporation or any successor to the Corporation registers any
class of its stock under Section 12 of the Securities
Exchange Act of 1934 (the Exchange Act); is required
to file periodic reports under Section 15(d) of the
Exchange Act, the date a registration statement filed under the
Securities Act of 1933 is declared effective; or July 28,
2011. The stated annual interest rate on all notes is 6.00%.
Interest is compounded annually. All accrued and unpaid interest
on the notes is due and payable at maturity. All such notes
receivable were originally issued in conjunction with purchases
of the Corporations common stock by the officers,
employees and a director. Performance of the officers and
directors obligations under these notes is secured by
security interests granted by each of the officers and director
to the Corporation in all of the common stock purchased.
Additionally, the Corporation has full recourse against the
assets of the officers and director for collection of amounts
due upon the occurrence of a default that was not remedied.
LLC conversion
As described in Note 1, on June 30, 2009, the
Corporation and its subsidiaries reorganized to form the
predecessor. Upon formation of Mid-Con Energy I, LLC each
holder of Preferred Stock, Common Stock and Restricted Common
Stock of Mid-Con Energy Corporation received an equal number of
Class A Units, Class B units and Class C units,
respectively, in Mid-Con Energy I, LLC.
F-62
Mid-Con
Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 (continued)
The Corporation has a $10 million revolving credit facility
with a financial institution. The borrowing base is
$5 million, re-determined annually based on the
Corporations oil and natural gas reserves. Interest is
payable monthly and charged at LIBOR plus 2.75% or the financial
institutions prime rate. All of the Corporations oil
and natural gas properties are pledged as security under the
agreement. The Corporation did not have any outstanding
borrowings at June 30, 2009, but had $0.2 million in
outstanding borrowings and $25,000 in letters of credit as of
June 30, 2008. The revolving credit facility matures at the
end of each fiscal year ending June 30.
The Corporation and its subsidiaries file consolidated United
States federal and state income tax returns. The tax returns and
the amount of taxable income or loss reflected thereon are
subject to examination by United States federal and state taxing
authorities. An estimated tax payment of $0.6 million was
made for the year ended June 30, 2009. There were no
current or estimated tax payment made for the year ended
June 30, 2008.
The reconciliation between the tax benefit (expense) computed by
multiplying pretax income by the U.S. federal statutory
rate and the reported amounts of income tax benefit (expense)
for the period ended June 30 is as follows:
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(as restated,
|
|
|
|
see Note 12)
|
|
|
U.S. federal statutory income tax rate
|
|
|
34.0
|
%
|
|
|
34.0
|
%
|
State income taxes
|
|
|
4.0
|
%
|
|
|
4.0
|
%
|
Percentage depletion in excess of tax basis
|
|
|
(11.3
|
)%
|
|
|
(32.7
|
)%
|
Non-deductible permanent differences
|
|
|
0.9
|
%
|
|
|
(1.0
|
)%
|
Other
|
|
|
1.6
|
%
|
|
|
(0.3
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
29.2
|
%
|
|
|
4.0
|
%
|
|
|
|
|
|
|
|
|
|
Financial instruments which potentially subject the Corporation
to credit risk consisted principally of cash balances, accounts
receivable and derivative financial instruments. The Corporation
maintains cash and cash equivalents in bank deposit accounts
which, at times, may have exceed the federally insured limits.
The Corporation has not experienced any significant losses from
such investments.
For the year ended June 30, 2008, purchases by a subsidiary
of Sunoco Logistics Partners L.P. (Sunoco
Logistics), Teppco Crude Oil, LLC and High Sierra Crude
Oil and Marketing, LLC accounted for 53%, 14% and 9%,
respectively of the Corporations total sales revenues.
For the year ended June 30, 2009, purchases by Sunoco
Logistics, ScissorTail Energy, LLC and Teppco Crude Oil, LLC
accounted for 69%, 16% and 5% of the Corporations total
sales revenues.
Management believes that the loss of any one purchaser would not
have an adverse effect on the ability of the predecessor to sell
its oil and gas production because management believes market
conditions are such that other purchasers would be willing to
buy from the predecessor
F-63
Mid-Con
Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 (continued)
at market based prices. The predecessor has not experienced any
significant losses due to uncollectible accounts receivable from
the purchasers.
|
|
9.
|
Commitments
and Contingencies
|
In the normal course of business, the Corporation enters into
contracts that contain a variety of representations and
warranties and provide general indemnifications. The
Corporations maximum exposure under these arrangements is
unknown as this would involve future claims that may be made
against the Corporation that have not yet occurred. The
Corporation does not expect to suffer any material losses in
connection with these contracts.
Various federal, state and local laws and regulations covering,
among other things, the release of waste materials into the
environment and state and local taxes affect the
Corporations operations and costs. Management believes the
Corporation is in substantial compliance with applicable
federal, state and local laws, and management expects that the
ultimate resolution of any claims or legal proceedings
instituted against the Corporation will not have a material
effect on its financial position or results of operations.
The Corporation is a party to a non-cancelable operating lease
for office space for its office in Tulsa, Oklahoma through 2012.
The Corporation recognizes expense on a straight-line basis in
equal amounts over the lease term. Rent expense was
approximately $0.2 million for each of the years ended
June 30, 2008 and 2009. Future minimum lease commitments
under this lease at June 30, 2009, are approximately
$0.2 million for fiscal 2010, $0.2 million for fiscal
2011 and $0.1 million for fiscal 2012.
The Corporation had an employment contract with an employee. The
contract provides for an annual bonus determined upon secondary
reserves identified, acquired and developed. The bonus equals
$0.15 per net barrel developed for the Corporation and is paid
as follows: one third upon approval of unitization, one third
upon achieving payout of the project and one third upon
achieving a second payout of the project. The employment
contract guarantees $24,000 annually to the employee to be paid
quarterly.
|
|
10.
|
Defined
Contribution Plan
|
The Corporation maintains a 401(k) contribution plan (the
Plan) for its employees. Employees must be
21 years of age or older and have worked for 90 days
to be eligible to participate. All employees that were employed
prior to adoption of the Plan on December 31, 2006, became
an active member of the Plan as of December 31, 2006.
Employees may contribute 15% of their compensation up to the
annual IRS limitation. The Corporation makes contributions of 3%
of an employees pay and employees are 100% vested at all
times.
For each of the years ended June 30, 2008 and 2009, the
Corporation contributed $0.1 million to the defined
contribution plans.
|
|
11.
|
Supplemental
Oil and Gas Disclosures
|
Costs Incurred in Oil and Gas Property Acquisition,
Exploration and Development Activities
F-64
Mid-Con
Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 (continued)
Costs incurred in the acquisition and development of oil and gas
assets are presented below for the years ended June 30:
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
1,758
|
|
|
$
|
1,080
|
|
Unproved
|
|
|
98
|
|
|
|
|
|
Development
|
|
|
5,555
|
|
|
|
11,570
|
|
Asset retirement obligations
|
|
|
249
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
$
|
7,660
|
|
|
$
|
12,686
|
|
|
|
|
|
|
|
|
|
|
Net Proved Oil and Gas Reserves(Unaudited)
The Corporations proved oil and gas reserves as of
June 30, 2007, 2008 and 2009 were prepared by the
Corporations reservoir engineers. These reserve estimates
have been prepared in compliance with the rules of the United
States Securities and Exchange Commission at those dates. The
Corporation emphasizes that reserve estimates are inherently
imprecise and that estimates of new discoveries are more
imprecise than those of producing oil and natural gas
properties. Accordingly, the estimates are expected to change as
future information becomes available. An analysis of the change
in estimated quantities of oil and gas reserves, all of which
are located within the United States, for the years ended
June 30, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended June 30, 2008
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
MBoe
|
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
4,250
|
|
|
|
228
|
|
|
|
4,288
|
|
Revisions of previous estimates
|
|
|
184
|
|
|
|
(27
|
)
|
|
|
179
|
|
Extensions, discoveries and other additions
|
|
|
997
|
|
|
|
1,650
|
|
|
|
1,272
|
|
Purchases of minerals in place
|
|
|
53
|
|
|
|
7
|
|
|
|
54
|
|
Production
|
|
|
(145
|
)
|
|
|
(86
|
)
|
|
|
(159
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
|
5,339
|
|
|
|
1,772
|
|
|
|
5,634
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
2,108
|
|
|
|
228
|
|
|
|
2,146
|
|
End of year
|
|
|
2,855
|
|
|
|
976
|
|
|
|
3,018
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
2,142
|
|
|
|
|
|
|
|
2,142
|
|
End of year
|
|
|
2,484
|
|
|
|
796
|
|
|
|
2,616
|
|
F-65
Mid-Con
Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended June 30, 2009
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
MBoe
|
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
5,339
|
|
|
|
1,772
|
|
|
|
5,634
|
|
Revisions of previous estimates
|
|
|
(618
|
)
|
|
|
(517
|
)
|
|
|
(704
|
)
|
Extensions, discoveries and other additions
|
|
|
300
|
|
|
|
2
|
|
|
|
301
|
|
Purchases of minerals in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(153
|
)
|
|
|
(341
|
)
|
|
|
(210
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
|
4,868
|
|
|
|
916
|
|
|
|
5,021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
2,855
|
|
|
|
976
|
|
|
|
3,018
|
|
End of year
|
|
|
2,489
|
|
|
|
834
|
|
|
|
2,628
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
2,484
|
|
|
|
796
|
|
|
|
2,616
|
|
End of year
|
|
|
2,379
|
|
|
|
82
|
|
|
|
2,393
|
|
The tables above include changes in estimated quantities of oil
and natural gas reserves shown in MBoe equivalents at a rate of
six Mcf per Boe.
The quantities of proved reserves due to Extensions,
discoveries and other additions in June 2008 were a result
of the development of the Highlands Unit, Decker Unit, drilling
of gas wells in the Paradigm Field in Oklahoma (a unit in our
Other core area), and the addition of proved
undeveloped drilling locations in North Dakota. During the
twelve months ended June 2009, the quantities of proved reserves
due to Extensions, discoveries and other additions
were a result of the development of the Twin Forks Unit, and
drilling development wells that offset the Southeast Hewitt
Unit. For the twelve months ended June 2009, the Revisions
of Previous Estimates were primarily due to significantly
lower oil prices.
Estimates of economically recoverable oil and natural gas
reserves and of future net revenues are based upon a number of
variable factors and assumptions, all of which are to some
degree subjective and may vary considerably from actual results.
Therefore, actual production, revenues, development and
operating expenditures may not occur as estimated. The reserve
data are estimates only, are subject to many uncertainties and
are based on data gained from production histories and on
assumptions as to geologic formations and other matters. Actual
quantities of oil and natural gas may differ materially from the
amounts estimated.
Standardized Measure of Discounted Future Net Cash
Flow(Unaudited)
The estimates of future cash flow and future production and
development costs as of June 30, 2008 and 2009 are based on
year-end sales prices for oil and natural gas. Estimated future
production of proved reserves and estimated future production
and development costs of proved reserves are based on current
costs and economic conditions. Future income tax expenses are
computed using the appropriate year-end statutory tax rates
applied to the future pretax net cash flow from proved oil and
natural gas reserves, less the tax basis of the
Corporations oil and natural gas properties. Prices used
were $140.00 and $69.89 per Bbl of oil and $13.85 and $3.84 per
Mcf of natural gas for June 30, 2008 and 2009,
respectively. These prices were adjusted by lease for quality,
transportation fees, location differentials, marketing bonuses
or deductions or other factors affecting the price received at
the wellhead. All wellhead prices are held flat over the life of
the properties for all reserve categories. The estimated future
net cash flow is then discounted at a rate of 10%.
F-66
Mid-Con
Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 (continued)
The standardized measure of discounted future net cash flow does
not purport to be, nor should it be interpreted to represent,
the fair market value of the proved oil and natural gas reserves
of the Corporation. An estimate of fair value would take into
account, among other things, the recovery of reserves not
presently classified as proved, the value of unproved
properties, and consideration of expected future economic and
operating conditions. The Corporation cautions that the
disclosures shown are based on estimates of proved reserve
quantities and future production schedules which are inherently
imprecise and subject to revision, and the 10% discount rate is
arbitrary. In addition, costs and prices as of the measurement
date are used in the determinations, and no value may be
assigned to probable or possible reserves.
The standardized measure of discounted future net cash flow
relating to proved oil and natural gas reserves is as follows at
June 30:
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
Future cash inflows
|
|
$
|
728,296
|
|
|
$
|
320,413
|
|
Future production costs
|
|
|
(167,642
|
)
|
|
|
(101,045
|
)
|
Future development costs
|
|
|
(17,223
|
)
|
|
|
(13,673
|
)
|
Future income tax expenses
|
|
|
(198,854
|
)
|
|
|
(66,268
|
)
|
|
|
|
|
|
|
|
|
|
Future net cash flow
|
|
|
344,577
|
|
|
|
139,427
|
|
10% discount for estimated timing of cash flow
|
|
|
(155,240
|
)
|
|
|
(61,547
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted cash flow
|
|
$
|
189,337
|
|
|
$
|
77,880
|
|
|
|
|
|
|
|
|
|
|
In the foregoing determination of future cash inflows, sales
prices used for oil and natural gas were adjusted NYMEX prices
at year end. Future costs of developing and producing the proved
gas and oil reserves reported at the end of each year shown were
based on costs determined at each such year end, assuming the
continuation of existing economic conditions.
Changes in the standardized measure of discounted future net
cash flow relating to proved oil and gas reserves are as follows:
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
Standardized measure of discounted future net cash flow,
beginning of year
|
|
$
|
77,526
|
|
|
$
|
189,337
|
|
Changes in the year resulting from:
|
|
|
|
|
|
|
|
|
Sales, less production costs
|
|
|
(8,334
|
)
|
|
|
(6,418
|
)
|
Revisions of previous quantity estimates
|
|
|
10,581
|
|
|
|
(16,928
|
)
|
Extensions, discoveries and improved recovery
|
|
|
51,014
|
|
|
|
3,264
|
|
Net change in prices and production costs
|
|
|
129,894
|
|
|
|
(172,916
|
)
|
Net change in income taxes
|
|
|
(69,207
|
)
|
|
|
72,238
|
|
Changes in estimated future development costs
|
|
|
(6,666
|
)
|
|
|
(2,795
|
)
|
Previously estimated development costs incurred during the period
|
|
|
5,241
|
|
|
|
10,795
|
|
Accretion of discount
|
|
|
11,700
|
|
|
|
29,802
|
|
Timing differences and other
|
|
|
(12,412
|
)
|
|
|
(28,499
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flow, end of
year
|
|
$
|
189,337
|
|
|
$
|
77,880
|
|
|
|
|
|
|
|
|
|
|
F-67
Mid-Con
Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 (continued)
During September 2011, our auditors identified mathematical
errors that existed in the calculation of depreciation,
depletion and amortization and impairment of proved oil and gas
properties for all periods prior to 2011.
Management has restated the consolidated financial statements to
correct these errors. The following tables reflect the impact of
the restatement on the Corporations consolidated
statements of operations and cash flow for the years ended
June 30, 2008 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended June 30, 2008
|
|
|
|
As Previously
|
|
|
|
|
|
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
As Restated
|
|
|
|
(in thousands)
|
|
|
Consolidated Statement of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
$
|
1,786
|
|
|
$
|
(187
|
)
|
|
$
|
1,599
|
|
Total operating costs and expenses
|
|
|
10,960
|
|
|
|
(187
|
)
|
|
|
10,773
|
|
Income from operations
|
|
|
486
|
|
|
|
187
|
|
|
|
673
|
|
Income before income taxes
|
|
|
706
|
|
|
|
187
|
|
|
|
893
|
|
Deferred income tax expense
|
|
|
(194
|
)
|
|
|
(67
|
)
|
|
|
(261
|
)
|
Total income tax expense
|
|
|
(194
|
)
|
|
|
(67
|
)
|
|
|
(261
|
)
|
Net income
|
|
|
512
|
|
|
|
120
|
|
|
|
632
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended June 30, 2009
|
|
|
|
As Previously
|
|
|
|
|
|
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
As Restated
|
|
|
|
(in thousands)
|
|
|
Consolidated Statement of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
$
|
2,802
|
|
|
$
|
(509
|
)
|
|
$
|
2,293
|
|
Total operating costs and expenses
|
|
|
11,154
|
|
|
|
(509
|
)
|
|
|
10,645
|
|
Income from operations
|
|
|
2,274
|
|
|
|
509
|
|
|
|
2,783
|
|
Income before income taxes
|
|
|
2,598
|
|
|
|
509
|
|
|
|
3,107
|
|
Deferred income tax benefit
|
|
|
686
|
|
|
|
(184
|
)
|
|
|
502
|
|
Total income tax (expense) benefit
|
|
|
61
|
|
|
|
(184
|
)
|
|
|
(123
|
)
|
Net income
|
|
|
2,659
|
|
|
|
325
|
|
|
|
2,984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2007
|
|
|
|
As Previously
|
|
|
|
|
|
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
As Restated
|
|
|
|
(in thousands)
|
|
|
Consolidated Statement of Stockholders Equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated deficit
|
|
$
|
(619
|
)
|
|
$
|
174
|
|
|
$
|
(445
|
)
|
Total stockholders equity
|
|
|
27,014
|
|
|
|
174
|
|
|
|
27,188
|
|
F-68
Mid-Con
Energy Corporation and Subsidiaries
Notes to Consolidated Financial Statements
June 30, 2008 and 2009 (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2008
|
|
|
|
As Previously
|
|
|
|
|
|
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
As Restated
|
|
|
|
(in thousands)
|
|
|
Consolidated Statement of Stockholders Equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained earnings (accumulated deficit)
|
|
$
|
(107
|
)
|
|
$
|
294
|
|
|
$
|
187
|
|
Total stockholders equity
|
|
|
27,544
|
|
|
|
294
|
|
|
|
27,838
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009
|
|
|
|
As Previously
|
|
|
|
|
|
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
As Restated
|
|
|
|
(in thousands)
|
|
|
Consolidated Statement of Stockholders Equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained earnings
|
|
$
|
2,552
|
|
|
$
|
619
|
|
|
$
|
3,171
|
|
Total stockholders equity
|
|
|
35,194
|
|
|
|
619
|
|
|
|
35,813
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended June 30, 2008
|
|
|
|
As Previously
|
|
|
|
|
|
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
As Restated
|
|
|
|
(in thousands)
|
|
|
Consolidated Statement of Cash Flow:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
512
|
|
|
$
|
120
|
|
|
$
|
632
|
|
Depreciation, depletion and amortization
|
|
|
1,786
|
|
|
|
(187
|
)
|
|
|
1,599
|
|
Deferred income taxes
|
|
|
194
|
|
|
|
67
|
|
|
|
261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended June 30, 2009
|
|
|
|
As Previously
|
|
|
|
|
|
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
As Restated
|
|
|
|
(in thousands)
|
|
|
Consolidated Statement of Cash Flow:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
2,659
|
|
|
$
|
325
|
|
|
$
|
2,984
|
|
Depreciation, depletion and amortization
|
|
|
2,802
|
|
|
|
(509
|
)
|
|
|
2,293
|
|
Deferred income taxes
|
|
|
(686
|
)
|
|
|
184
|
|
|
|
(502
|
)
|
F-69
APPENDIX-A
FIRST
AMENDED AND RESTATED
AGREEMENT OF LIMITED PARTNERSHIP
OF
MID-CON ENERGY PARTNERS, LP
TABLE OF
CONTENTS
|
|
|
|
|
|
|
ARTICLE I DEFINITIONS
|
|
|
A-1
|
|
Section 1.1
|
|
Definitions
|
|
|
A-1
|
|
Section 1.2
|
|
Construction
|
|
|
A-14
|
|
|
|
|
|
|
ARTICLE II ORGANIZATION
|
|
|
A-14
|
|
Section 2.1
|
|
Formation
|
|
|
A-14
|
|
Section 2.2
|
|
Name
|
|
|
A-14
|
|
Section 2.3
|
|
Registered Office; Registered Agent; Principal Office; Other
Offices
|
|
|
A-14
|
|
Section 2.4
|
|
Purpose and Business
|
|
|
A-15
|
|
Section 2.5
|
|
Powers
|
|
|
A-15
|
|
Section 2.6
|
|
Term
|
|
|
A-15
|
|
Section 2.7
|
|
Title to Partnership Assets
|
|
|
A-15
|
|
|
|
|
|
|
ARTICLE III RIGHTS
OF LIMITED PARTNERS
|
|
|
A-16
|
|
Section 3.1
|
|
Limitation of Liability
|
|
|
A-16
|
|
Section 3.2
|
|
Management of Business
|
|
|
A-16
|
|
Section 3.3
|
|
Outside Activities of the Limited Partners
|
|
|
A-16
|
|
Section 3.4
|
|
Rights of Limited Partners
|
|
|
A-16
|
|
|
|
|
|
|
ARTICLE IV
CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS;
REDEMPTION OF PARTNERSHIP INTERESTS
|
|
|
A-17
|
|
Section 4.1
|
|
Certificates
|
|
|
A-17
|
|
Section 4.2
|
|
Mutilated, Destroyed, Lost or Stolen Certificates
|
|
|
A-17
|
|
Section 4.3
|
|
Record Holders
|
|
|
A-18
|
|
Section 4.4
|
|
Transfer Generally
|
|
|
A-18
|
|
Section 4.5
|
|
Registration and Transfer of Limited Partner Interests
|
|
|
A-19
|
|
Section 4.6
|
|
Transfer of the General Partners General Partner Interest
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A-19
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Section 4.7
|
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Restrictions on Transfers
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A-20
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Section 4.8
|
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Eligibility Certificates; Ineligible Holders
|
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A-21
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Section 4.9
|
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Redemption of Partnership Interests of Ineligible Holders
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A-22
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|
|
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ARTICLE V CAPITAL
CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS
|
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A-23
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Section 5.1
|
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Organizational Contributions
|
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A-23
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Section 5.2
|
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Contributions by the General Partner and its Affiliates
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A-23
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Section 5.3
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Contributions by Underwriters
|
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A-23
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Section 5.4
|
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Interest and Withdrawal of Capital Contributions
|
|
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A-24
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Section 5.5
|
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Capital Accounts
|
|
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A-24
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Section 5.6
|
|
Issuances of Additional Partnership Interests
|
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A-26
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Section 5.7
|
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Limited Preemptive Right
|
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A-27
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Section 5.8
|
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Splits and Combinations
|
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A-27
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Section 5.9
|
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Fully Paid and Non-Assessable Nature of Limited Partner Interests
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A-28
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|
|
|
|
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ARTICLE VI
ALLOCATIONS AND DISTRIBUTIONS
|
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A-28
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Section 6.1
|
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Allocations for Capital Account Purposes
|
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A-28
|
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Section 6.2
|
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Allocations for Tax Purposes
|
|
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A-32
|
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Section 6.3
|
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Requirement of Distributions; Distributions to Record Holders
|
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A-33
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A-i
|
|
|
|
|
|
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ARTICLE VII
MANAGEMENT AND OPERATION OF BUSINESS
|
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A-34
|
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Section 7.1
|
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Management
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A-34
|
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Section 7.2
|
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Certificate of Limited Partnership
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A-36
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Section 7.3
|
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Restrictions on the General Partners Authority
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A-36
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Section 7.4
|
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Reimbursement of the General Partner
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A-36
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Section 7.5
|
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Outside Activities
|
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A-37
|
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Section 7.6
|
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Loans from the General Partner; Loans or Contributions from the
Partnership or Group Members
|
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A-38
|
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Section 7.7
|
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Indemnification
|
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A-39
|
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Section 7.8
|
|
Liability of Indemnitees
|
|
|
A-40
|
|
Section 7.9
|
|
Resolution of Conflicts of Interest; Standards of Conduct and
Modification of Duties
|
|
|
A-41
|
|
Section 7.10
|
|
Other Matters Concerning the General Partner
|
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|
A-43
|
|
Section 7.11
|
|
Purchase or Sale of Partnership Interests
|
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|
A-43
|
|
Section 7.12
|
|
Registration Rights of the General Partner and its Affiliates
|
|
|
A-44
|
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Section 7.13
|
|
Reliance by Third Parties
|
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A-46
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|
|
|
|
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ARTICLE VIII BOOKS,
RECORDS, ACCOUNTING AND REPORTS
|
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|
A-47
|
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Section 8.1
|
|
Records and Accounting
|
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A-47
|
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Section 8.2
|
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Fiscal Year
|
|
|
A-47
|
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Section 8.3
|
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Reports
|
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A-47
|
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|
|
|
|
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ARTICLE IX TAX
MATTERS
|
|
|
A-48
|
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Section 9.1
|
|
Tax Returns and Information
|
|
|
A-48
|
|
Section 9.2
|
|
Tax Elections
|
|
|
A-48
|
|
Section 9.3
|
|
Tax Controversies
|
|
|
A-48
|
|
Section 9.4
|
|
Withholding; Tax Payments
|
|
|
A-48
|
|
|
|
|
|
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ARTICLE X ADMISSION
OF PARTNERS
|
|
|
A-49
|
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Section 10.1
|
|
Admission of Limited Partners
|
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A-49
|
|
Section 10.2
|
|
Admission of Successor or Additional General Partner
|
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|
A-49
|
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Section 10.3
|
|
Amendment of Agreement and Certificate of Limited Partnership
|
|
|
A-50
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|
|
|
|
|
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ARTICLE XI
WITHDRAWAL OR REMOVAL OF PARTNERS
|
|
|
A-50
|
|
Section 11.1
|
|
Withdrawal of the General Partner
|
|
|
A-50
|
|
Section 11.2
|
|
Removal of the General Partner
|
|
|
A-51
|
|
Section 11.3
|
|
Interest of Departing General Partner and Successor General
Partner
|
|
|
A-52
|
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Section 11.4
|
|
Withdrawal of Limited Partners
|
|
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A-53
|
|
|
|
|
|
|
ARTICLE XII
DISSOLUTION AND LIQUIDATION
|
|
|
A-53
|
|
Section 12.1
|
|
Dissolution
|
|
|
A-53
|
|
Section 12.2
|
|
Continuation of the Business of the Partnership After Dissolution
|
|
|
A-54
|
|
Section 12.3
|
|
Liquidator
|
|
|
A-54
|
|
Section 12.4
|
|
Liquidation
|
|
|
A-55
|
|
Section 12.5
|
|
Cancellation of Certificate of Limited Partnership
|
|
|
A-55
|
|
Section 12.6
|
|
Return of Contributions
|
|
|
A-55
|
|
Section 12.7
|
|
Waiver of Partition
|
|
|
A-55
|
|
Section 12.8
|
|
Capital Account Restoration
|
|
|
A-56
|
|
A-ii
|
|
|
|
|
|
|
ARTICLE XIII
AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE
|
|
|
A-56
|
|
Section 13.1
|
|
Amendments to be Adopted Solely by the General Partner
|
|
|
A-56
|
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Section 13.2
|
|
Amendment Procedures
|
|
|
A-57
|
|
Section 13.3
|
|
Amendment Requirements
|
|
|
A-58
|
|
Section 13.4
|
|
Special Meetings
|
|
|
A-58
|
|
Section 13.5
|
|
Notice of a Meeting
|
|
|
A-59
|
|
Section 13.6
|
|
Record Date
|
|
|
A-59
|
|
Section 13.7
|
|
Adjournment
|
|
|
A-59
|
|
Section 13.8
|
|
Waiver of Notice; Approval of Meeting
|
|
|
A-59
|
|
Section 13.9
|
|
Quorum and Voting
|
|
|
A-60
|
|
Section 13.10
|
|
Conduct of a Meeting
|
|
|
A-60
|
|
Section 13.11
|
|
Action Without a Meeting
|
|
|
A-60
|
|
Section 13.12
|
|
Right to Vote and Related Matters
|
|
|
A-61
|
|
|
|
|
|
|
ARTICLE XIV MERGER,
CONSOLIDATION OR CONVERSION
|
|
|
A-61
|
|
Section 14.1
|
|
Authority
|
|
|
A-61
|
|
Section 14.2
|
|
Procedure for Merger, Consolidation or Conversion
|
|
|
A-62
|
|
Section 14.3
|
|
Approval by Limited Partners
|
|
|
A-63
|
|
Section 14.4
|
|
Certificate of Merger
|
|
|
A-64
|
|
Section 14.5
|
|
Effect of Merger, Consolidation or Conversion
|
|
|
A-64
|
|
|
|
|
|
|
ARTICLE XV RIGHT TO
ACQUIRE LIMITED PARTNER INTERESTS
|
|
|
A-65
|
|
Section 15.1
|
|
Right to Acquire Limited Partner Interests
|
|
|
A-65
|
|
|
|
|
|
|
ARTICLE XVI GENERAL
PROVISIONS
|
|
|
A-66
|
|
Section 16.1
|
|
Addresses and Notices; Written Communications
|
|
|
A-66
|
|
Section 16.2
|
|
Further Action
|
|
|
A-67
|
|
Section 16.3
|
|
Binding Effect
|
|
|
A-67
|
|
Section 16.4
|
|
Integration
|
|
|
A-67
|
|
Section 16.5
|
|
Creditors
|
|
|
A-67
|
|
Section 16.6
|
|
Waiver
|
|
|
A-67
|
|
Section 16.7
|
|
Third-Party Beneficiaries
|
|
|
A-68
|
|
Section 16.8
|
|
Counterparts
|
|
|
A-68
|
|
Section 16.9
|
|
Applicable Law; Forum, Venue and Jurisdiction
|
|
|
A-68
|
|
Section 16.10
|
|
Invalidity of Provisions
|
|
|
A-69
|
|
Section 16.11
|
|
Consent of Partners
|
|
|
A-69
|
|
Section 16.12
|
|
Facsimile Signatures
|
|
|
A-69
|
|
A-iii
FIRST
AMENDED AND RESTATED AGREEMENT OF LIMITED
PARTNERSHIP OF MID-CON ENERGY PARTNERS, LP
THIS FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP
OF MID-CON ENERGY PARTNERS, LP, dated as
of ,
2011, is entered into by and between MID-CON ENERGY GP, LLC, a
Delaware limited liability company, as the General Partner, and
Mr. S. Craig George, as the Organizational Limited Partner,
together with any other Persons who become Partners in the
Partnership or parties hereto as provided herein. In
consideration of the covenants, conditions and agreements
contained herein, the parties hereto hereby agree as follows:
ARTICLE I
DEFINITIONS
Section 1.1 Definitions. The
following definitions shall be for all purposes, unless
otherwise clearly indicated to the contrary, applied to the
terms used in this Agreement.
Adjusted Capital Account means the Capital
Account maintained for each Partner as of the end of each
taxable period of the Partnership, (a) increased by any
amounts that such Partner is obligated to restore under the
standards set by Treasury
Regulation Section 1.704-1(b)(2)(ii)(c)
(or is deemed obligated to restore under Treasury
Regulation Sections 1.704-2(g)
and 1.704-2(i)(5)) and (b) decreased by (i) the amount
of all deductions in respect of depletion that, as of the end of
such taxable period, are reasonably expected to be made to such
Partners Capital Account in respect of the oil and gas
properties of the Partnership Group, (ii) the amount of all
losses and deductions that, as of the end of such taxable
period, are reasonably expected to be allocated to such Partner
in subsequent taxable periods under Sections 704(e)(2) and
706(d) of the Code and Treasury
Regulation Section 1.751-1(b)(2)(ii),
and (iii) the amount of all distributions that, as of the
end of such taxable period, are reasonably expected to be made
to such Partner in subsequent taxable periods in accordance with
the terms of this Agreement or otherwise to the extent they
exceed offsetting increases to such Partners Capital
Account that are reasonably expected to occur during (or prior
to) the taxable period in which such distributions are
reasonably expected to be made (other than increases as a result
of a minimum gain chargeback pursuant to Section 6.1(d)(i)
or 6.1(d)(ii)). The foregoing definition of Adjusted Capital
Account is intended to comply with the provisions of Treasury
Regulation Section 1.704-1(b)(2)(ii)(d)
and shall be interpreted consistently therewith. The
Adjusted Capital Account of a Partner in respect of
any Partnership Interest shall be the amount that such Adjusted
Capital Account would be if such Partnership Interest were the
only interest in the Partnership held by such Partner from and
after the date on which such Partnership Interest was first
issued.
Adjusted Property means any property the
Carrying Value of which has been adjusted pursuant to
Section 5.5(d)(i) or 5.5(d)(ii).
Affiliate means, with respect to any Person,
any other Person that directly or indirectly through one or more
intermediaries controls, is controlled by or is under common
control with, the Person in question.
Agreed Allocation means any allocation, other
than a Required Allocation, of an item of income, gain, loss or
deduction pursuant to the provisions of Section 6.1,
including a Curative Allocation (if appropriate to the context
in which the term Agreed Allocation is used).
Agreed Value of any Contributed Property
means the fair market value of such property at the time of
contribution and in the case of an Adjusted Property, the fair
market value of such Adjusted Property on the date of the
revaluation event as described in Section 5.5(d), in both
cases as determined by the General Partner.
A-1
Agreement means this First Amended and
Restated Agreement of Limited Partnership of Mid-Con Energy
Partners, LP, as it may be amended, supplemented or restated
from time to time.
Associate means, when used to indicate a
relationship with any Person, (a) any corporation or
organization of which such Person is a director, officer,
manager, general partner or managing member or is, directly or
indirectly, the owner of 20% or more of any class of voting
stock or other voting interest; (b) any trust or other
estate in which such Person has at least a 20% beneficial
interest or as to which such Person serves as trustee or in a
similar fiduciary capacity; and (c) any relative or spouse
of such Person, or any relative of such spouse, who has the same
principal residence as such Person.
Available Cash means, with respect to any
Quarter ending prior to the Liquidation Date:
(a) the sum of (i) all cash and cash equivalents of
the Partnership Group (or the Partnerships proportionate
share of cash and cash equivalents in the case of Subsidiaries
that are not wholly owned) on hand at the end of such Quarter
and, (ii) if the General Partner so determines, all or a
portion of the cash and cash equivalents on hand on the date of
determination of Available Cash for such Quarter, less
(b) the amount of any cash reserves (or the
Partnerships proportionate share of cash reserves in the
case of Subsidiaries that are not wholly owned) established by
the General Partner to (i) provide for the proper conduct
of the business of the Partnership Group (including reserves for
future capital expenditures, working capital and operating
expenses) subsequent to such Quarter, (ii) comply with
applicable law or any loan agreement, security agreement,
mortgage, debt instrument or other agreement or obligation to
which any Group Member is a party or by which it is bound or its
assets are subject or (iii) provide funds for distributions
under Section 6.3 in respect of any one or more of the next
four Quarters;
provided, however, that disbursements made by a Group
Member or cash reserves established, increased or reduced after
the end of such Quarter but on or before the date of
determination of Available Cash with respect to such Quarter
shall be deemed to have been made, established, increased or
reduced, for purposes of determining Available Cash, within such
Quarter if the General Partner so determines.
Notwithstanding the foregoing, Available Cash
with respect to the Quarter in which the Liquidation Date occurs
and any subsequent Quarter shall equal zero.
Board of Directors means the board of
directors, board of managers or similar governing body, as
applicable, of the General Partner or, if the General Partner is
a limited partnership, the board of directors, board of managers
or similar governing body of the general partner of the General
Partner.
Book-Tax Disparity means, with respect to any
item of Contributed Property or Adjusted Property, as of the
date of any determination, the difference between the Carrying
Value of such Contributed Property or Adjusted Property and the
adjusted basis thereof for federal income tax purposes as of
such date. A Partners share of the Partnerships
Book-Tax Disparities in all of its Contributed Property and
Adjusted Property will be reflected by the difference between
such Partners Capital Account balance as maintained
pursuant to Section 5.5 and the hypothetical balance of
such Partners Capital Account computed as if it had been
maintained strictly in accordance with federal income tax
accounting principles.
Business Day means Monday through Friday of
each week, except that a legal holiday recognized as such by the
government of the United States of America or the State of Texas
shall not be regarded as a Business Day.
Capital Account means the capital account
maintained for a Partner pursuant to Section 5.5. The
Capital Account of a Partner in respect of any
Partnership Interest shall be
A-2
the amount that such Capital Account would be if such
Partnership Interest were the only interest in the Partnership
held by such Partner from and after the date on which such
Partnership Interest was first issued.
Capital Contribution means any cash, cash
equivalents or the Net Agreed Value of Contributed Property that
a Partner contributes to the Partnership or that is contributed
or deemed contributed to the Partnership on behalf of a Partner
(including, in the case of an underwritten offering of Units,
the amount of any underwriting discounts or commissions).
Carrying Value means (a) with respect to
a Contributed Property or Adjusted Property, the Agreed Value of
such property reduced (but not below zero) by all depreciation,
Simulated Depletion, amortization and cost recovery deductions
charged to the Partners Capital Accounts in respect of
such property and (b) with respect to any other Partnership
property, the adjusted basis of such property for federal income
tax purposes, all as of the time of determination;
provided, however, that the Carrying Value of any
property shall be adjusted from time to time in accordance with
Section 5.5(d) and to reflect changes, additions or other
adjustments to the Carrying Value for dispositions and
acquisitions of Partnership properties, as deemed appropriate by
the General Partner.
Cause means a court of competent jurisdiction
has entered a final, non-appealable judgment finding the General
Partner liable for actual fraud or willful misconduct in its
capacity as a general partner of the Partnership.
Certificate means a certificate in such form
(including global form if permitted by applicable rules and
regulations) as may be adopted by the General Partner, issued by
the Partnership evidencing ownership of one or more Partnership
Interests. The initial form of certificate approved by the
General Partner for Common Units is attached as Exhibit A
to this Agreement. Any modification to or replacement of such
form of Certificate adopted by the General Partner shall not
constitute an amendment to this Agreement.
Certificate of Limited Partnership means the
Certificate of Limited Partnership of the Partnership filed with
the Secretary of State of the State of Delaware as referenced in
Section 7.2, as such Certificate of Limited Partnership may
be amended, supplemented or restated from time to time.
Citizenship Certification means a properly
completed certificate in such form as may be specified by the
General Partner by which a Limited Partner certifies that he
(and if he is a nominee holding for the account of another
Person, that to the best of his knowledge such other Person) is
an Eligible Citizen Holder.
claim (as used in Section 7.12(c)) is
defined in Section 7.12(c).
class or classes means the
classes of Units into which Partnership Interests may be
classified or divided from time to time by the General Partner
in its sole discretion pursuant to the provisions of this
Agreement. As of the date of this Agreement, the only class is
the Common Units. Subclasses within a class shall not be
separate classes for purposes of this Agreement. For all
purposes hereunder and under the Delaware Act, only such classes
expressly established under this Agreement, including by the
General Partner in accordance with this Agreement, shall be
deemed to be classes of Partnership Interests or Limited Partner
Interests in the Partnership.
Closing Date means the closing date of the
sale of the Firm Units (as such term is defined in the
Underwriting Agreement) in the Initial Public Offering.
Closing Price means, in respect of any class
of Limited Partner Interests, as of the date of determination,
the last sale price on such day, regular way, or in case no such
sale takes place on such day, the average of the closing bid and
asked prices on such day, regular way, in either case as
reported in the principal consolidated transaction reporting
system with respect to securities
A-3
listed or admitted to trading on the principal National
Securities Exchange on which the respective Limited Partner
Interests are listed or admitted to trading or, if such Limited
Partner Interests are not listed or admitted to trading on any
National Securities Exchange, the last quoted price on such day
or, if not so quoted, the average of the high bid and low asked
prices on such day in the
over-the-counter
market, as reported by the primary reporting system then in use
in relation to such Limited Partner Interests of such class, or,
if on any such day such Limited Partner Interests of such class
are not quoted by any such organization, the average of the
closing bid and asked prices on such day as furnished by a
professional market maker making a market in such Limited
Partner Interests of such class selected by the General Partner,
or if on any such day no market maker is making a market in such
Limited Partner Interests of such class, the fair value of such
Limited Partner Interests on such day as determined by the
General Partner.
Code means the Internal Revenue Code of 1986,
as amended and in effect from time to time. Any reference herein
to a specific section or sections of the Code shall be deemed to
include a reference to any corresponding provision of any
successor law.
Combined Interest is defined in
Section 11.3(a).
Commission means the United States Securities
and Exchange Commission or any successor agency having
jurisdiction under the Securities Act.
Common Unit means a Partnership Interest
representing a fractional part of the Partnership Interests of
all Limited Partners and having the rights and obligations
specified with respect to a Common Unit in this Agreement.
Conflicts Committee means a committee of the
Board of Directors composed entirely of two or more directors
who (a) are not (i) officers or employees of the
General Partner, (ii) officers or employees of any
Affiliate of the General Partner or directors of any Affiliate
of the General Partner (other than a Group Member) or
(iii) holders of any ownership interest in the General
Partner or any of its Affiliates, including any Group Member,
other than Common Units or securities exercisable, convertible
into or exchangeable for Common Units (including awards made to
such director under any incentive plan for the General Partner
or the Partnership) and (b) also meet the independence
standards required of directors who serve on an audit committee
of a board of directors established by the Securities Exchange
Act and the rules and regulations of the Commission thereunder
and by the National Securities Exchange on which any class of
Partnership Interests is listed or admitted to trading.
Contributed Property means each property, in
such form as may be permitted by the Delaware Act, but excluding
cash, contributed to the Partnership. Once the Carrying Value of
a Contributed Property is adjusted pursuant to
Section 5.5(d), such property shall no longer constitute a
Contributed Property, but shall be deemed an Adjusted Property.
Contributing Parties means the Founders,
Yorktown Funds and the Minority Members, collectively.
Contribution and Merger Agreement means that
certain Contribution, Conveyance, Assumption and Merger
Agreement, dated as
of ,
2011, among the General Partner, the Partnership, the Operating
Company, Mid-Con I, Mid-Con II and the Founders,
together with the additional conveyance documents and
instruments contemplated or referenced thereunder, as such may
be amended, supplemented or restated from time to time.
control means the possession, direct or
indirect, of the power to direct or cause the direction of the
management and policies of a Person, whether through ownership
of voting securities, by contract or otherwise.
Curative Allocation means any allocation of
an item of income, gain, deduction, loss or credit pursuant to
the provisions of Section 6.1(d)(ix).
A-4
Current Market Price means, in respect of any
class of Limited Partner Interests, as of the date of
determination, the average of the daily Closing Prices per
Limited Partner Interest of such class for the 20 consecutive
Trading Days immediately prior to such date.
Deferred Issuance and Distribution means both
(a) the issuance by the Partnership to the Contributing
Parties of a number of additional Common Units that is equal to
the excess, if any, of (x)
[ ]
minus (y) the aggregate number, if any, of Common Units
actually purchased by and issued to the Underwriters pursuant to
the Over-Allotment Option on the Option Closing Date(s) and
(b) the distribution by the Partnership of cash to the
Contributing Parties in an amount equal to the aggregate amount
of cash, if any, contributed by the Underwriters to the
Partnership on or in connection with any Option Closing Date
with respect to Common Units issued by the Partnership upon the
applicable exercise of the Over-Allotment Option as described in
Section 5.3(b), if any, in each case, pursuant to the
Contribution and Merger Agreement.
Delaware Act means the Delaware Revised
Uniform Limited Partnership Act, 6 Del. C.
Section 17-101,
et. seq., as amended, supplemented or restated from time to
time, and any successor to such statute.
Departing General Partner means a former
General Partner from and after the effective date of any
withdrawal or removal of such former General Partner pursuant to
Section 11.1 or Section 11.2.
Economic Risk of Loss has the meaning set
forth in Treasury
Regulation Section 1.752-2(a).
Eligibility Certification means a Citizenship
Certification.
Eligible Citizen Holder means (A) (i) a
citizen of the United States; (ii) a corporation organized
under the laws of the United States or of any state thereof;
(iii) a public body of the United States, including a
municipality of the United States; or (iv) an association
of United States citizens, such as a partnership or limited
liability company, organized under the laws of the United States
or of any state thereof, but only if such association does not
have any direct or indirect foreign ownership, other than
foreign ownership of stock in a parent corporation organized
under the laws of the United States or of any state thereof, and
(B) a Limited Partner whose nationality, citizenship or
other related status would not, in the determination of the
General Partner, create a substantial risk of cancellation or
forfeiture of any property in which a Group Member has an
interest.
Eligible Holder means an Eligible Citizen
Holder.
Event of Withdrawal is defined in
Section 11.1(a).
Excess Distribution is defined in
Section 6.1(d)(x).
Excess Distribution Unit is defined in
Section 6.1(d)(x).
Founders means Messrs. Charles R.
Olmstead, S. Craig George and Jeffrey R. Olmstead, collectively.
General Partner means Mid-Con Energy GP, LLC,
a Delaware limited liability company, and its successors and
permitted assigns that are admitted to the Partnership as
general partner of the Partnership, in its capacity as general
partner of the Partnership (except as the context otherwise
requires).
General Partner Interest means the ownership
interest of the General Partner in the Partnership (in its
capacity as a general partner without reference to any Limited
Partner Interest held by it), which is evidenced in part by
Notional General Partner Units, and includes any and all rights,
powers and benefits to which the General Partner is entitled as
provided in this Agreement, together with all obligations of the
General Partner to comply with the terms and provisions of this
Agreement.
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Gross Liability Value means, with respect to
any Liability of the Partnership described in Treasury
Regulation Section 1.752-7(b)(3)(i),
the amount of cash that a willing assignor would pay to a
willing assignee to assume such Liability in an
arms-length transaction.
Group means a Person that with or through any
of its Affiliates or Associates has any contract, arrangement,
understanding or relationship for the purpose of acquiring,
holding, voting (except voting pursuant to a revocable proxy or
consent given to such Person in response to a proxy or consent
solicitation made to 10 or more Persons), exercising investment
power or disposing of any Partnership Interests with any other
Person that beneficially owns, or whose Affiliates or Associates
beneficially own, directly or indirectly, Partnership Interests.
Group Member means a member of the
Partnership Group.
Group Member Agreement means the partnership
agreement of any Group Member, other than the Partnership, that
is a limited or general partnership, the limited liability
company agreement of any Group Member that is a limited
liability company, the certificate of incorporation and bylaws
or similar organizational documents of any Group Member that is
a corporation, the joint venture agreement or similar governing
document of any Group Member that is a joint venture and the
governing or organizational or similar documents of any other
Group Member that is a Person other than a limited or general
partnership, limited liability company, corporation or joint
venture, as such may be amended, supplemented or restated from
time to time.
Holder as used in Section 7.12, is
defined in Section 7.12(a).
Indemnified Persons is defined in
Section 7.12(c).
Indemnitee means (a) any General
Partner, (b) any Departing General Partner, (c) any
Person who is or was an Affiliate of the General Partner or any
Departing General Partner, (d) any Person who is or was a
manager, managing member, general partner, director, officer,
employee, agent, fiduciary or trustee of any Group Member, a
General Partner, any Departing General Partner or any Affiliate
of a Group Member, a General Partner or a Departing General
Partner, (e) any Person who is or was serving at the
request of a General Partner, any Departing General Partner or
any Affiliate of a Group Member, a General Partner or a
Departing General Partner as an officer, director, manager,
managing member, general partner, employee, agent, fiduciary or
trustee of another Person owing a fiduciary duty to any Group
Member; provided, however, that a Person shall not
be an Indemnitee by reason of providing, on a
fee-for-services
basis, trustee, fiduciary or custodial services, (f) any
Person who controls a General Partner or Departing General
Partner and (g) any Person the General Partner in its sole
discretion designates as an Indemnitee for purposes
of this Agreement.
Ineligible Citizen Holder means a Person whom
the General Partner has determined does not constitute an
Eligible Citizen Holder and as to whose Partnership Interest the
General Partner has become the substitute Limited Partner,
pursuant to Section 4.8(a).
Initial Limited Partners means the Founders,
the Yorktown Funds, the Minority Members, in each case, with
respect to the Common Units received pursuant to
Section 5.3 and upon being admitted to the Partnership in
accordance with Section 10.1.
Initial Public Offering means the initial
public offering of Common Units by the Partnership, as described
in the Registration Statement, including any Common Units issued
pursuant to the exercise of the Over-Allotment Option.
Liability means any liability or obligation
of any nature, whether accrued, contingent or otherwise.
Limited Partner means, unless the context
otherwise requires, the Organizational Limited Partner prior to
its withdrawal from the Partnership, each Initial Limited
Partner, each additional Person that becomes a Limited Partner
pursuant to the terms of this Agreement and
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any Departing General Partner upon the change of its status
from General Partner to Limited Partner pursuant to
Section 11.3, in each case, in such Persons capacity
as a limited partner of the Partnership. For purposes of the
Delaware Act, the Limited Partners shall constitute a single
class or group of limited partners.
Limited Partner Interest means the ownership
interest of a Limited Partner in the Partnership, which may be
evidenced by Common Units or other Partnership Interests or a
combination thereof or interest therein, and includes any and
all benefits to which such Limited Partner is entitled as
provided in this Agreement, together with all obligations of
such Limited Partner to comply with the terms and provisions of
this Agreement. For purposes of this Agreement, the Limited
Partner Interests shall constitute a single class or group of
interests unless any Limited Partner Interests are expressly
designated in writing as a separate class or group by the
General Partner in its sole discretion.
Liquidation Date means (a) in the case
of an event giving rise to the dissolution of the Partnership of
the type described in clauses (a) and (b) of the first
sentence of Section 12.2, the date on which the applicable
time period during which the holders of Outstanding Units have
the right to elect to continue the business of the Partnership
and appoint a successor General Partner has expired without such
an election and appointment being made, and (b) in the case
of any other event giving rise to the dissolution of the
Partnership, the date on which such event occurs.
Liquidator means one or more Persons selected
pursuant to Section 12.3 to perform the functions described
in Section 12.4 as liquidating trustee of the Partnership
within the meaning of the Delaware Act.
Merger Agreement is defined in
Section 14.1.
Mid-Con I means Mid-Con Energy I, LLC, a
Delaware limited liability company, and any successors thereto.
Mid-Con II means Mid-Con Energy II, LLC, a
Delaware limited liability company, and any successors thereto.
Minority Members means the individuals and
entities, other than the Founders and the Yorktown Funds, who
hold limited liability company interests in Mid-Con I
and/or
Mid-Con II.
National Securities Exchange means an
exchange registered with the Commission under Section 6(a)
of the Securities Exchange Act (or any successor to such
Section) and any other securities exchange (whether or not
registered with the Commission under Section 6(a) (or
successor to such Section) of the Securities Exchange Act) that
the General Partner shall designate as a National Securities
Exchange for purposes of this Agreement.
Net Agreed Value means (a) in the case
of any Contributed Property, the Agreed Value of such property
reduced by any Liabilities either assumed by the Partnership
upon such contribution or to which such property is subject when
contributed and (b) in the case of any property distributed
to a Partner by the Partnership, the Partnerships Carrying
Value of such property (as adjusted pursuant to
Section 5.5(d)(ii)) at the time such property is
distributed, reduced by any Liabilities either assumed by such
Partner upon such distribution or to which such property is
subject at the time of distribution.
Net Income means, for any taxable period, the
excess, if any, of the Partnerships items of income and
gain (other than those items taken into account in the
computation of Net Termination Gain or Net Termination Loss) for
such taxable period over the Partnerships items of loss
and deduction (other than those items taken into account in the
computation of Net Termination Gain or Net Termination Loss) for
such taxable period. The items included in the calculation of
Net Income shall be determined in accordance with
Section 5.5(b) and shall include Simulated Gain, but shall
not include any items specially allocated under
Section 6.1(d) or Section 6.1(e);
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provided that the determination of the items that have been
specially allocated under Section 6.1(d) or
Section 6.1(e) shall be made without regard to any reversal
of such items under Section 6.1(d)(x).
Net Loss means, for any taxable period, the
excess, if any, of the Partnerships items of loss and
deduction (other than those items taken into account in the
computation of Net Termination Gain or Net Termination Loss) for
such taxable period over the Partnerships items of income
and gain (other than those items taken into account in the
computation of Net Termination Gain or Net Termination Loss) for
such taxable period. The items included in the calculation of
Net Loss shall be determined in accordance with
Section 5.5(b) and shall include Simulated Gain but shall
not include any items specially allocated under
Section 6.1(d) or Section 6.1(e); provided,
however, that the determination of the items that have been
specially allocated under Section 6.1(d) shall be made
without regard to any reversal of such items under
Section 6.1(d)(x).
Net Termination Gain means, for any taxable
period, the sum, if positive, of all items of income, gain, loss
or deduction (determined in accordance with Section 5.5(b))
that are (a) recognized by the Partnership (i) after
the Liquidation Date or (ii) upon the sale, exchange or
other disposition of all or substantially all of the assets of
the Partnership Group, taken as a whole, in a single transaction
or a series of related transactions (excluding any disposition
to a member of the Partnership Group), or (b) deemed
recognized by the Partnership pursuant to Section 5.5(d);
provided the items included in the determination of Net
Termination Gain shall include Simulated Gain, but shall not
include any items of income, gain or loss specially allocated
under Section 6.1(d) or Section 6.1(e).
Net Termination Loss means, for any taxable
period, the sum, if negative, of all items of income, gain, loss
or deduction (determined in accordance with Section 5.5(b))
that are (a) recognized by the Partnership (i) after
the Liquidation Date or (ii) upon the sale, exchange or
other disposition of all or substantially all of the assets of
the Partnership Group, taken as a whole, in a single transaction
or a series of related transactions (excluding any disposition
to a member of the Partnership Group), or (b) deemed
recognized by the Partnership pursuant to Section 5.5(d);
provided, however, that, items included in the
determination of Net Termination Loss shall include Simulated
Gain, but shall not include any items of income, gain or loss
specially allocated under Section 6.1(d) or
Section 6.1(e).
Nonrecourse Built-in Gain means, with respect
to any Contributed Properties or Adjusted Properties that are
subject to a mortgage or pledge securing a Nonrecourse
Liability, the amount of any taxable gain that would be
allocated to the Partners pursuant to Section 6.2(d) if
such properties were disposed of in a taxable transaction in
full satisfaction of such liabilities and for no other
consideration.
Nonrecourse Deductions means any and all
items of loss, deduction, expenditure (including any expenditure
described in Section 705(a)(2)(B) of the Code), Simulated
Depletion or Simulated Loss that, in accordance with the
principles of Treasury
Regulation Section 1.704-2(b),
are attributable to a Nonrecourse Liability.
Nonrecourse Liability has the meaning set
forth in Treasury
Regulation Section 1.752-1(a)(2).
Notice of Election to Purchase is defined in
Section 15.1(b).
Notional General Partner Unit means a
notional unit used solely to calculate the General
Partners Percentage Interest. Notional General Partner
Units shall not constitute Units for any purpose of
this Agreement. There shall initially
be
Notional General Partner Units (resulting in the General
Partners Percentage Interest being 2% after giving effect
to any exercise of the Over-Allotment Option and the Deferred
Issuance and Distribution). If the General Partner makes
additional Capital Contributions pursuant to
Section 5.2(b) to maintain its Percentage Interest,
the number of Notional General Partner Units shall be increased
proportionally to reflect the maintenance of such Percentage
Interest.
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Omnibus Agreement means the Omnibus
Agreement, dated as of the Closing Date, between the General
Partner and the Partnership, as such may be amended,
supplemented or restated from time to time.
Operating Company means Mid-Con Energy
Properties, LLC, a Delaware limited liability company.
Opinion of Counsel means a written opinion of
counsel (who may be regular counsel to the Partnership or the
General Partner or any of its Affiliates) acceptable to the
General Partner.
Option Closing Date means the date or dates
on which any Common Units are sold by the Partnership to the
Underwriters upon exercise of the Over-Allotment Option.
Organizational Limited Partner means
Mr. S. Craig George in his capacity as the organizational
limited partner of the Partnership pursuant to this Agreement.
Outstanding means, with respect to
Partnership Interests, all Partnership Interests that are issued
by the Partnership and reflected as outstanding on the
Partnerships books and records as of the date of
determination; provided, however, that if at any
time any Person or Group (other than the General Partner or its
Affiliates) beneficially owns 20% or more of the Partnership
Interests of any class then Outstanding, none of the Partnership
Interests of any class owned by such Person or Group shall be
entitled to be voted on any matter or considered to be
Outstanding when sending notices of a meeting of Limited
Partners to vote on any matter (unless otherwise required by
law), calculating required votes, determining the presence of a
quorum or for other similar purposes under this Agreement,
except that Partnership Interests so owned shall be considered
to be Outstanding for purposes of Section 11.1(b)(iv) (such
Partnership Interests shall not, however, be treated as a
separate class or group of Partnership Interests for purposes of
this Agreement or the Delaware Act); provided,
further, that the foregoing limitation shall not apply to
(i) any of the Founders, the Yorktown Funds or their
respective Affiliates, (ii) any Person or Group who
acquired 20% or more of the Partnership Interests of any class
then Outstanding directly from the General Partner or its
Affiliates (other than the Partnership), (iii) any Person
or Group who acquired 20% or more of the Partnership Interests
of any class then Outstanding directly or indirectly from a
Person or Group described in clauses (i) or
(ii) provided, that the General Partner shall have notified
such Person or Group in writing that such limitation shall not
apply, or (iv) any Person or Group who acquired 20% or more
of any Partnership Interests issued by the Partnership if the
General Partner shall have notified such Person or Group in
writing that such limitation shall not apply.
Over-Allotment Option means the
over-allotment option granted to the Underwriters by the
Partnership pursuant to the Underwriting Agreement.
Partner Nonrecourse Debt has the meaning set
forth in Treasury Regulation
Section 1.704-2(b)(4).
Partner Nonrecourse Debt Minimum Gain has the
meaning set forth in Treasury Regulation
Section 1.704-2(i)(2).
Partner Nonrecourse Deductions means any and
all items of loss, deduction, expenditure (including any
expenditure described in Section 705(a)(2)(B) of the Code),
Simulated Depletion or Simulated Loss that, in accordance with
the principles of Treasury
Regulation Section 1.704-2(i),
are attributable to a Partner Nonrecourse Debt.
Partners means the General Partner and the
Limited Partners.
Partnership means Mid-Con Energy Partners,
LP, a Delaware limited partnership.
Partnership Group means the Partnership and
its Subsidiaries treated as a single consolidated entity.
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Partnership Interest means any class or
series of equity interest in the Partnership, which shall
include the General Partner Interest and any Limited Partner
Interests but shall exclude any options, rights, warrants,
appreciation rights, tracking interests or phantom interests
relating to any equity interest in the Partnership.
Partnership Minimum Gain means that amount
determined in accordance with the principles of Treasury
Regulation Section 1.704-2(d).
Percentage Interest means as of any date of
determination (a) as to the General Partner, with respect
to the General Partner Interest (calculated based upon a number
of Notional General Partner Units), and as to any Unitholder
with respect to Units, the product obtained by multiplying
(i) 100% less the percentage applicable to clause (b)
below by (ii) the quotient obtained by dividing
(A) the number of Notional General Partner Units held by
the General Partner or the number of Units held by such
Unitholder, as the case may be, by (B) the total number of
Outstanding Units and Notional General Partner Units, and
(b) as to the holders of other Partnership Interests issued
by the Partnership in accordance with Section 5.6, the
percentage established as a part of such issuance.
Person means an individual or a corporation,
firm, limited liability company, partnership, joint venture,
trust, unincorporated organization, association, government
agency or political subdivision thereof or other entity.
Plan of Conversion is defined in
Section 14.1.
Pro Rata means (a) when used with
respect to Units or any class thereof, apportioned equally among
all designated Units in accordance with their relative
Percentage Interests and (b) when used with respect to
Partners or Record Holders, apportioned among all Partners or
Record Holders in accordance with their relative Percentage
Interests.
Purchase Date means the date determined by
the General Partner as the date for purchase of all Outstanding
Limited Partner Interests of a certain class (other than Limited
Partner Interests owned by the General Partner and its
Affiliates) pursuant to Article XV.
Quarter means, unless the context requires
otherwise, a fiscal quarter of the Partnership, or, with respect
to the fiscal quarter of the Partnership that includes the
Closing Date, the portion of such fiscal quarter after the
Closing Date.
Recapture Income means any gain recognized by
the Partnership (computed without regard to any adjustment
required by Section 734 or Section 743 of the Code)
upon the disposition of any property or asset of the
Partnership, which gain is characterized as ordinary income
because it represents the recapture of deductions previously
taken with respect to such property or asset.
Record Date means the date established by the
General Partner or otherwise in accordance with this Agreement
for determining (a) the identity of the Record Holders
entitled to notice of, or to vote at, any meeting of Limited
Partners or entitled to vote by ballot or give approval of
Partnership action in writing without a meeting or entitled to
exercise rights in respect of any lawful action of Limited
Partners or (b) the identity of Record Holders entitled to
receive any report or distribution or to participate in any
offer.
Record Holder means, (a) with respect to
the Common Units or any other class of Partnership Interests for
which a Transfer Agent has been appointed, the Person in whose
name a Common Unit or Partnership Interest of such other class
is registered on the books of the Transfer Agent as of the
opening of business on a particular Business Day or,
(b) with respect to other classes of Partnership Interests,
the Person in whose name any such other Partnership Interest is
registered on the books that the General Partner has caused to
be kept as of the opening of business on such Business Day.
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Redeemable Interests means any Partnership
Interests for which a redemption notice has been given, and has
not been withdrawn, pursuant to Section 4.9.
Registration Statement means the
Partnerships Registration Statement on
Form S-1
(Registration
No. 333-174017)
as it has been or as it may be amended or supplemented from time
to time, filed by the Partnership with the Commission under the
Securities Act to register the offering and sale of the Common
Units in the Initial Public Offering.
Required Allocations means any allocation of
an item of income, gain, loss, deduction, Simulated Depletion or
Simulated Loss pursuant to Section 6.1(d)(i),
Section 6.1(d)(ii), Section 6.1(d)(iii),
Section 6.1(d)(iv), Section 6.1(d)(v),
Section 6.1(d)(vi), Section 6.1(d)(viii) or
Section 6.1(e).
Securities Act means the Securities Act of
1933, as amended, supplemented or restated from time to time and
any successor to such statute.
Securities Exchange Act means the Securities
Exchange Act of 1934, as amended, supplemented or restated from
time to time and any successor to such statute.
Services Agreement means the Services
Agreement, dated as of the Closing Date, by and among the
Partnership, the General Partner and Mid-Con Energy Operating,
Inc.
Simulated Basis means the Carrying Value of
any oil and gas property (as defined in Section 614 of the
Code).
Simulated Depletion means, with respect to an
oil and gas property (as defined in Section 614 of the
Code), a depletion allowance computed in accordance with federal
income tax principles (as if the Simulated Basis of the property
was its adjusted tax basis) and in the manner specified in
Treasury
Regulation Section 1.704-1(b)(2)(iv)(k)(2).
For purposes of computing Simulated Depletion with respect to
any property, the Simulated Basis of such property shall be
deemed to be the Carrying Value of such property, and in no
event shall such allowance for Simulated Depletion, in the
aggregate, exceed such Simulated Basis.
Simulated Gain means the excess, if any, of
the amount realized from the sale or other disposition of an oil
or gas property over the Carrying Value of such property.
Simulated Loss means the excess, if any, of
the Carrying Value of an oil or gas property over the amount
realized from the sale or other disposition of such property.
Special Approval means approval by a majority
of the members of the Conflicts Committee.
Subsidiary means, with respect to any Person,
(a) a corporation of which more than 50% of the voting
power of shares entitled (without regard to the occurrence of
any contingency) to vote in the election of directors or other
governing body of such corporation is owned, directly or
indirectly, at the date of determination, by such Person, by one
or more Subsidiaries of such Person or a combination thereof,
(b) a partnership (whether general or limited) in which
such Person or a Subsidiary of such Person is, at the date of
determination, a general or limited partner of such partnership,
but only if such Person, directly or indirectly through one or
more Subsidiaries of such Person, (i) owns 50% or more of
the partnership interests of such partnership (considering all
of the partnership interests of the partnership as a single
class) at the date of determination or (ii) controls such
partnership at the date of determination, or (c) any other
Person (other than a corporation or a partnership) in which such
Person, one or more Subsidiaries of such Person, or a
combination thereof, directly or indirectly, at the date of
determination, has (i) at least a majority ownership
interest or (ii) the power to elect or direct the election
of a majority of the directors or other governing body of such
other Person.
Surviving Business Entity is defined in
Section 14.2(b)(ii).
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Trading Day means, for the purpose of
determining the Current Market Price of any class of Limited
Partner Interests, a day on which the principal National
Securities Exchange on which such class of Limited Partner
Interests is listed or admitted to trading is open for the
transaction of business or, if Limited Partner Interests of a
class are not listed or admitted to trading on any National
Securities Exchange, a day on which banking institutions in New
York City generally are open.
transfer is defined in Section 4.4(a).
Transfer Agent means such bank, trust company
or other Person (including the General Partner or one of its
Affiliates) as may be appointed from time to time by the General
Partner to act as registrar and transfer agent for a class of
Partnership Interests; provided, however, that if no
Transfer Agent is specifically designated for a class of
Partnership Interests, the General Partner shall act in such
capacity.
Underwriter means each Person named as an
underwriter in the Underwriting Agreement who purchases Common
Units pursuant thereto.
Underwriting Agreement means the Underwriting
Agreement,
dated ,
2011, among the Underwriters, the Partnership, the General
Partner and the other parties thereto, providing for the
purchase of Common Units by the Underwriters in the Initial
Public Offering.
Unit means a Partnership Interest that is
designated as a Unit and shall include Common Units
but shall not include Notional General Partner Units (or the
General Partner Interest represented thereby).
Unitholders means the holders of Units.
Unit Majority means at least a majority of
the Outstanding Common Units.
Unrealized Gain attributable to any item of
Partnership property means, as of any date of determination, the
excess, if any, of (a) the fair market value of such
property as of such date (as determined under
Section 5.5(d)) over (b) the Carrying Value of such
property as of such date (prior to any adjustment to be made
pursuant to Section 5.5(d) as of such date).
Unrealized Loss attributable to any item of
Partnership property means, as of any date of determination, the
excess, if any, of (a) the Carrying Value of such property
as of such date (prior to any adjustment to be made pursuant to
Section 5.5(d) as of such date) over (b) the fair
market value of such property as of such date (as determined
under Section 5.5(d)).
Unrestricted Person means (a) each
Indemnitee, (b) each Partner, (c) each Person who is
or was a member, partner, director, officer, employee or agent
of any Group Member, a General Partner or any Departing General
Partner or any Affiliate of any Group Member, a General Partner
or any Departing General Partner and (d) any Person the
General Partner designates as an Unrestricted Person
for purposes of this Agreement.
U.S. GAAP means United States generally
accepted accounting principles, as in effect from time to time,
consistently applied.
Withdrawal Opinion of Counsel is defined in
Section 11.1(b).
Yorktown Funds means Yorktown Energy Partners
VI, L.P., Yorktown Energy Partners VII, L.P. and Yorktown Energy
Partners VIII, L.P.
Section 1.2 Construction. Unless
the context requires otherwise: (a) any pronoun used in
this Agreement shall include the corresponding masculine,
feminine or neuter forms, and the singular form of nouns,
pronouns and verbs shall include the plural and vice versa;
(b) references to Articles and Sections refer to Articles
and Sections of this Agreement; (c) the terms
include, includes,
including or words of like import shall be
deemed to be followed by the words without
limitation; and (d) the terms
hereof, herein or
hereunder refer to this Agreement
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as a whole and not to any particular provision of this
Agreement. The table of contents and headings contained in this
Agreement are for reference purposes only, and shall not affect
in any way the meaning or interpretation of this Agreement.
ARTICLE II
ORGANIZATION
Section 2.1 Formation. The
General Partner and the Organizational Limited Partner
previously formed the Partnership as a limited partnership
pursuant to the provisions of the Delaware Act and hereby amend
and restate the Agreement of Limited Partnership of Mid-Con
Energy Partners, LP, dated as of July 27, 2011, in its
entirety. This amendment and restatement shall become effective
as of the date first set forth above. Except as expressly
provided to the contrary in this Agreement, the rights, duties
(including fiduciary duties), liabilities and obligations of the
Partners and the administration, dissolution and termination of
the Partnership shall be governed by the Delaware Act. All
Partnership Interests shall constitute personal property of the
owner thereof for all purposes.
Section 2.2 Name. The
name of the Partnership shall be Mid-Con Energy Partners,
LP. The Partnerships business may be conducted under
any other name or names as determined by the General Partner,
including the name of the General Partner. The words
Limited Partnership, LP,
Ltd. or similar words or letters shall be included
in the Partnerships name where necessary for the purpose
of complying with the laws of any jurisdiction that so requires.
The General Partner may change the name of the Partnership at
any time and from time to time without the consent or approval
of any Limited Partner and shall notify the Limited Partners of
such change in the next regular communication to the Limited
Partners.
Section 2.3 Registered
Office; Registered Agent; Principal Office; Other
Offices. Unless and until changed by the General
Partner, the registered office of the Partnership in the State
of Delaware shall be located at 1209 Orange Street, Wilmington,
New Castle County, Delaware 19801, and the registered agent for
service of process on the Partnership in the State of Delaware
at such registered office shall be The Corporation
Trust Company. The principal office of the Partnership
shall be located at 2431 E. 61st Street,
Suite 850, Tulsa Oklahoma 74136, or such other place as the
General Partner may from time to time designate by notice to the
Limited Partners. The Partnership may maintain offices at such
other place or places within or outside the State of Delaware as
the General Partner determines to be necessary or appropriate.
The address of the General Partner shall be
2431 E. 61st Street, Suite 850, Tulsa
Oklahoma 74136, or such other place as the General Partner may
from time to time designate by notice to the Limited Partners.
Section 2.4 Purpose
and Business. The purpose and nature of the
business to be conducted by the Partnership shall be to
(a) engage directly in, or enter into or form, hold and
dispose of any corporation, partnership, joint venture, limited
liability company or other arrangement to engage indirectly in,
any business activity that is approved by the General Partner,
in its sole discretion, and that lawfully may be conducted by a
limited partnership organized pursuant to the Delaware Act and,
in connection therewith, to exercise all of the rights and
powers conferred upon the Partnership pursuant to the agreements
relating to such business activity and (b) do anything
necessary or appropriate to the foregoing, including the making
of capital contributions or loans to a Group Member;
provided, however, that the General Partner shall not
cause the Partnership to engage, directly or indirectly, in any
business activity that the General Partner determines would be
reasonably likely to cause the Partnership to be treated as an
association taxable as a corporation or otherwise taxable as an
entity for federal income tax purposes. To the fullest extent
permitted by law, the General Partner shall have no duty
(including any fiduciary duty) or obligation whatsoever to the
Partnership, any Limited Partner, any Person who acquires an
interest in Partnership Interests or any other Person bound by
this
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Agreement to propose or approve the conduct by the Partnership
of any business, and may, in its sole discretion, decline to
propose or approve, the conduct by the Partnership of any
business free of any duty (including any fiduciary duty) or
obligation whatsoever to the Partnership, any Limited Partner,
any Person who acquires an interest in Partnership Interests or
any other Person bound by this Agreement and, in declining to so
propose or approve, shall not be required to act in good faith
or pursuant to any other standard imposed by this Agreement, any
Group Member Agreement, any other agreement contemplated hereby
or under the Delaware Act or any other law, rule or regulation
or at equity.
Section 2.5 Powers. The
Partnership shall be empowered to do any and all acts and things
necessary, appropriate, proper, advisable, incidental to or
convenient for the furtherance and accomplishment of the
purposes and business described in Section 2.4 and for the
protection and benefit of the Partnership.
Section 2.6 Term. The
term of the Partnership commenced upon the filing of the
Certificate of Limited Partnership in accordance with the
Delaware Act and shall continue until the dissolution of the
Partnership in accordance with the provisions of
Article XII. The existence of the Partnership as a separate
legal entity shall continue until the cancellation of the
Certificate of Limited Partnership as provided in the Delaware
Act.
Section 2.7 Title
to Partnership Assets. Title to Partnership
assets, whether real, personal or mixed and whether tangible or
intangible, shall be deemed to be owned by the Partnership as an
entity, and no Partner, individually or collectively, shall have
any ownership interest in such Partnership assets or any portion
thereof. Title to any or all of the Partnership assets may be
held in the name of the Partnership, the General Partner, one or
more of its Affiliates or one or more nominees, as the General
Partner may determine. The General Partner hereby declares and
warrants that any Partnership assets for which record title is
held in the name of the General Partner or one or more of its
Affiliates or one or more nominees shall be held by the General
Partner or such Affiliate or nominee for the use and benefit of
the Partnership in accordance with the provisions of this
Agreement; provided, however, that the General Partner
shall use reasonable efforts to cause record title to such
assets (other than those assets in respect of which the General
Partner determines that the expense and difficulty of
conveyancing makes transfer of record title to the Partnership
impracticable) to be vested in the Partnership as soon as
reasonably practicable; provided, further, that, prior to
the withdrawal or removal of the General Partner or as soon
thereafter as practicable, the General Partner shall use
reasonable efforts to effect the transfer of record title to the
Partnership and, prior to any such transfer, will provide for
the use of such assets in a manner satisfactory to the General
Partner. All Partnership assets shall be recorded as the
property of the Partnership in its books and records,
irrespective of the name in which record title to such
Partnership assets is held.
ARTICLE III
RIGHTS OF
LIMITED PARTNERS
Section 3.1 Limitation
of Liability. The Limited Partners shall have no
liability under this Agreement except as expressly provided in
this Agreement or the Delaware Act.
Section 3.2 Management
of Business. No Limited Partner, in its capacity
as such, shall participate in the operation, management or
control (within the meaning of the Delaware Act) of the
Partnerships business, transact any business in the
Partnerships name or have the power to sign documents for
or otherwise bind the Partnership. Any action taken by any
Affiliate of the General Partner or any officer, director,
employee, manager, member, general partner, agent or trustee of
the General Partner or any of its Affiliates, or any officer,
director, employee, manager, member, general partner, agent or
trustee of a Group Member, in its capacity as such, shall not,
to the fullest extent permitted by law, be deemed to be
participation in the control of the business
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of the Partnership by a limited partner of the Partnership
(within the meaning of
Section 17-303(a)
of the Delaware Act) and shall not affect, impair or eliminate
the limitations on the liability of the Limited Partners under
this Agreement.
Section 3.3 Outside
Activities of the Limited Partners. Subject to
the provisions of Section 7.5, which shall continue to be
applicable to the Persons referred to therein, regardless of
whether such Persons shall also be Limited Partners, any Limited
Partner shall be entitled to and may have business interests and
engage in business activities in addition to those relating to
the Partnership, including business interests and activities in
direct competition with the Partnership Group. Neither the
Partnership nor any of the other Partners shall have any rights
by virtue of this Agreement in any business ventures of any
Limited Partner.
Section 3.4 Rights
of Limited Partners.
(a) In addition to other rights provided by this Agreement
or by applicable law (other than
Section 17-305
of the Delaware Act, the obligations of which are to the fullest
extent permitted by law expressly replaced in there entirety by
the provisions of this Section 3.4(a)), and except as
limited by Sections 3.4(b) and 3.4(c), each Limited Partner
shall have the right, for a purpose that is reasonably related
to such Limited Partners interest as a Limited Partner in
the Partnership, the reasonableness of which shall be determined
by the General Partner, upon reasonable written demand stating
the purpose of such demand, and at such Limited Partners
own expense, to obtain:
(i) true and full information regarding the status of the
business and financial condition of the Partnership (provided
that the requirements of this Section 3.4(a)(i) shall
be satisfied to the extent the Limited Partner is furnished the
Partnerships most recent annual report and any subsequent
quarterly or periodic reports required to filed with the
Commission pursuant to Section 13 of the Securities
Exchange Act);
(ii) a current list of the name and last known business,
residence or mailing address of each Record Holder;
(iii) a copy of this Agreement and the Certificate of
Limited Partnership and all amendments thereto (provided that
the requirements of this Section 3.4(a)(iii) shall be
satisfied to the extent that true and correct copies of such
documents are publicly available with the Commission via its
Electronic Data Gathering Analysis and Retrieval System);
(iv) such other information regarding the affairs of the
Partnership as the General Partner determines in its sole
discretion is just and reasonable.
(b) To the fullest extent permitted by law, the General
Partner may keep confidential from the Limited Partners, for
such period of time as the General Partner deems reasonable,
(i) any information that the General Partner reasonably
believes to be in the nature of trade secrets or (ii) other
information the disclosure of which the General Partner in good
faith believes (A) is not in the best interests of the
Partnership Group, (B) could damage the Partnership Group
or its business or (C) that any Group Member is required by
law or by agreement with any third party to keep confidential
(other than agreements with Affiliates of the Partnership the
primary purpose of which is to circumvent the obligations set
forth in this Section 3.4).
(c) Notwithstanding any other provision of this Agreement
or
Section 17-305
of the Delaware Act, each of the Partners, each other Person who
acquires an interest in a Partnership Interest and each other
Person bound by this Agreement hereby agrees to the fullest
extent permitted by law that they do not have rights to receive
information from the Partnership or any Indemnitee for the
purpose of determining whether to pursue litigation or assist in
pending litigation against the Partnership or any Indemnitee
relating to the affairs of the Partnership except pursuant to
the applicable rules of discovery relating to litigation
commenced by such Person.
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ARTICLE IV
CERTIFICATES;
RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS;
REDEMPTION OF
PARTNERSHIP INTERESTS
Section 4.1 Certificates. Notwithstanding
anything to the contrary in this Agreement, unless the General
Partner shall determine otherwise with respect to all or a
portion of any particular class of Partnership Interests,
Partnership Interests shall not be evidenced by certificates;
provided, upon the request of any Person holding Common Units,
the Partnership shall issue one or more Certificates evidencing
Common Units in the name of such Person. Certificates issued
evidencing Partnership Interests shall be executed by the
General Partner on behalf of the Partnership by the Chairman of
the Board, Chief Executive Officer, President, Chief Financial
Officer or any Vice President and the Secretary, any Assistant
Secretary, or other authorized officer or director of the
General Partner on behalf of the General Partner. No Certificate
shall be valid for any purpose until it has been countersigned
by the Transfer Agent (if other than the General Partner);
provided, however, that, if the General Partner elects to
cause the Partnership to issue Partnership Interests of such
class in global form, the Certificate shall be valid upon
receipt of a certificate from the Transfer Agent certifying that
the Partnership Interests have been duly registered in
accordance with the directions of the Partnership.
Section 4.2 Mutilated,
Destroyed, Lost or Stolen Certificates.
(a) If any mutilated Certificate is surrendered to the
Transfer Agent (if a Transfer Agent has been appointed for the
class of Partnership Interests represented by such Certificate)
or the General Partner (if no Transfer Agent has been appointed
for the class of Partnership Interests represented by such
Certificate), the appropriate officers of the General Partner on
behalf of the Partnership shall execute, and the Transfer Agent
(if applicable) shall countersign and deliver in exchange
therefor, a new Certificate (or, if requested by the holder
thereof, other evidence of the issuance of uncertificated
Partnership Interests) evidencing the same number and type of
Partnership Interests as the Certificate so surrendered.
(b) The appropriate officers of the General Partner on
behalf of the Partnership shall execute and deliver, and the
Transfer Agent (if applicable) shall countersign, a new
Certificate in place of any Certificate previously issued, or
issue uncertificated Units, if the Record Holder of the
Certificate:
(i) makes proof by affidavit, in form and substance
satisfactory to the General Partner, that a previously issued
Certificate has been lost, destroyed or stolen;
(ii) requests the issuance of a new Certificate or evidence
of the issuance of uncertificated Partnership Interests before
the General Partner has notice that the Certificate has been
acquired by a purchaser for value in good faith and without
notice of an adverse claim;
(iii) if requested by the General Partner, delivers to the
General Partner and the Transfer Agent a bond, in form and
substance satisfactory to the General Partner, with surety or
sureties and with fixed or open penalty as the General Partner
may direct to indemnify the Partnership, the Partners, the
General Partner and the Transfer Agent against any claim that
may be made on account of the alleged loss, destruction or theft
of the Certificate; and
(iv) satisfies any other reasonable requirements imposed by
the General Partner.
If a Limited Partner fails to notify the General Partner within
a reasonable period of time after such Limited Partner has
notice of the loss, destruction or theft of a Certificate, and a
transfer of the Limited Partner Interests represented by the
Certificate is registered before the Partnership, the General
Partner or the Transfer Agent receives such notification, the
Limited Partner shall be precluded from making any claim against
the Partnership, the General Partner
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or the Transfer Agent for such transfer or for a new Certificate
or evidence of the issuance of uncertificated Partnership
Interests.
(c) As a condition to the issuance of any new Certificate
or evidence of the issuance of uncertificated Partnership
Interests under this Section 4.2, the General Partner may
require the payment of a sum sufficient to cover any tax or
other governmental charge that may be imposed in relation
thereto and any other expenses (including the fees and expenses
of the Transfer Agent) reasonably connected therewith.
Section 4.3 Record
Holders. The Partnership shall be entitled to
recognize the Record Holder as the Partner with respect to any
Partnership Interest and, accordingly, shall not be bound to
recognize any equitable or other claim to, or interest in, such
Partnership Interest on the part of any other Person, regardless
of whether the Partnership shall have actual or other notice
thereof, except as otherwise provided by law or any applicable
rule, regulation, guideline or requirement of any National
Securities Exchange on which such Partnership Interests are
listed or admitted to trading. Without limiting the foregoing,
when a Person (such as a broker, dealer, bank, trust company or
clearing corporation or an agent of any of the foregoing) is
acting as nominee, agent or in some other representative
capacity for another Person in acquiring
and/or
holding Partnership Interests, as between the Partnership on the
one hand, and such other Persons on the other, such
representative Person shall be (a) the Record Holder of
such Partnership Interest and (b) bound by this Agreement
and shall have the rights and obligations of a Partner hereunder
as, and to the extent, provided herein.
Section 4.4 Transfer
Generally.
(a) The term transfer, when used in this
Agreement with respect to a Partnership Interest, shall mean a
transaction (i) by which the General Partner assigns its
General Partner Interest (including its Notional General Partner
Units) to another Person, and includes a sale, assignment, gift,
pledge, encumbrance, hypothecation, mortgage, exchange or any
other disposition by law or otherwise or (ii) by which the
holder of a Limited Partner Interest assigns such Limited
Partner Interest to another Person who is or becomes a Limited
Partner, and includes a sale, assignment, gift, exchange or any
other disposition by law or otherwise, excluding a pledge,
encumbrance, hypothecation or mortgage but including any
transfer upon foreclosure of any pledge, encumbrance,
hypothecation or mortgage.
(b) No Partnership Interest shall be transferred, in whole
or in part, except in accordance with the terms and conditions
set forth in this Article IV. Any transfer or purported
transfer of a Partnership Interest not made in accordance with
this Article IV shall be, to the fullest extent permitted
by law, null and void.
(c) Nothing contained in this Agreement shall be construed
to prevent a disposition by any stockholder, member, partner or
other owner of any Partner of any or all of the shares of stock,
membership or limited liability company interests, partnership
interests or other ownership interests in such Partner and the
term transfer shall not mean any such
disposition.
Section 4.5 Registration
and Transfer of Limited Partner Interests.
(a) The General Partner shall keep or cause to be kept on
behalf of the Partnership a register in which, subject to such
reasonable regulations as it may prescribe and subject to the
provisions of Section 4.5(b), the Partnership will provide
for the registration and transfer of Limited Partner Interests.
Wells Fargo Shareowner Services is hereby appointed as the
initial Transfer Agent for the purposes of registering the
Common Units and transfers of such Common Units as herein
provided.
(b) Neither the General Partner nor the Partnership shall
recognize any transfer of Limited Partner Interests evidenced by
Certificates until the endorsed Certificates evidencing such
Limited Partner Interests are surrendered for registration of
transfer. No charge shall be
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imposed by the General Partner for such transfer;
provided, however, that as a condition to the
issuance of any new Certificate under this Section 4.5, the
General Partner may require the payment of a sum sufficient to
cover any tax or other governmental charge that may be imposed
with respect thereto. Upon surrender of a Certificate for
registration of transfer of any Limited Partner Interests
evidenced by a Certificate, and subject to the provisions
hereof, the appropriate officers of the General Partner on
behalf of the General Partner on behalf of the Partnership shall
execute, the Transfer Agent (if applicable) shall countersign
and the General Partner or the Transfer Agent (if applicable)
shall deliver, in the name of the holder or the designated
transferee or transferees, as required pursuant to the
holders instructions, one or more new Certificates (or, if
requested by the holder, other evidence of the issuance of
uncertificated Limited Partner Interests) evidencing the same
aggregate number and type of Limited Partner Interests as was
evidenced by the Certificate so surrendered.
(c) Upon the receipt of proper transfer instructions from
the Record Holder of uncertificated Limited Partner Interests,
such transfer of uncertificated Limited Partner Interests shall
be recorded upon the Partnerships register.
(d) Subject to (i) the foregoing provisions of this
Section 4.5, (ii) Section 4.3,
(iii) Section 4.8, (iv) with respect to any class
or series of Limited Partner Interests, the provisions of any
statement of designations or an amendment to this Agreement
establishing such class or series, (v) any contractual
provisions binding on any Limited Partner and
(vi) provisions of applicable law, including the Securities
Act, Limited Partner Interests shall be freely transferable.
(e) The General Partner and its Affiliates shall have the
right, subject to Section 4.6, at any time to transfer
their Common Units and any other Partnership Interests they may
acquire to one or more Persons.
Section 4.6 Transfer
of the General Partners General Partner Interest.
(a) Subject to Section 4.6(c) below, prior to December
31, 2021, the General Partner shall not transfer all or any part
of its General Partner Interest (including its Notional General
Partner Units) to a Person unless such transfer (i) has
been approved by the prior written consent or vote of the
holders of at least a majority of the Outstanding Common Units
(excluding Common Units held by the General Partner and its
Affiliates) or (ii) is of all, but not less than all, of
its General Partner Interest (including its Notional General
Partner Units) to (A) an Affiliate of the General Partner
(other than an individual) or (B) another Person (other
than an individual) in connection with the merger or
consolidation of the General Partner with or into such other
Person or the transfer by the General Partner of all or
substantially all of its assets to such other Person.
(b) Subject to Section 4.6(c) below, on or after
December 31, 2021, the General Partner may at its option
transfer its General Partner Interest (including its Notional
General Partner Units), in whole or in part, without Unitholder
approval.
(c) Notwithstanding anything herein to the contrary, no
transfer by the General Partner of all or any part of its
General Partner Interest to another Person shall be permitted
unless (i) the transferee agrees to assume the rights and
duties of the General Partner under this Agreement and to be
bound by the provisions of this Agreement, (ii) the
Partnership receives an Opinion of Counsel that such transfer
would not result in the loss of limited liability of any Limited
Partner under the Delaware Act or cause the Partnership to be
treated as an association taxable as a corporation or otherwise
to be taxed as an entity for federal income tax purposes (to the
extent not already so treated or taxed) and (iii) such
transferee also agrees to purchase all (or the appropriate
portion thereof, if applicable) of the partnership or membership
interest held by the General Partner as the general partner or
managing member, if any, of each other Group Member. In the case
of a transfer pursuant to and in compliance with this
Section 4.6, the transferee or successor (as the case may
be) is hereby authorized to and shall, subject to compliance
with the terms of Section 10.2, be admitted to the
Partnership as the General Partner
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effective immediately prior to the transfer of the General
Partner Interest, and the business of the Partnership shall
continue without dissolution.
Section 4.7 Restrictions
on Transfers.
(a) Notwithstanding the other provisions of this
Article IV, no transfer of any Partnership Interests shall
be made if such transfer would (i) violate the then
applicable federal or state securities laws or rules and
regulations of the Commission, any state securities commission
or any other governmental authority with jurisdiction over such
transfer, (ii) terminate the existence or qualification of
the Partnership under the laws of the jurisdiction of its
formation or (iii) cause the Partnership to be treated as
an association taxable as a corporation or otherwise to be taxed
as an entity for federal income tax purposes (to the extent not
already so treated or taxed).
(b) The General Partner may impose restrictions on the
transfer of Partnership Interests if it determines, with the
advice of counsel, that such restrictions are necessary or
advisable to (i) avoid a significant risk of the
Partnership becoming taxable as a corporation or otherwise
becoming taxable as an entity for U.S. federal income tax
purposes or (ii) preserve the uniformity of the Limited
Partner Interests (or any class or classes thereof). The General
Partner may impose such restrictions by amending this Agreement;
provided, however, that any amendment that would result
in the delisting or suspension of trading of any class of
Limited Partner Interests on the principal National Securities
Exchange on which such class of Limited Partner Interests is
then listed or admitted to trading must be approved, prior to
such amendment being effected, by the holders of at least a
majority of the Outstanding Limited Partner Interests of such
class.
(c) Nothing contained in this Agreement shall preclude the
settlement of any transactions involving Partnership Interests
entered into through the facilities of any National Securities
Exchange on which such Partnership Interests are listed or
admitted to trading.
(d) Each Certificate evidencing Partnership Interests shall
bear a conspicuous legend in substantially the following form:
THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF
MID-CON ENERGY PARTNERS, LP (THE
PARTNERSHIP) THAT THIS SECURITY MAY
NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED
IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE
FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS
OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES
COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION
OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR
QUALIFICATION OF THE PARTNERSHIP UNDER THE LAWS OF THE STATE OF
DELAWARE, (C) CAUSE THE PARTNERSHIP TO BE TREATED AS AN
ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS
AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT
ALREADY SO TREATED OR TAXED) OR (D) VIOLATE THE TERMS AND
CONDITIONS OF THE PARTNERSHIP AGREEMENT. THE GENERAL PARTNER OF
THE PARTNERSHIP MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE
TRANSFER OF THIS SECURITY IF IT DETERMINES WITH THE ADVICE OF
COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY OR ADVISABLE TO
AVOID A SIGNIFICANT RISK OF THE PARTNERSHIP BECOMING TAXABLE AS
A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR
FEDERAL INCOME TAX PURPOSES OR TO PRESERVE THE UNIFORMITY OF THE
LIMITED PARTNER INTERESTS REPRESENTED BY THIS SECURITY (OR ANY
CLASS OR CLASSES THEREOF). THE RESTRICTIONS SET FORTH
ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS
INVOLVING THIS SECURITY ENTERED INTO THROUGH THE
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FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS
SECURITY IS LISTED OR ADMITTED TO TRADING.
Section 4.8 Eligibility
Certificates; Ineligible Holders.
(a) The General Partner may request any Limited Partner to
furnish to the General Partner, within 30 days after
receipt of such request, an executed Citizenship Certification
or such other information concerning such Limited Partners
nationality, citizenship or other related status (or, if the
Limited Partner is a nominee holding for the account of another
Person, the nationality, citizenship or other related status of
such Person) as the General Partner may request. If a Limited
Partner fails to furnish to the General Partner within the
aforementioned
30-day
period such Citizenship Certification or other requested
information or if upon receipt of such Citizenship Certification
or other requested information the General Partner determines
that a Limited Partner is not an Eligible Citizen Holder, the
Limited Partner Interests owned by such Limited Partner shall be
subject to redemption in accordance with the provisions of
Section 4.9. In addition, the General Partner may require
that the status of any such Limited Partner be changed to that
of an Ineligible Citizen Holder and, thereupon, such Ineligible
Citizen Holder shall cease to be a Partner and shall have no
voting rights (whether arising hereunder, under the Delaware
Act, at law, in equity or otherwise) in respect of his Limited
Partner Interests in the Partnership. The General Partner shall
be substituted for such Ineligible Citizen Holder as the Limited
Partner in respect of such Ineligible Citizen Holders
Limited Partner Interests and shall vote such Limited Partner
Interests in accordance with Section 4.8(b).
(b) The General Partner shall, in exercising voting rights
in respect of Limited Partner Interests held by it on behalf of
Ineligible Citizen Holders, distribute the votes in the same
ratios as the votes of Limited Partners (including the General
Partner and its Affiliates) in respect of Limited Partner
Interests other than those of Ineligible Citizen Holders are
cast, either for, against or abstaining as to the matter.
(c) Upon dissolution of the Partnership, an Ineligible
Citizen Holder shall have no right to receive a distribution in
kind pursuant to Section 12.4 but shall be entitled to the
cash equivalent thereof, and the Partnership shall provide cash
in exchange for an assignment of the Ineligible Citizen
Holders share of any distribution in kind. Such payment
and assignment shall be treated for Partnership purposes as a
purchase by the Partnership from the Ineligible Citizen Holder
of his Limited Partner Interest (representing his right to
receive his share of such distribution in kind).
(d) At any time after an Ineligible Citizen Holder can and
does certify that it has become an Eligible Holder, an
Ineligible Citizen Holder may, upon application to the General
Partner, request that with respect to any Limited Partner
Interests of such Ineligible Citizen Holder not redeemed
pursuant to Section 4.9, such Ineligible Citizen Holder be
admitted as a Limited Partner, and upon approval of the General
Partner, in its sole discretion, such Ineligible Citizen Holder
shall be admitted as a Limited Partner and shall no longer
constitute an Ineligible Holder and the General Partner shall
cease to be deemed to be the Limited Partner in respect of the
Ineligible Citizen Holders Limited Partner Interests.
Section 4.9 Redemption
of Partnership Interests of Ineligible Holders.
(a) If at any time a Limited Partner fails to furnish an
Eligibility Certification or other information requested within
the time period specified in Section 4.8(a), or if upon
receipt of such Eligibility Certification or other information,
the General Partner determines, with the advice of counsel, that
a Limited Partner is an Ineligible Citizen Holder, the
Partnership may, unless the Limited Partner establishes to the
satisfaction of the General Partner that such Limited Partner is
not an Ineligible Holder or has transferred his Limited Partner
Interests to a Person who is an Eligible Citizen Holder and who
furnishes an Eligibility Certification or other information, as
the
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case may be, to the General Partner prior to the date fixed for
redemption as provided below, redeem the Limited Partner
Interest of such Limited Partner as follows:
(i) The General Partner shall, not later than the
30th day before the date fixed for redemption, give notice
of redemption to the Limited Partner, at his last address
designated on the records of the Partnership or the Transfer
Agent, as applicable, by registered or certified mail, postage
prepaid. The notice shall be deemed to have been given when so
mailed. The notice shall specify the Redeemable Interests, the
date fixed for redemption, the place of payment, that payment of
the redemption price will be made upon redemption of the
Redeemable Interests (or, if later in the case of Redeemable
Interests evidenced by Certificates, upon surrender of the
Certificates evidencing the Redeemable Interests in the manner
specified in the notice) and that on and after the date fixed
for redemption no further allocations or distributions to which
the Limited Partner would otherwise be entitled in respect of
the Redeemable Interests will accrue or be made.
(ii) The aggregate redemption price for Redeemable
Interests shall be an amount equal to the Current Market Price
(the date of determination of which shall be the date fixed for
redemption) of Limited Partner Interests of the class to be so
redeemed multiplied by the number of Limited Partner Interests
of each such class included among the Redeemable Interests. The
redemption price shall be paid, as determined by the General
Partner, in cash or by delivery of a promissory note of the
Partnership in the principal amount of the redemption price,
bearing interest at the rate of 5% annually and payable in three
equal annual installments of principal together with accrued
interest, commencing one year after the redemption date.
(iii) The Limited Partner or his duly authorized
representative shall be entitled to receive the payment for the
Redeemable Interests at the place of payment specified in the
notice of redemption on the redemption date (or, if later in the
case of Redeemable Interests evidenced by Certificates, upon
surrender by or on behalf of the Limited Partner at the place
specified in the notice of redemption, of the Certificates
evidencing the Redeemable Interests, duly endorsed in blank or
accompanied by an assignment duly executed in blank).
(iv) After the redemption date, Redeemable Interests shall
no longer constitute issued and Outstanding Limited Partner
Interests.
(b) The provisions of this Section 4.9 shall also be
applicable to Limited Partner Interests held by a Limited
Partner as nominee of a Person determined to be an Ineligible
Citizen Holder.
(c) Nothing in this Section 4.9 shall prevent the
recipient of a notice of redemption from transferring his
Limited Partner Interest before the redemption date if such
transfer is otherwise permitted under this Agreement. Upon
receipt of notice of such a transfer, the General Partner shall
withdraw the notice of redemption, provided the transferee of
such Limited Partner Interest certifies to the satisfaction of
the General Partner that he is an Eligible Holder. If the
transferee fails to make such certification, such redemption
shall be effected from the transferee on the original redemption
date.
ARTICLE V
CAPITAL
CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS
Section 5.1 Organizational
Contributions. In connection with the formation
of the Partnership under the Delaware Act, the General Partner
made an initial Capital Contribution to the Partnership in the
amount of $20.00 in exchange for a General Partner Interest
equal to a 2.0% Percentage Interest and was admitted as the
General Partner of the Partnership and hereby continues in such
capacity. The Organizational Limited Partner made an initial
Capital Contribution to the Partnership in the amount of $980.00
in exchange for a Limited Partner Interest
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equal to a 98.0% Percentage Interest and was admitted as a
Limited Partner of the Partnership and hereby continues in such
capacity. As of the Closing Date, and effective with the
admission of another Limited Partner to the Partnership, the
interest of the Organizational Limited Partner shall be redeemed
as provided in the Contribution and Merger Agreement, the
Organizational Limited Partner shall cease to be a limited
partner of the Partnership and the initial Capital Contribution
of the Organizational Limited Partner shall thereupon be
refunded. Ninety-eight percent of any interest or other profit
that may have resulted from the investment or other use of such
initial Capital Contributions shall be allocated and distributed
to the Organizational Limited Partner.
Section 5.2 Contributions
by the General Partner.
(a) On the Closing Date and pursuant to the Contribution
and Merger Agreement the General Partner will contribute to the
Partnership, as a Capital Contribution, the GP Contribution
Interests (as defined in the Contribution and Merger Agreement)
in exchange for Notional General
Partner Units, representing a continuation of its General
Partner Interest with a 2.0% Percentage Interest (after giving
effect to any exercise of the Over-Allotment Option and the
Deferred Issuance and Distribution), subject to all of the
rights, privileges and duties of the General Partner under this
Agreement.
(b) Upon the issuance of any additional Limited Partner
Interests by the Partnership (other than the Common Units issued
in the Initial Public Offering, the Common Units issued pursuant
to the Over-Allotment Option or the Deferred Issuance and
Distribution), the General Partner may, in exchange for a
proportionate number of Notional General Partner Units, make
additional Capital Contributions in an amount equal to the
product obtained by multiplying (i) the quotient determined
by dividing (A) the General Partners Percentage
Interest by (B) 100 less the General Partners
Percentage Interest times (ii) the amount contributed to
the Partnership by the Limited Partners in exchange for such
additional Limited Partner Interests. Except as set forth in
Section 12.8, the General Partner shall not be obligated to
make any additional Capital Contributions to the Partnership.
Section 5.3 Contributions
by Limited Partners.
(a) On the Closing Date and pursuant to the Contribution
and Merger Agreement, Mid-Con I and Mid-Con II will merge
with and into the Operating Company, with the Operating Company
surviving the merger, and in exchange for the right of the
Contributing Parties to receive, in the aggregate, (i) an
issuance of Common Units and
a distribution of $ million
in cash and (ii) a further distribution of cash upon any
exercise of the Over-Allotment Option and, to the extent the
Over-Allotment Option is not exercised, an issuance of
additional Common Units pursuant to the Deferred Issuance and
Distribution.
(b) On the Closing Date and pursuant to the Underwriting
Agreement, each Underwriter shall contribute cash to the
Partnership in exchange for the issuance by the Partnership of
an aggregate of Common Units
to the Underwriter, as set forth in the Underwriting Agreement.
(c) Upon the exercise, if any, of the Over-Allotment
Option, each Underwriter shall contribute cash to the
Partnership in exchange for the issuance by the Partnership of
Common Units to each Underwriter, all as set forth in the
Underwriting Agreement. The Partnership will then distribute the
cash received to the Contributing Parties pursuant to the
Contribution and Merger Agreement.
(d) To the extent the Over-Allotment Option is not
exercised, upon the expiration of such option, the Partnership
will issue additional Common Units to the Contributing Parties
pursuant to the Contribution and Merger Agreement.
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(e) No Limited Partner will be required to make any
additional Capital Contribution to the Partnership pursuant to
this Agreement.
Section 5.4 Interest
and Withdrawal of Capital Contributions.
No interest shall be paid by the Partnership on Capital
Contributions. No Partner shall be entitled to the withdrawal or
return of its Capital Contribution, except to the extent, if
any, that distributions made pursuant to this Agreement or upon
dissolution of the Partnership may be considered as such by law
and then only to the extent provided for in this Agreement.
Except to the extent expressly provided in this Agreement, no
Partner shall have priority over any other Partner either as to
the return of Capital Contributions or as to profits, losses or
distributions. Any such return shall be a compromise to which
all Partners agree within the meaning of
Section 17-502(b)
of the Delaware Act.
Section 5.5 Capital
Accounts.
(a) The Partnership shall maintain for each Partner (or a
beneficial owner of Partnership Interests held by a nominee in
any case in which the nominee has furnished the identity of such
owner to the Partnership in accordance with Section 6031(c)
of the Code or any other method acceptable to the General
Partner) owning a Partnership Interest a separate Capital
Account with respect to such Partnership Interest in accordance
with the rules of Treasury
Regulation Section 1.704-1(b)(2)(iv).
Such Capital Account shall be increased by (i) the amount
of all Capital Contributions made to the Partnership with
respect to such Partnership Interest and (ii) all items of
Partnership income and gain (including Simulated Gain and income
and gain exempt from tax) computed in accordance with
Section 5.5(b) and allocated with respect to such
Partnership Interest pursuant to Section 6.1, and decreased
by (x) the amount of cash or Net Agreed Value of all actual
and deemed distributions of cash or property made with respect
to such Partnership Interest and (y) all items of
Partnership deduction and loss (including Simulated Depletion
and Simulated Loss) computed in accordance with
Section 5.5(b) and allocated with respect to such
Partnership Interest pursuant to Section 6.1.
(b) For purposes of computing the amount of any item of
income, gain, loss, deduction, Simulated Depletion, Simulated
Gain or Simulated Loss that is to be allocated pursuant to
Article VI and is to be reflected in the Partners
Capital Accounts, the determination, recognition and
classification of any such item shall be the same as its
determination, recognition and classification for
U.S. federal income tax purposes (including any method of
depreciation, cost recovery or amortization used for that
purpose), provided, that:
(i) Solely for purposes of this Section 5.5, the
Partnership shall be treated as owning directly its
proportionate share (as determined by the General Partner based
upon the provisions of the applicable Group Member Agreement) of
all property owned by (x) any other Group Member that is
classified as a partnership for U.S. federal income tax
purposes and (y) any other partnership, limited liability
company, unincorporated business or other entity classified as a
partnership for U.S. federal income tax purposes of which a
Group Member is, directly or indirectly, a partner, member or
other equityholder.
(ii) All fees and other expenses incurred by the
Partnership to promote the sale of (or to sell) a Partnership
Interest that can neither be deducted nor amortized under
Section 709 of the Code, if any, shall, for purposes of
Capital Account maintenance, be treated as an item of deduction
at the time such fees and other expenses are incurred and shall
be allocated among the Partners pursuant to Section 6.1.
(iii) Except as otherwise provided in Treasury
Regulation Section 1.704-1(b)(2)(iv)(m),
the computation of all items of income, gain, loss, deduction,
Simulated Depletion, Simulated Gain and Simulated Loss shall be
made without regard to any election under Section 754 of
the Code that may be made by the Partnership and, as to those
items described in Section 705(a)(1)(B) or 705(a)(2)(B) of
the Code, without regard to the fact that such items
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are not includable in gross income or are neither currently
deductible nor capitalized for U.S. federal income tax
purposes. To the extent an adjustment to the adjusted tax basis
of any Partnership asset pursuant to Section 734(b) or
743(b) of the Code is required, pursuant to Treasury
Regulation Section 1.704-1(b)(2)(iv)(m),
to be taken into account in determining Capital Accounts, the
amount of such adjustment in the Capital Accounts shall be
treated as an item of gain or loss.
(iv) Any income, gain, loss, Simulated Gain or Simulated
Loss attributable to the taxable disposition of any Partnership
property shall be determined as if the adjusted basis of such
property as of such date of disposition were equal in amount to
the Partnerships Carrying Value with respect to such
property as of such date.
(v) In accordance with the requirements of
Section 704(b) of the Code, any deductions for
depreciation, cost recovery, amortization or Simulated Depletion
attributable to any Contributed Property shall be determined as
if the adjusted basis of such property on the date it was
acquired by the Partnership were equal to the Agreed Value of
such property. Upon an adjustment pursuant to
Section 5.5(d) to the Carrying Value of any Partnership
property subject to depreciation, cost recovery, amortization or
Simulated Depletion, any further deductions for such
depreciation, cost recovery, amortization or Simulated Depletion
attributable to such property shall be determined under the
rules prescribed by Treasury
Regulation Section 1.704-3(d)(2)
as if the adjusted basis of such property were equal to the
Carrying Value of such property immediately following such
adjustment.
(vi) The Gross Liability Value of each Liability of the
Partnership described in Treasury
Regulation Section 1.752-7(b)(3)(i)
shall be adjusted at such times as provided in this Agreement
for an adjustment to Carrying Values. The amount of any such
adjustment shall be treated for purposes hereof as an item of
loss (if the adjustment increases the Carrying Value of such
Liability of the Partnership) or an item of gain (if the
adjustment decreases the Carrying Value of such Liability of the
Partnership) and shall be taken into account for purposes of
computing Net Income and Net Loss.
(c) A transferee of a Partnership Interest shall succeed to
a Pro Rata portion of the Capital Account of the transferor
relating to the Partnership Interest so transferred.
(d) (i) In accordance with Treasury
Regulation Section 1.704-1(b)(2)(iv)(f),
upon an issuance of additional Partnership Interests for cash or
Contributed Property, the issuance of Partnership Interests as
consideration for the provision of services, or the conversion
of the Combined Interest to Common Units pursuant to
Section 11.3(b), the Carrying Value of each Partnership
property immediately prior to such issuance shall be adjusted
upward or downward to reflect any Unrealized Gain or Unrealized
Loss attributable to such Partnership property, and any such
Unrealized Gain or Unrealized Loss shall be treated, for
purposes of maintaining Capital Accounts, as if it had been
recognized on an actual sale of each such property for an amount
equal to its fair market value immediately prior to such
issuance and had been allocated among the Partners at such time
pursuant to Section 6.1(c) in the same manner as any item
of gain, loss, Simulated Gain or Simulated Loss actually
recognized following an event giving rise to the liquidation of
the Partnership would have been allocated; provided,
however, that in the event of an issuance of Partnership
Interests for a de minimis amount of cash or Contributed
Property, or in the event of an issuance of a de minimis amount
of Partnership Interests as consideration for the provision of
services, the General Partner may determine that such
adjustments are unnecessary for the proper administration of the
Partnership. In determining such Unrealized Gain or Unrealized
Loss, the aggregate fair market value of all Partnership
property (including cash or cash equivalents) immediately prior
to the issuance of additional Partnership Interests shall be
determined by the General Partner using such method of valuation
as it may adopt. In making its determination of the fair market
values of individual properties, the General Partner may
determine that it is appropriate to first determine an aggregate
value for the Partnership, based
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on the current trading price of the Common Units, and taking
fully into account the fair market value of the Partnership
Interests of all Partners at such time, and then allocate such
aggregate value among the individual properties of the
Partnership (in such manner as it determines appropriate).
(ii) In accordance with Treasury
Regulation Section 1.704-1(b)(2)(iv)(f),
immediately prior to any actual or deemed distribution to a
Partner of any Partnership property (other than a distribution
of cash that is not in redemption or retirement of a Partnership
Interest), the Carrying Value of all Partnership property shall
be adjusted upward or downward to reflect any Unrealized Gain or
Unrealized Loss attributable to such Partnership property, and
any such Unrealized Gain or Unrealized Loss shall be treated,
for purposes of maintaining Capital Accounts, as if it had been
recognized on an actual sale of each such property immediately
prior to such distribution for an amount equal to its fair
market value, and had been allocated among the Partners, at such
time, pursuant to Section 6.1(c) in the same manner as any
item of gain, loss, Simulated Gain or Simulated Loss actually
recognized following an event giving rise to the dissolution of
the Partnership would have been allocated. In determining such
Unrealized Gain or Unrealized Loss the aggregate fair market
value of all Partnership property (including cash or cash
equivalents) immediately prior to a distribution shall
(A) in the case of an actual distribution that is not made
pursuant to Section 12.4 or in the case of a deemed
distribution, be determined in the same manner as that provided
in Section 5.5(d)(i) or (B) in the case of a
liquidating distribution pursuant to Section 12.4, be
determined by the Liquidator using such method of valuation as
it may adopt.
Section 5.6 Issuances
of Additional Partnership Interests.
(a) The Partnership may issue additional Partnership
Interests and options, rights, warrants, restricted units,
appreciation rights, phantom or tracking interests or other
economic interests in the Partnership or interests in
Partnership Interests (including pursuant to
Section 7.4(c)) for any Partnership purpose at any time and
from time to time to such Persons for such consideration and on
such terms and conditions as the General Partner in its sole
discretion shall determine, all without the approval of any
Limited Partners.
(b) Each additional Partnership Interest or other security
authorized to be issued by the Partnership pursuant to
Section 5.6(a) or Section 7.4(c) may be issued in one
or more classes, or one or more series of any such classes, with
such designations, preferences, rights, powers and duties (which
may be senior or junior to existing classes and series of
Partnership Interests or other securities), as shall be fixed by
the General Partner, including (i) the right to share in
Partnership profits and losses or items thereof; (ii) the
right to share in Partnership distributions; (iii) rights
upon dissolution and liquidation of the Partnership;
(iv) whether, and the terms and conditions upon which, the
Partnership may or shall be required to redeem the Partnership
Interest or other security (including sinking fund provisions);
(v) whether such Partnership Interest or other security is
issued with the privilege of conversion or exchange and, if so,
the terms and conditions of such conversion or exchange;
(vi) the terms and conditions upon which each Partnership
Interest or other security will be issued, evidenced by
certificates and assigned or transferred; (vii) the method
for determining the Percentage Interest as to such Partnership
Interest or other security; and (viii) the right, if any,
of each such Partnership Interest or other security to vote on
Partnership matters, including matters relating to the relative
rights, preferences and privileges of such Partnership Interest
or other security.
(c) The General Partner shall take all actions that it
determines to be necessary or appropriate in connection with
(i) each issuance of Partnership Interests and options,
rights, warrants, restricted units, appreciation rights, phantom
or tracking interests or other economic interests in the
Partnership relating to Partnership Interests pursuant to this
Section 5.6 or Section 7.4(c), (ii) the
conversion of the General Partner Interest (represented by
Notional General Partner Units) into Units pursuant to the terms
of this Agreement, (iii) the admission of such additional
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Limited Partners and (iv) all additional issuances of
Partnership Interests or other securities. The General Partner
shall determine the relative rights, powers and duties of the
holders of the Units or other Partnership Interests or other
securities being so issued. The General Partner shall do all
things necessary to comply with the Delaware Act and is
authorized and directed to do all things that it determines to
be necessary or appropriate in connection with any future
issuance of Partnership Interests or other securities or in
connection with the conversion of the Combined Interest into
Units pursuant to the terms of this Agreement, including
compliance with any statute, rule, regulation or guideline of
any federal, state or other governmental agency or any National
Securities Exchange on which the Units or other Partnership
Interests or other securities are listed or admitted to trading.
(d) No fractional Units shall be issued by the Partnership.
Section 5.7 Limited
Preemptive Right.
Except as provided in this Section 5.7 and in
Section 5.2 or as otherwise provided in a separate
agreement by the Partnership, no Person shall have any
preemptive, preferential or other similar right with respect to
the issuance of any Partnership Interest or other security,
whether unissued, held in the treasury or hereafter created. The
General Partner shall have the right, in its sole discretion,
which it may from time to time assign in whole or in part to any
of its Affiliates, to purchase Partnership Interests from the
Partnership whenever, and on the same terms that, the
Partnership issues Partnership Interests to Persons other than
the General Partner and its Affiliates to the extent necessary
to maintain the Percentage Interests of the General Partner and
its Affiliates or the beneficial owners thereof or any of their
respective Affiliates equal to any or all of those Percentage
Interests that existed immediately prior to the issuance of such
Partnership Interests.
Section 5.8 Splits
and Combinations.
(a) Subject to Section 5.8(e), the Partnership may
make a Pro Rata distribution of Partnership Interests to all
Record Holders or may effect a subdivision or combination of
Partnership Interests so long as, after any such event, each
Partner shall have the same Percentage Interest in the
Partnership as before such event, and any amounts calculated on
a per Unit basis or stated as a number of Units are
proportionately adjusted.
(b) Whenever such a Pro Rata distribution, subdivision or
combination of Partnership Interests is declared, the General
Partner shall select a Record Date as of which the distribution,
subdivision or combination shall be effective and shall send
notice thereof at least 20 days prior to such Record Date
to each Record Holder as of a date not less than 10 days
prior to the date of such notice. The General Partner also may
cause a firm of independent public accountants selected by it to
calculate the number of Partnership Interests to be held by each
Record Holder after giving effect to such distribution,
subdivision or combination. The General Partner shall be
entitled to rely on any certificate provided by such firm as
conclusive evidence of the accuracy of such calculation.
(c) If a Pro Rata distribution of Partnership Interests, or
a subdivision or combination of Partnership Interests, is made
as contemplated in this Section 5.8, the number of Notional
General Partner Units constituting the Percentage Interest of
the General Partner (as determined immediately prior to the
Record Date for such distribution, subdivision or combination)
shall be appropriately adjusted as of the date of payment of
such distribution, or the effective date of such subdivision or
combination, to maintain such Percentage Interest of the General
Partner.
(d) Promptly following any such distribution, subdivision
or combination, the Partnership may issue Certificates or
uncertificated Partnership Interests to the Record Holders of
Partnership Interests, as of the applicable Record Date,
representing the new number of Partnership Interests held by
such Record Holders, or the General Partner may adopt such other
procedures
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that it determines to be necessary or appropriate to reflect
such changes. If any such combination results in a smaller total
number of Partnership Interests Outstanding, the Partnership
shall require, as a condition to the delivery to a Record Holder
of such new Certificate or uncertificated Partnership Interests,
the surrender of any Certificate held by such Record Holder
immediately prior to such Record Date.
(e) The Partnership shall not issue fractional Units or
Notional General Partner Units upon any distribution,
subdivision or combination of Units. If a distribution,
subdivision or combination of Units would result in the issuance
of fractional Units or Notional General Partner Units but for
the provisions of Section 5.6(d) and this
Section 5.8(e), each fractional Unit shall be rounded to
the nearest whole Unit or Notional General Partner Unit (and a
0.5 Unit shall be rounded to the next higher Unit or Notional
General Partner Unit).
Section 5.9 Fully
Paid and Non-Assessable Nature of Limited Partner Interests.
All Limited Partner Interests issued pursuant to, and in
accordance with the requirements of, this Article V shall
be fully paid and non-assessable Limited Partner Interests in
the Partnership, except as such non-assessability may be
affected by the Delaware Act.
ARTICLE VI
ALLOCATIONS
AND DISTRIBUTIONS
Section 6.1 Allocations
for Capital Account Purposes.
For purposes of maintaining the Capital Accounts and in
determining the rights of the Partners among themselves, the
Partnerships items of income, gain, loss, deduction,
Simulated Depletion, Simulated Gain and Simulated Loss (computed
in accordance with Section 5.5(b)) for each taxable period
shall be allocated among the Partners as provided herein below.
(a) Net Income. After giving effect to
the special allocations set forth in Sections 6.1(d) and
(e) and any allocations to other Partnership Interests, Net
Income for each taxable period and all items of income, gain,
loss, deduction, and Simulated Gain taken into account in
computing Net Income for such taxable period shall be allocated
as follows:
(i) First, 100% to the General Partner until the
General Partner has been allocated cumulative Net Income for the
current and all prior taxable periods equal to the cumulative
Net Loss previously allocated to the General Partner pursuant to
Section 6.1(b)(ii); and
(ii) Second, to all Partners, Pro Rata.
(b) Net Loss. After giving effect to the
special allocations set forth in Sections 6.1(d) and
(e) and any allocations to other Partnership Interests, Net
Loss for each taxable period and all items of income, gain,
loss, deduction and Simulated Gain taken into account in
computing Net Loss for such taxable period shall be allocated as
follows:
(i) First, to all Partners, Pro Rata; provided,
however, that Net Loss shall not be allocated pursuant to
this Section 6.1(b) to the extent that such allocation
would cause any Unitholder to have a deficit balance in its
Adjusted Capital Account at the end of such taxable period (or
increase any existing deficit balance in its Adjusted Capital
Account); and
(ii) Second, 100% to the General Partner.
(c) Net Termination Gains and
Losses. After giving effect to the special
allocations set forth in Sections 6.1(d) and (e) and
any allocations to other Partnership Interests, Net Termination
Gain or Net Termination Loss (including a pro rata part of each
item of income, gain, loss, deduction, and Simulated Gain taken
into account in computing Net Termination Gain or Net
Termination Loss) for such taxable period shall be allocated in
the manner set forth in this Section 6.1(c). All
allocations under this Section 6.1(c) shall be made after
Capital Account
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balances have been adjusted by all other allocations provided
under this Section 6.1 and after all distributions of
Available Cash provided under Section 6.3 have been made;
provided, however, that solely for purposes of this
Section 6.1(c), Capital Accounts shall not be adjusted for
distributions made pursuant to Section 12.4.
(i) If a Net Termination Gain (including a pro rata part of
each item of income, gain, loss, deduction and Simulated Gain
taken into account in computing Net Termination Gain) is
recognized, such Net Termination Gain shall be allocated in the
following manner:
(A) First, to each Partner having a deficit balance
in its Capital Account in the proportion that such deficit bears
to the total deficit balances in the Capital Accounts of all
Partners, until each Partner has been allocated Net Termination
Gain equal to any such deficit in its Capital Account; and
(B) Second, to all Partners, Pro Rata.
(ii) If a Net Termination Loss is recognized, such Net
Termination Loss shall be allocated among the Partners in the
following manner:
(A) First, 100% to all Partners, Pro Rata, until the
Capital Account in respect of each Common Unit then Outstanding
has been reduced to zero; and
(B) Second, the balance, if any, 100% to the General
Partner.
(d) Special Allocations. Notwithstanding
any other provision of this Section 6.1, the following
special allocations shall be made for such taxable period:
(i) Partnership Minimum Gain
Chargeback. Notwithstanding any other provision
of this Section 6.1, if there is a net decrease in
Partnership Minimum Gain during any Partnership taxable period,
each Partner shall be allocated items of Partnership income,
gain and Simulated Gain for such period (and, if necessary,
subsequent periods) in the manner and amounts provided in
Treasury
Regulation Sections 1.704-2(f)(6),
1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision.
For purposes of this Section 6.1(d), each Partners
Adjusted Capital Account balance shall be determined, and the
allocation of income, gain or Simulated Gain required hereunder
shall be effected, prior to the application of any other
allocations pursuant to this Section 6.1(d) with respect to
such taxable period (other than an allocation pursuant to
Section 6.1(d)(v) and Section 6.1(d)(vi)). This
Section 6.1(d)(i) is intended to comply with the
Partnership Minimum Gain chargeback requirement in Treasury
Regulation Section 1.704-2(f)
and shall be interpreted consistently therewith.
(ii) Chargeback of Partner Nonrecourse Debt Minimum
Gain. Notwithstanding the other provisions of
this Section 6.1 (other than Section 6.1(d)(i)),
except as provided in Treasury
Regulation Section 1.704-2(i)(4),
if there is a net decrease in Partner Nonrecourse Debt Minimum
Gain during any Partnership taxable period, any Partner with a
share of Partner Nonrecourse Debt Minimum Gain at the beginning
of such taxable period shall be allocated items of Partnership
income, gain and Simulated Gain for such period (and, if
necessary, subsequent periods) in the manner and amounts
provided in Treasury
Regulation Sections 1.704-2(i)(4)
and 1.704-2(j)(2)(ii), or any successor provisions. For purposes
of this Section 6.1(d), each Partners Adjusted
Capital Account balance shall be determined, and the allocation
of income, gain or Simulated Gain required hereunder shall be
effected, prior to the application of any other allocations
pursuant to this Section 6.1(d), other than
Section 6.1(d)(i) and other than an allocation pursuant to
Section 6.1(d)(v) and Section 6.1(d)(vi), with respect
to such taxable period. This Section 6.1(d)(ii) is intended
to comply with the chargeback of items of income and gain
requirement in Treasury
Regulation Section 1.704-2(i)(4)
and shall be interpreted consistently therewith.
(iii) Qualified Income Offset. In the
event any Partner unexpectedly receives any adjustments,
allocations or distributions described in Treasury
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Regulation Sections 1.704-1(b)(2)(ii)(d)(4),
1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of
Partnership gross income and gain shall be specially allocated
to such Partner in an amount and manner sufficient to eliminate,
to the extent required by the Treasury Regulations promulgated
under Section 704(b) of the Code, the deficit balance, if
any, in its Adjusted Capital Account created by such
adjustments, allocations or distributions as quickly as
possible; provided, however, that an allocation
pursuant to this Section 6.1(d)(iii) shall be made only if
and to the extent that such Partner would have a deficit balance
in its Adjusted Capital Account as adjusted after all other
allocations provided for in this Section 6.1 have been
tentatively made as if this Section 6.1(d)(iii) were not in
this Agreement.
(iv) Gross Income Allocation. In the
event any Partner has a deficit balance in its Capital Account
at the end of any taxable period in excess of the sum of
(A) the amount such Partner is required to restore pursuant
to the provisions of this Agreement and (B) the amount such
Partner is deemed obligated to restore pursuant to Treasury
Regulation Sections 1.704-2(g)
and 1.704-2(i)(5), such Partner shall be specially allocated
items of the Partnerships gross income, gain and Simulated
Gain in the amount of such excess as quickly as possible;
provided, however, that an allocation pursuant to
this Section 6.1(d)(iv) shall be made only if and to the
extent that such Partner would have a deficit balance in its
Capital Account as adjusted after all other allocations provided
for in this Section 6.1 have been tentatively made as if
Section 6.1(d)(iii) and this Section 6.1(d)(iv) were
not in this Agreement.
(v) Nonrecourse Deductions. Nonrecourse
Deductions for any taxable period shall be allocated to the
Partners Pro Rata. If the General Partner determines that the
Partnerships Nonrecourse Deductions should be allocated in
a different ratio to satisfy the safe harbor requirements of the
Treasury Regulations promulgated under Section 704(b) of
the Code, the General Partner is authorized, upon notice to the
other Partners, to revise the prescribed ratio to the
numerically closest ratio that does satisfy such requirements.
(vi) Partner Nonrecourse
Deductions. Partner Nonrecourse Deductions for
any taxable period shall be allocated 100% to the Partner that
bears the Economic Risk of Loss with respect to the Partner
Nonrecourse Debt to which such Partner Nonrecourse Deductions
are attributable in accordance with Treasury
Regulation Section 1.704-2(i).
If more than one Partner bears the Economic Risk of Loss with
respect to a Partner Nonrecourse Debt, such Partner Nonrecourse
Deductions attributable thereto shall be allocated between or
among such Partners in accordance with the ratios in which they
share such Economic Risk of Loss.
(vii) Nonrecourse Liabilities. For
purposes of Treasury
Regulation Section 1.752-3(a)(3),
the Partners agree that Nonrecourse Liabilities of the
Partnership in excess of the sum of (A) the amount of
Partnership Minimum Gain and (B) the total amount of
Nonrecourse Built-in Gain shall be allocated among the Partners
Pro Rata.
(viii) Code Section 754
Adjustments. To the extent an adjustment to the
adjusted tax basis of any Partnership asset pursuant to
Section 734(b) or 743(b) of the Code is required, pursuant
to Treasury
Regulation Section 1.704-1(b)(2)(iv)(m),
to be taken into account in determining Capital Accounts, the
amount of such adjustment to the Capital Accounts shall be
treated as an item of gain or Simulated Gain (if the adjustment
increases the basis of the asset) or loss or Simulated Loss (if
the adjustment decreases such basis), and such item of gain,
loss Simulated Gain or Simulated Loss shall be specially
allocated to the Partners in a manner consistent with the manner
in which their Capital Accounts are required to be adjusted
pursuant to such Section of the Treasury Regulations.
(ix) Curative Allocation.
(A) Notwithstanding any other provision of this
Section 6.1, other than the Required Allocations, the
Required Allocations shall be taken into account in making the
Agreed
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Allocations so that, to the extent possible, the net amount of
items of gross income, gain, loss, deduction Simulated
Depletion, Simulated Gain and Simulated Loss allocated to each
Partner pursuant to the Required Allocations and the Agreed
Allocations, together, shall be equal to the net amount of such
items that would have been allocated to each such Partner under
the Agreed Allocations had the Required Allocations and the
related Curative Allocation not otherwise been provided in this
Section 6.1 and Simulated Depletion and Simulated Loss had
been included in the definition of Net Income, Net Loss, Net
Termination Gain and Net Termination Loss. Notwithstanding the
preceding sentence, Required Allocations relating to
(1) Nonrecourse Deductions shall not be taken into account
except to the extent there has been a decrease in Partnership
Minimum Gain and (2) Partner Nonrecourse Deductions shall
not be taken into account except to the extent there has been a
decrease in Partner Nonrecourse Debt Minimum Gain. In exercising
its discretion under this Section 6.1(d)(ix)(A), the
General Partner may take into account future Required
Allocations that, although not yet made, are likely to offset
other Required Allocations previously made. Allocations pursuant
to this Section 6.1(d)(ix)(A) shall only be made with
respect to Required Allocations to the extent the General
Partner determines that such allocations will otherwise be
inconsistent with the economic agreement among the Partners.
Further, allocations pursuant to this Section 6.1(d)(ix)(A)
shall be deferred with respect to allocations pursuant to
clauses (1) and (2) hereof to the extent the General
Partner determines that such allocations are likely to be offset
by subsequent Required Allocations.
(B) The General Partner shall, with respect to each taxable
period, (1) apply the provisions of
Section 6.1(d)(ix)(A) in whatever order is most likely to
minimize the economic distortions that might otherwise result
from the Required Allocations, and (2) divide all
allocations pursuant to Section 6.1(d)(ix)(A) among the
Partners in a manner that is likely to minimize such economic
distortions.
(x) Priority Allocations. If the amount
of cash or the Net Agreed Value of any property distributed
(except cash or property distributed pursuant to
Section 12.4) with respect to a Unit exceeds the amount of
cash or the Net Agreed Value of property distributed with
respect to another Unit (the amount of the excess, an
Excess Distribution and the Unit with
respect to which the greater distribution is paid, an
Excess Distribution Unit), then
(1) there shall be allocated gross income and gain to each
Unitholder receiving an Excess Distribution with respect to the
Excess Distribution Unit until the aggregate amount of such
items allocated with respect to such Excess Distribution Unit
pursuant to this Section 6.1(d)(x) for the current taxable
period and all previous taxable periods is equal to the amount
of the Excess Distribution; and (2) the General Partner
shall be allocated gross income and gain with respect to each
such Excess Distribution in an amount equal to the product
obtained by multiplying (aa) the quotient determined by dividing
(x) the General Partners Percentage Interest at the
time when the Excess Distribution occurs by (y) a
percentage equal to 100% less the General Partners
Percentage Interest at the time when the Excess Distribution
occurs, times (bb) the amount allocated in clause (1) above
with respect to such Excess Distribution.
(xi) Economic Uniformity; Changes in
Law. For the proper administration of the
Partnership and for the preservation of uniformity of the
Limited Partner Interests (or any class or classes thereof), the
General Partner shall (i) adopt such conventions as it
deems appropriate in determining the amount of depreciation,
amortization and cost recovery deductions; (ii) make
special allocations of income, gain, loss or deduction,
including Unrealized Gain or Unrealized Loss; and
(iii) amend the provisions of this Agreement as appropriate
(x) to reflect the proposal or promulgation of Treasury
Regulations under Section 704(b) or Section 704(c) of
the Code or (y) otherwise to preserve or achieve uniformity
of the Limited Partner Interests (or any class or classes
thereof). The General Partner may adopt such conventions, make
such allocations and make such amendments to this Agreement as
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provided in this Section 6.1(b)(xi) only if such
conventions, allocations or amendments would not have a material
adverse effect on the Partners, the holders of any class or
classes of Outstanding Limited Partner Interests or the
Partnership, and if such allocations are consistent with the
principles of Section 704 of the Code.
(e) Simulated Depletion and Simulated Loss.
(i) In accordance with Treasury
Regulation Section 1.704-1(b)(2)(iv)(k),
Simulated Depletion with respect to each oil and gas property
shall be allocated among the Partners, Pro Rata.
(ii) Simulated Loss with respect to the disposition of an
oil and gas property shall be allocated among the Partners in
proportion to their allocable share of total amount realized
from such disposition under Section 6.2(c)(i).
Section 6.2 Allocations
for Tax Purposes.
(a) Except as otherwise provided herein, for federal income
tax purposes, each item of income, gain, loss and deduction
shall be allocated among the Partners in the same manner as its
correlative item of book income, gain, loss or
deduction is allocated pursuant to Section 6.1.
(b) The deduction for depletion with respect to each
separate oil and gas property (as defined in Section 614 of
the Code) shall be computed for federal income tax purposes
separately by the Partners rather than by the Partnership in
accordance with Section 613A(c)(7)(D) of the Code. Except
as provided in Section 6.2(c)(iii), for purposes of such
computation (before taking into account any adjustments
resulting from an election made by the Partnership under
Section 754 of the Code), the adjusted tax basis of each
oil and gas property (as defined in Section 614 of the
Code) shall be allocated among the Partners Pro Rata. Each
Partner shall separately keep records of his share of the
adjusted tax basis in each oil and gas property, allocated as
provided above, adjust such share of the adjusted tax basis for
any cost or percentage depletion allowable with respect to such
property, and use such adjusted tax basis in the computation of
its cost depletion or in the computation of his gain or loss on
the disposition of such property by the Partnership.
(c) Except as provided in Section 6.2(c)(iii), for the
purposes of the separate computation of gain or loss by each
Partner on the sale or disposition of each separate oil and gas
property (as defined in Section 614 of the Code), the
Partnerships allocable share of the amount
realized (as such term is defined in Section 1001(b)
of the Code) from such sale or disposition shall be allocated
for federal income tax purposes among the Partners as follows:
(i) first, to the extent such amount realized
constitutes a recovery of the Simulated Basis of the property,
to the Partners in the same proportion as the depletable basis
of such property was allocated to the Partners pursuant to
Section 6.2(b) (without regard to any special allocation of
basis under Section 6.2(c)(iii));
(ii) second, the remainder of such amount realized,
if any, to the Partners so that, to the maximum extent possible,
the amount realized allocated to each Partner under this
Section 6.2(c)(ii) will equal such Partners share of
the Simulated Gain recognized by the Partnership from such sale
or disposition.
(iii) The Partners recognize that with respect to
Contributed Property and Adjusted Property there will be a
difference between the Carrying Value of such property at the
time of contribution or revaluation, as the case may be, and the
adjusted tax basis of such property at that time. All items of
tax depreciation, cost recovery, amortization, adjusted tax
basis of depletable properties, amount realized and gain or loss
with respect to such Contributed Property and Adjusted Property
shall be allocated among the Partners to take into account the
disparities between the Carrying Values and the adjusted tax
basis with respect to such properties in accordance with the
principles of Treasury
Regulation Section 1.704-3(d).
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(d) In an attempt to eliminate Book-Tax Disparities
attributable to a Contributed Property or Adjusted Property,
other than oil and gas properties pursuant to
Section 6.2(c), items of income, gain, loss, depreciation,
amortization and cost recovery deductions shall be allocated for
federal income tax purposes among the Partners in the manner
provided under Section 704(c) of the Code, and the Treasury
Regulations promulgated under Section 704(b) and 704(c) of
the Code, as determined appropriate by the General Partner;
provided, however, that the General Partner shall apply
the principles of Treasury
Regulation Section 1.704-3(d)
in all events.
(e) The General Partner may determine to depreciate or
amortize the portion of an adjustment under Section 743(b)
of the Code attributable to unrealized appreciation in any
Adjusted Property (to the extent of the unamortized Book-Tax
Disparity) using a predetermined rate derived from the
depreciation or amortization method and useful life applied to
the unamortized Book-Tax Disparity of such property, despite any
inconsistency of such approach with Treasury
Regulation Section 1.167(c)-l(a)(6)
or any successor regulations thereto. If the General Partner
determines that such reporting position cannot reasonably be
taken, the General Partner may adopt depreciation and
amortization conventions under which all purchasers acquiring
Limited Partner Interests in the same month would receive
depreciation and amortization deductions, based upon the same
applicable rate as if they had purchased a direct interest in
the Partnerships property. If the General Partner chooses
not to utilize such aggregate method, the General Partner may
use any other depreciation and amortization conventions to
preserve the uniformity of the intrinsic tax characteristics of
any Limited Partner Interests, so long as such conventions would
not have a material adverse effect on the Limited Partners or
the Record Holders of any class or classes of Limited Partner
Interests.
(f) In accordance with Treasury
Regulation Sections 1.1245-1(e)
and 1.1250-1(f), any gain allocated to the Partners upon the
sale or other taxable disposition of any Partnership asset
shall, to the extent possible, after taking into account other
required allocations of gain pursuant to this Section 6.2,
be characterized as Recapture Income in the same proportions and
to the same extent as such Partners (or their predecessors in
interest) have been allocated any deductions directly or
indirectly giving rise to the treatment of such gains as
Recapture Income.
(g) All items of income, gain, loss, deduction and credit
recognized by the Partnership for federal income tax purposes
and allocated to the Partners in accordance with the provisions
hereof shall be determined without regard to any election under
Section 754 of the Code that may be made by the
Partnership; provided, however, that such allocations,
once made, shall be adjusted (in the manner determined by the
General Partner) to take into account those adjustments
permitted or required by Sections 734 and 743 of the Code.
(h) Each item of Partnership income, gain, loss and
deduction shall, for federal income tax purposes, be determined
for each taxable period and prorated on a monthly basis and
shall be allocated to the Partners as of the opening of the
National Securities Exchange on which the Partnership Interests
are listed or admitted to trading on the first Business Day of
each month; provided, however, such items for the
period beginning on the Closing Date and ending on the last day
of the month in which the Over-Allotment Option is exercised in
full or the expiration of the Over-Allotment Option occurs shall
be allocated to the Partners as of the opening of the National
Securities Exchange on which the Partnership Interests are
listed or admitted to trading on the first Business Day of the
next succeeding month; and provided further, that gain or
loss on a sale or other disposition of any assets of the
Partnership or any other extraordinary item of gross income,
gain, loss or deduction as determined by the General Partner,
shall be allocated to the Partners as of the opening of the
National Securities Exchange on which the Partnership Interests
are listed or admitted to trading on the first Business Day of
the month in which such item is recognized for federal income
tax purposes. The General Partner may revise, alter or otherwise
modify such methods of allocation to the extent permitted or
required by Section 706 of the Code and the regulations or
rulings promulgated thereunder.
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(i) Allocations that would otherwise be made to a Limited
Partner under the provisions of this Article VI shall
instead be made to the beneficial owner of Limited Partner
Interests held by a nominee in any case in which the nominee has
furnished the identity of such owner to the Partnership in
accordance with Section 6031(c) of the Code or any other
method determined by the General Partner.
Section 6.3 Requirement
of Distributions; Distributions to Record Holders.
(a) Subject to Section 6.3(b), within 45 days
following the end of each Quarter commencing with the Quarter
ending December 31, 2011, an amount equal to 100% of
Available Cash with respect to such Quarter shall be distributed
in accordance with this Article VI by the Partnership to
the Partners in accordance with their Percentage Interest as of
the Record Date selected by the General Partner. Notwithstanding
any provision to the contrary contained in this Agreement, the
Partnership shall not be required to make a distribution to any
Partner on account of its interest in the Partnership if such
distribution would violate the Delaware Act or any other
applicable law.
(b) Notwithstanding Section 6.3(a), in the event of
the dissolution and liquidation of the Partnership, all assets
received by the Partnership during or after the Quarter in which
the Liquidation Date occurs shall be applied and distributed
solely in accordance with, and subject to the terms and
conditions of, Section 12.4.
(c) The General Partner may treat taxes paid by the
Partnership on behalf of, or amounts withheld with respect to,
all or less than all of the Partners, as a distribution of
Available Cash to such Partners.
(d) Each distribution in respect of a Partnership Interest
shall be paid by the Partnership, directly or through the
Transfer Agent or through any other Person or agent, only to the
Record Holder of such Partnership Interest as of the Record Date
set for such distribution. Such payment shall constitute full
payment and satisfaction of the Partnerships liability in
respect of such payment, regardless of any claim of any Person
who may have an interest in such payment by reason of an
assignment or otherwise.
ARTICLE VII
MANAGEMENT
AND OPERATION OF BUSINESS
Section 7.1 Management.
(a) The General Partner shall conduct, direct and manage
all activities of the Partnership. Except as otherwise expressly
provided in this Agreement, but without limitation on the
ability of the General Partner to delegate its rights and powers
to other Persons, all management powers over the business and
affairs of the Partnership shall be exclusively vested in the
General Partner, and no Limited Partner shall have any
management power over the business and affairs of the
Partnership. In addition to the powers now or hereafter granted
a general partner of a limited partnership under applicable law
or that are granted to the General Partner under any other
provision of this Agreement, the General Partner, subject to
Section 7.3, shall have full power and authority to do all
things, and on such terms, as it determines to be necessary or
appropriate to conduct the business of the Partnership, to
exercise all powers set forth in Section 2.5 and to
effectuate the purposes set forth in Section 2.4, including
the following:
(i) the making of any expenditures, the lending or
borrowing of money, the assumption or guarantee of, or other
contracting for, indebtedness and other liabilities, the
issuance of evidences of indebtedness, including indebtedness
that is convertible or exchangeable into Partnership Interests,
and the incurring of any other obligations;
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(ii) the making of tax, regulatory and other filings, or
rendering of periodic or other reports to governmental or other
agencies having jurisdiction over the business or assets of the
Partnership;
(iii) the acquisition, disposition, mortgage, pledge,
encumbrance, hypothecation or exchange of any or all of the
assets of the Partnership or the merger or other combination of
the Partnership with or into another Person (the matters
described in this clause (iii) being subject, however, to
any prior approval that may be required by Section 7.3 or
Article XIV);
(iv) the use of the assets of the Partnership (including
cash on hand) for any purpose consistent with the terms of this
Agreement, including (A) the financing of the conduct of
the operations of the Partnership Group, (B) subject to
Section 7.6(a), the lending of funds to other Persons
(including other Group Members), (C) the repayment or
guarantee of obligations of any Group Member and (D) the
making of capital contributions to any Group Member;
(v) the negotiation, execution and performance of any
contracts, conveyances or other instruments (including
instruments that limit the liability of the Partnership under
contractual arrangements to all or particular assets of the
Partnership, with the other party to the contract to have no
recourse against the General Partner or its assets other than
its interest in the Partnership, even if the same results in the
terms of the transaction being less favorable to the Partnership
than would otherwise be the case);
(vi) the distribution of Partnership cash;
(vii) the selection, employment, retention and dismissal of
employees (including employees having titles such as chief
executive officer, president, chief
financial officer, chief operating officer,
general counsel, vice president,
secretary and treasurer) and agents,
outside attorneys, accountants, consultants and contractors of
the General Partner or the Partnership Group and the
determination of their compensation and other terms of
employment or hiring;
(viii) the maintenance of insurance for the benefit of the
Partnership Group, the Partners and Indemnitees;
(ix) the formation of, or acquisition of an interest in,
and the contribution of property and the making of loans to, any
further limited or general partnerships, joint ventures,
corporations, limited liability companies or other Persons
(including the acquisition of interests in, and the
contributions of property to, any Group Member from time to
time) subject to the restrictions set forth in Section 2.4;
(x) the control of any matters affecting the rights and
obligations of the Partnership, including the bringing and
defending of actions at law or in equity and otherwise engaging
in the conduct of litigation, arbitration or mediation and the
incurring of legal expense and the settlement of claims and
litigation;
(xi) the indemnification of any Person against liabilities
and contingencies to the extent permitted by law;
(xii) the entering into of listing agreements with any
National Securities Exchange and the delisting of some or all of
the Limited Partner Interests from, or requesting that trading
be suspended on, any such exchange (subject to any prior
approval that may be required under Section 4.7);
(xiii) the purchase, sale or other acquisition or
disposition of Partnership Interests, or the issuance of
options, rights, warrants, restricted units, appreciation
rights, phantom or tracking interests or other economic
interests in the Partnership or relating to Partnership
Interests;
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(xiv) the undertaking of any action in connection with the
Partnerships participation in the management of any Group
Member; and
(xv) the entering into of agreements with any of its
Affiliates to render services to a Group Member or to itself in
the discharge of its duties as General Partner of the
Partnership.
(b) Notwithstanding any other provision of this Agreement,
any Group Member Agreement, the Delaware Act or any applicable
law, rule or regulation, each of the Partners and each other
Person who may acquire an interest in Partnership Interests or
is otherwise bound by this Agreement hereby (i) approves,
ratifies and confirms the execution, delivery and performance by
the parties thereto of this Agreement, any Group Member
Agreement, the Underwriting Agreement, the Contribution and
Merger Agreement, the Services Agreement, the Omnibus Agreement
and the other agreements described in or filed as exhibits to
the Registration Statement that are related to the transactions
contemplated by the Registration Statement (in each case other
than this Agreement, without giving effect to any amendments,
supplements or restatements after the date hereof);
(ii) agrees that the General Partner (on its own or on
behalf of the Partnership) is authorized to execute, deliver and
perform the agreements referred to in clause (i) of this
sentence and the other agreements, acts, transactions and
matters described in or contemplated by the Registration
Statement on behalf of the Partnership without any further act,
approval or vote of the Partners or the other Persons who may
acquire an interest in Partnership Interests or are otherwise
bound by this Agreement; and (iii) agrees that the
execution, delivery or performance by the General Partner, any
Group Member or any Affiliate of any of them of this Agreement
or any agreement authorized or permitted under this Agreement
(including the exercise by the General Partner or any Affiliate
of the General Partner of the rights accorded pursuant to
Article XV) shall not constitute a breach by the
General Partner of any duty that the General Partner may owe the
Partnership or the Limited Partners or any other Persons under
this Agreement (or any other agreements) or of any duty existing
at law, in equity or otherwise.
Section 7.2 Certificate
of Limited Partnership.
The General Partner has caused the Certificate of Limited
Partnership to be filed with the Secretary of State of the State
of Delaware as required by the Delaware Act. The General Partner
shall use all reasonable efforts to cause to be filed such other
certificates or documents that the General Partner determines to
be necessary or appropriate for the formation, continuation,
qualification and operation of a limited partnership (or a
partnership in which the limited partners have limited
liability) in the State of Delaware or any other state in which
the Partnership may elect to do business or own property. To the
extent the General Partner determines such action to be
necessary or appropriate, the General Partner shall file
amendments to and restatements of the Certificate of Limited
Partnership and do all things to maintain the Partnership as a
limited partnership (or a partnership or other entity in which
the limited partners have limited liability) under the laws of
the State of Delaware or of any other state in which the
Partnership may elect to do business or own property. Subject to
the terms of Section 3.4(a), the General Partner shall not
be required, before or after filing, to deliver or mail a copy
of the Certificate of Limited Partnership, any qualification
document or any amendment thereto to any Limited Partner.
Section 7.3 Restrictions
on the General Partners Authority.
Except as provided in Article XII and Article XIV, the
General Partner may not sell, exchange or otherwise dispose of
all or substantially all of the assets of the Partnership Group,
taken as a whole, in a single transaction or a series of related
transactions (including by way of merger, consolidation or other
combination or sale of ownership interests of the
Partnerships Subsidiaries) without the approval of the
holders of a Unit Majority; provided, however, that this
provision shall not preclude or limit the General Partners
ability to mortgage, pledge, hypothecate or grant a security
interest in all or substantially all of the assets of the
Partnership Group
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and shall not apply to any forced sale of any or all of the
assets of the Partnership Group pursuant to the foreclosure of,
or other realization upon, any such encumbrance.
Section 7.4 Reimbursement
of the General Partner.
(a) Except as provided in this Section 7.4 and
elsewhere in this Agreement, the General Partner shall not be
compensated for its services as a general partner or managing
member of any Group Member.
(b) The General Partner shall be reimbursed on a monthly
basis, or such other basis as the General Partner may determine,
for (i) all direct and indirect expenses it incurs or
payments it makes on behalf of the Partnership Group (including
salary, bonus, incentive compensation, employment benefits and
other amounts paid to any Person, including Affiliates of the
General Partner to perform services for the Partnership Group or
for the General Partner in the discharge of its duties to the
Partnership Group), and (ii) all other expenses allocable
to the Partnership Group or otherwise incurred by the General
Partner in connection with operating the Partnership
Groups business (including expenses allocated to the
General Partner by its Affiliates). The General Partner shall
determine the expenses that are allocable to the General Partner
or the Partnership Group. Reimbursements pursuant to this
Section 7.4 shall be in addition to any reimbursement to
the General Partner as a result of indemnification pursuant to
Section 7.7.
(c) Subject to the applicable rules and regulations of the
National Securities Exchange on which the Common Units are
listed, the General Partner, without the approval of the Limited
Partners (who shall have no other right to vote in respect
thereof under this Agreement), may propose and adopt on behalf
of the Partnership benefit plans, programs and practices
(including plans, programs and practices involving the issuance
of Partnership Interests or options to purchase or rights,
warrants or appreciation rights or phantom or tracking interests
or other economic interests in the Partnership or relating to
Partnership Interests), or cause the Partnership to issue
Partnership Interests in connection with, or pursuant to, any
benefit plan, program or practice maintained or sponsored by the
General Partner or any of its Affiliates, in each case for the
benefit of employees and directors of the General Partner or any
of its Affiliates, in respect of services performed, directly or
indirectly, for the benefit of the Partnership Group. The
Partnership agrees to issue and sell to the General Partner or
any of its Affiliates any Partnership Interests or other
securities that the General Partner or such Affiliates are
obligated to provide to any employees, officers and directors
pursuant to any such benefit plans, programs or practices.
Expenses incurred by the General Partner in connection with any
such benefit plans, programs and practices (including the net
cost to the General Partner or such Affiliates of Partnership
Interests or other securities purchased by the General Partner
or such Affiliates from the Partnership to fulfill options or
awards under such plans, programs and employee practices) shall
be reimbursed in accordance with Section 7.4(b). Any and
all obligations of the General Partner under any employee
benefit plans, employee programs or employee practices adopted
by the General Partner as permitted by this Section 7.4(c)
shall constitute obligations of the General Partner hereunder
and shall be assumed by any successor General Partner approved
pursuant to Section 11.1 or Section 11.2 or the
transferee of or successor to all of the General Partners
General Partner Interest pursuant to Section 4.6.
Section 7.5 Outside
Activities.
(a) The General Partner, for so long as it is the General
Partner of the Partnership, (i) agrees that its sole
business will be to act as a general partner or managing member,
as the case may be, of the Partnership and any other partnership
or limited liability company of which the Partnership is,
directly or indirectly, a partner or member and to undertake
activities that are ancillary or related thereto (including
being a Limited Partner in the Partnership) and (ii) shall
not engage in any business or activity or incur any debts or
liabilities except in connection with or incidental to
(A) its performance as general partner or managing member,
if any, of one or
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more Group Members or as described in or contemplated by the
Registration Statement, (B) the acquiring, owning or
disposing of debt securities or equity interests in any Group
Member or (C) the guarantee of, and mortgage, pledge, or
encumbrance of any or all of its assets in connection with, any
indebtedness of the General Partner or any of its Affiliates.
(b) Each Unrestricted Person (other than the General
Partner) shall have the right to engage in businesses of every
type and description and other activities for profit and to
engage in and possess an interest in other business ventures of
any and every type or description, whether in businesses engaged
in or anticipated to be engaged in by any Group Member,
independently or with others, including business interests and
activities in direct competition with the business and
activities of any Group Member, and none of the same shall
constitute a breach of this Agreement or any duty otherwise
existing at law, in equity or otherwise, to any Group Member or
any Partner. None of the Group Members, any Limited Partner or
any other Person shall have any rights by virtue of this
Agreement, any Group Member Agreement, or the partnership
relationship established hereby in any business ventures of any
Unrestricted Person.
(c) Subject to the terms of Sections 7.5(a) and
7.5(b), but otherwise notwithstanding anything to the contrary
in this Agreement, (i) the engaging in competitive
activities by any Unrestricted Person (other than the General
Partner) in accordance with the provisions of this
Section 7.5 is hereby approved by the Partnership and all
Partners, (ii) it shall be deemed not to be a breach of any
fiduciary duty or any other obligation of any type whatsoever of
the General Partner or any other Unrestricted Person for any
Unrestricted Person (other than the General Partner) to engage
in such business interests and activities in preference to or to
the exclusion of the Partnership and (iii) no Unrestricted
Person shall have any obligation hereunder or as a result of any
duty otherwise existing at law, in equity or otherwise, to
present business opportunities to the Partnership.
Notwithstanding anything to the contrary in this Agreement, the
doctrine of corporate opportunity, or any analogous doctrine,
shall not apply to any Unrestricted Person (including the
General Partner). No Unrestricted Person (including the General
Partner) who acquires knowledge of a potential transaction,
agreement, arrangement or other matter that may be an
opportunity for any Group Member, shall have any duty to
communicate or offer such opportunity to any Group Member, and
such Unrestricted Person (including the General Partner) shall
not be liable to the Partnership, any Limited Partner, any
Person who acquires an interest in a Partnership Interest or any
other Person who is bound by this Agreement for breach of any
fiduciary or other duty by reason of the fact that such
Unrestricted Person (including the General Partner) pursues or
acquires such opportunity for itself, directs such opportunity
to another Person or does not communicate such opportunity or
information to any Group Member; provided,
however, such Unrestricted Person does not engage in such
business or activity as a result of or using confidential or
proprietary information provided by or on behalf of the
Partnership to such Unrestricted Person.
(d) The General Partner and each of its Affiliates may
acquire Units or other Partnership Interests or securities in
addition to those acquired on the Closing Date and, except as
otherwise provided in this Agreement, shall be entitled to
exercise, at their option, all rights relating to all Units
and/or other
Partnership Interests or securities acquired by them. The term
Affiliates when used in this
Section 7.5(d) with respect to the General Partner shall
not include any Group Member.
Section 7.6 Loans
from the General Partner; Loans or Contributions from the
Partnership or Group Members.
(a) The General Partner or any of its Affiliates may, but
shall be under no obligation to, lend to any Group Member, and
any Group Member may, but shall be under no obligation to,
borrow from the General Partner or any of its Affiliates, funds
needed or desired by the Group Member for such periods of time
and in such amounts as the General Partner may determine;
provided, however, that in any such case the lending
party may not charge the borrowing party interest at
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a rate greater than the rate that would be charged the borrowing
party or impose terms less favorable to the borrowing party than
would be charged or imposed on the borrowing party by unrelated
lenders on comparable loans made on an arms-length basis
(without reference to the lending partys financial
abilities or guarantees), all as determined by the General
Partner. The borrowing party shall reimburse the lending party
for any costs (other than any additional interest costs)
incurred by the lending party in connection with the borrowing
of such funds. For purposes of this Section 7.6(a) and
Section 7.6(b), the term Group Member
shall include any Affiliate of a Group Member that is controlled
by the Group Member.
(b) The Partnership may lend or contribute to any Group
Member, and any Group Member may borrow from the Partnership,
funds on terms and conditions determined by the General Partner
in its sole discretion. No Group Member may lend funds to the
General Partner or any of its Affiliates (other than another
Group Member).
(c) No borrowing by any Group Member or the approval
thereof by the General Partner shall be deemed to constitute a
breach of any duty (including any fiduciary duty) of the General
Partner or any of its Affiliates to the Partnership or the
Partners by reason of the fact that the purpose or effect of
such borrowings is directly or indirectly to enable
distributions to be made to the General Partner or its
Affiliates (including, if applicable, in their capacities as
Limited Partners).
Section 7.7 Indemnification.
(a) To the fullest extent permitted by law but subject to
the limitations expressly provided in this Agreement, all
Indemnitees shall be indemnified and held harmless by the
Partnership from and against any and all losses, claims,
damages, liabilities, joint or several, expenses (including
legal fees and expenses), judgments, fines, penalties, interest,
settlements or other amounts arising from any and all threatened
pending or contemplated claims, demands, actions, suits or
proceedings, whether civil, criminal, administrative or
investigative, and whether formal or informal and including
appeals, in which any Indemnitee may be involved, or is
threatened to be involved, as a party or otherwise, by reason of
its status as an Indemnitee and its having acted (or refrained
from acting) in such capacity; provided, however,
that the Indemnitee shall not be indemnified and held harmless
pursuant to this Agreement if there has been a final and
non-appealable judgment entered by a court of competent
jurisdiction determining that, in respect of the matter for
which the Indemnitee is seeking indemnification pursuant to this
Section 7.7, the Indemnitee acted in bad faith or engaged
in fraud or willful misconduct or, in the case of a criminal
matter, acted with knowledge that the Indemnitees conduct
was unlawful; provided, further, that no indemnification
pursuant to this Section 7.7 shall be available to the
General Partner or its Affiliates (other than a Group Member)
with respect to its or their obligations incurred pursuant to
the Underwriting Agreement or the Omnibus Agreement (other than
obligations incurred by the General Partner on behalf of the
Partnership). Any indemnification pursuant to this
Section 7.7 shall be made only out of the assets of the
Partnership, it being agreed that the General Partner shall not
be personally liable for such indemnification and shall have no
obligation to contribute or loan any monies or property to the
Partnership to enable it to effectuate such indemnification.
(b) To the fullest extent permitted by law, expenses
(including legal fees and expenses) incurred by an Indemnitee
who is indemnified pursuant to Section 7.7(a) in appearing
at, participating in, defending or preparing to defend against
any claim, demand, action, suit or proceeding shall, from time
to time, be advanced by the Partnership prior to a final and
non-appealable judgment entered by a court of competent
jurisdiction determining that, in respect of the matter for
which the Indemnitee is seeking indemnification pursuant to this
Section 7.7, the Indemnitee is not entitled to be
indemnified upon receipt by the Partnership of an undertaking by
or on behalf of the Indemnitee to repay such amount if it shall
be ultimately determined that the Indemnitee is not entitled to
be indemnified as authorized by this Section 7.7.
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(c) Notwithstanding Sections 7.7(a) and 7.7(b), the
Partnership shall be required to indemnify and advance expenses
to an Indemnitee in connection with any action, suit or
proceeding commenced by such Indemnitee only if the commencement
of such action, suit or proceeding by such Indemnitee was
authorized by the General Partner in its sole discretion.
(d) The indemnification provided by this Section 7.7
shall be in addition to any other rights to which an Indemnitee
may be entitled under any agreement, pursuant to any vote of the
holders of Outstanding Limited Partner Interests, as a matter of
law, in equity or otherwise, both as to actions in the
Indemnitees capacity as an Indemnitee and as to actions in
any other capacity (including any capacity under the
Underwriting Agreement), and shall continue as to an Indemnitee
who has ceased to serve in such capacity and shall inure to the
benefit of the heirs, successors, assigns and administrators of
the Indemnitee.
(e) The Partnership may purchase and maintain (or reimburse
the General Partner or its Affiliates for the cost of)
insurance, on behalf of the General Partner, its Affiliates, the
Indemnities and such other Persons as the General Partner shall
determine, against any liability that may be asserted against,
or expense that may be incurred by, any such Person in
connection with the Partnerships activities or such
Persons activities on behalf of the Partnership,
regardless of whether the Partnership would have the power to
indemnify such Person against such liability under the
provisions of this Agreement.
(f) For purposes of this Section 7.7, the Partnership
shall be deemed to have requested an Indemnitee to serve as
fiduciary of an employee benefit plan whenever the performance
by such Indemnitee of its duties to the Partnership also imposes
duties on, or otherwise involves services by, it to the plan or
participants or beneficiaries of the plan; excise taxes assessed
on an Indemnitee in such Indemnitees capacity as a
fiduciary, administrator or other role with respect to an
employee benefit plan pursuant to applicable law shall
constitute fines within the meaning of
Section 7.7(a); and action taken or omitted by an
Indemnitee with respect to any employee benefit plan in the
performance of its duties for a purpose reasonably believed by
it to be in the best interest of the participants and
beneficiaries of the plan shall be deemed to be for a purpose
that is in the best interests of the Partnership.
(g) In no event may an Indemnitee subject the Limited
Partners to personal liability by reason of the indemnification
provisions set forth in this Agreement.
(h) An Indemnitee shall not be denied indemnification in
whole or in part under this Section 7.7 because the
Indemnitee had an interest in the transaction with respect to
which the indemnification applies if the transaction was
otherwise permitted by the terms of this Agreement.
(i) The provisions of this Section 7.7 are for the
benefit of the Indemnitees and their heirs, successors, assigns,
executors and administrators and shall not be deemed to create
any rights for the benefit of any other Persons.
(j) No amendment, modification or repeal of this
Section 7.7 or any provision hereof shall in any manner
terminate, reduce or impair the right of any past, present or
future Indemnitee to be indemnified by the Partnership, nor the
obligations of the Partnership to indemnify any such Indemnitee
under and in accordance with the provisions of this
Section 7.7 as in effect immediately prior to such
amendment, modification or repeal with respect to claims arising
from or relating to matters occurring, in whole or in part,
prior to such amendment, modification or repeal, regardless of
when such claims may arise or be asserted.
Section 7.8 Liability
of Indemnitees.
(a) Notwithstanding anything to the contrary set forth in
this Agreement, no Indemnitee shall be liable for monetary
damages to the Partnership, the Limited Partners, any other
Person who acquires an interest in a Partnership Interest or any
other Person who is bound by this
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Agreement for losses sustained or liabilities incurred as a
result of any act or omission of an Indemnitee unless there has
been a final and non-appealable judgment entered by a court of
competent jurisdiction determining that, in respect of the
matter in question, the Indemnitee acted in bad faith or engaged
in fraud, willful misconduct or, in the case of a criminal
matter, acted with knowledge that the Indemnitees conduct
was criminal. Each Limited Partner, each other Person who
acquires an interest in a Partnership Interest and each other
Person who is bound by this Agreement, on its own behalf and on
behalf of the Partnership, waives, to the fullest extent
permitted by the law, any and all rights to claim punitive
damages or damages based on federal or state income taxes paid
or payable by any Limited Partner or other Person.
(b) Subject to its obligations and duties as General
Partner set forth in Section 7.1(a), the General Partner
may exercise any of the powers granted to it by this Agreement
and perform any of the duties imposed upon it hereunder either
directly or by or through its agents, and the General Partner
shall not be responsible for any misconduct or negligence on the
part of any such agent appointed by the General Partner in good
faith.
(c) To the extent that, at law or in equity, the General
Partner or any other Indemnitee has duties (including fiduciary
duties) and liabilities relating thereto to the Partnership, the
Partners or any other Person bound by this Agreement, the
General Partner and any other Indemnitee acting in connection
with the Partnerships business or affairs shall not be
liable to the Partnership, any Partner or any other Person bound
by this Agreement for its good faith reliance on the provisions
of this Agreement.
(d) Any amendment, modification or repeal of this
Section 7.8 or any provision hereof shall be prospective
only and shall not in any way affect the limitations on the
liability of the Indemnitees under this Section 7.8 as in
effect immediately prior to such amendment, modification or
repeal with respect to claims arising from or relating to
matters occurring, in whole or in part, prior to such amendment,
modification or repeal, regardless of when such claims may arise
or be asserted.
Section 7.9 Resolution
of Conflicts of Interest; Standards of Conduct and Modification
of Duties.
(a) Unless otherwise expressly provided in this Agreement
or any Group Member Agreement, whenever a potential conflict of
interest exists or arises between the General Partner (in its
individual capacity or in its capacity as general partner or
limited partner) or any of its Affiliates or Associates or any
Indemnitee, on the one hand, and the Partnership, any Group
Member or any other Partner, on the other, any resolution or
course of action by the General Partner, its Affiliates or
Associates or any Indemnittee in respect of such conflict of
interest shall be permitted and deemed approved by all Partners,
and shall not constitute a breach of this Agreement, any Group
Member Agreement, any agreement contemplated herein or therein,
or any duty hereunder or existing at law, in equity or
otherwise, if the resolution of, or course of action taken with
respect to, such conflict of interest is (i) approved by
Special Approval, (ii) approved by the vote of the holders
of a majority of the Outstanding Common Units (excluding Common
Units owned by the General Partner and its Affiliates),
(iii) on terms no less favorable to the Partnership than
those generally being provided to or available from unrelated
third parties or (iv) fair and reasonable to the
Partnership, taking into account the totality of the
relationships between the parties involved (including other
transactions that may be particularly favorable or advantageous
to the Partnership). The General Partner shall be authorized but
not required in connection with its resolution of, or course of
action taken with respect to, such conflict of interest to seek
Special Approval or Unitholder approval of such resolution, and
the General Partner may also adopt a resolution or course of
action that has not received Special Approval or Unitholder
approval. Notwithstanding any other provision of this Agreement
or any provision of applicable law, if Special Approval is
sought or obtained, then, it shall be conclusively deemed that,
in making its decision, the Conflicts Committee acted in good
faith, and if neither
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Special Approval or Unitholder approval is sought, or if
neither is obtained, and the Board of Directors determines that
the resolution or course of action taken with respect to a
conflict of interest satisfies either of the standards set forth
in clauses (iii) or (iv) above, then, it shall be
presumed that, in making its decision, the Board of Directors
acted in good faith and, in each case, in any proceeding brought
by any Limited Partner or by or on behalf of such Limited
Partner or any other Limited Partner or the Partnership
challenging such approval, the Person bringing or prosecuting
such proceeding shall have the burden of overcoming such
presumption. Notwithstanding anything to the contrary in this
Agreement or any duty otherwise existing at law or in equity,
(x) when making any determination in connection with the
resolution of or course of action taken with respect to a
conflict of interest, the Conflicts Committee and the Board of
Directors shall be authorized in connection with such
determination to consider any and all factors as the Board of
Director or Conflicts Committee, as applicable, deems to be
relevant or appropriate under the circumstances and shall have
no duty or obligation to consider any other factors and
(y) the existence of the conflicts of interest described in
the Registration Statement and any actions taken by the General
Partner in connection therewith are hereby approved by all
Partners and shall not constitute a breach of this Agreement or
of any duty hereunder or existing at law, in equity or
otherwise. For purposes of this Section 7.9,
Associates of the General Partner shall include any
Person controlled individually or collectively by one or more of
the Founders, the Yorktown Funds or any Affiliates or Associates
of any of the Founders or the Yorktown Funds.
(b) Whenever the General Partner, the Board of Directors or
any committee thereof (including the Conflicts Committee) makes
a determination or takes or declines to take any action, or any
Affiliate of the General Partner or other Indemnitee causes it
to do so, in the General Partners capacity as the general
partner of the Partnership as opposed to in its individual
capacity, whether under this Agreement, any Group Member
Agreement or any other agreement contemplated hereby or
otherwise, then, unless another express standard is provided for
in this Agreement, the General Partner, the Board of Directors,
such committee or such Affiliates or other Indemnitees causing
the General Partner to do so, shall make such determination or
take or decline to take such other action in good faith and
shall not be subject to any other or different standards
(including fiduciary standards) imposed by this Agreement, any
Group Member Agreement, any other agreement contemplated hereby
or under the Delaware Act or otherwise existing at law, in
equity or otherwise. A determination, other action or failure to
act by the General Partner, the Board of Directors or any
committee thereof (including the Conflicts Committee), or any
Affiliate of the General Partner or other Indemnitee that causes
it to make such determination, take such action or fail to act,
will be deemed to be in good faith if the General
Partner, the Board of Directors or such committee or such
Affiliate of the General Partner or other Indemnitee
subjectively believed that such determination, other action or
failure to act was in, or not opposed to, the best interests of
the Partnership. In any proceeding brought by the Partnership,
any Limited Partner, any Person who acquires an interest in a
Partnership Interest or any other Person who is bound by this
Agreement challenging such determination, other action or
failure to act, the Person bringing or prosecuting such
proceeding shall have the burden of proving that such
determination, action or failure to act was not in good faith.
(c) Whenever the General Partner (including the Board of
Directors or any committee thereof) makes a determination or
takes or declines to take any action, or any Affiliate of the
General Partner or any other Indemnitee causes it to do so,
(i) under any provision that permits or requires a
determination to be made in its discretion or
sole discretion, regardless of whether it is acting
in its capacity as the general partner of the Partnership or in
its individual capacity or (ii) in its individual capacity
as opposed to in its capacity as the general partner of the
Partnership, in any case, whether under this Agreement, any
Group Member Agreement or any other agreement contemplated
hereby or otherwise, then the General Partner (including the
Board of Directors or any committee thereof) or such Affiliate
or other Indemnitee causing it to do so, to the fullest extent
permitted by law, shall not be subject to any duty or obligation
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(fiduciary or otherwise) to the Partnership, any Partner or any
other Person and shall be entitled to consider only such
interests and factors as it desires, including its own interests
and the interests of its Affiliates and Associates, and shall
have no duty or obligation (fiduciary or otherwise) to give any
consideration to any interest of or factors affecting the
Partnership, the Partners, or any other Person, and shall not be
subject to any other or different standards (including fiduciary
standards) imposed by this Agreement or otherwise existing at
law, in equity or otherwise. By way of illustration and not of
limitation, whenever the phrase, at the option of the
General Partner or at its option, or some
variation of those phrases, is used in this Agreement, it
indicates that the General Partner is acting in its individual
capacity. For the avoidance of doubt, whenever the General
Partner votes or transfers its Partnership Interests, refrains
from voting or transferring its Partnership Interests, exercises
or refrains from exercising its right to acquire Partnership
Interests or otherwise acts in its capacity as a Limited Partner
or holder of Limited Partner Interests, it shall be acting in
its individual capacity.
(d) The General Partners organizational documents may
provide that determinations to take or decline to take any
action in its individual, rather than representative, capacity
or in its discretion or sole discretion
may or shall be determined by its members, if the General
Partner is a limited liability company, stockholders, if the
General Partner is a corporation, or the members or stockholders
of the General Partners general partner, if the General
Partner is a partnership.
(e) Notwithstanding anything to the contrary in this
Agreement, the General Partner and the other Indemnitees shall
have no duty or obligation, express or implied, to (i) sell
or otherwise dispose of any asset of the Partnership Group other
than in the ordinary course of business or (ii) permit any
Group Member to use any facilities or assets of the General
Partner and its Affiliates, except as may be provided in
contracts entered into from time to time specifically dealing
with such use. Any determination by the General Partner or any
of its Affiliates to enter into such contracts shall be at its
option.
(f) The Limited Partners, each Person who acquires an
interest in a Partnership Interest and each other Person who is
bound by this Agreement hereby authorize the General Partner, on
behalf of the Partnership as a partner or member of a Group
Member, to approve of actions by the general partner or managing
member of such Group Member similar to those actions permitted
to be taken by the General Partner pursuant to this
Section 7.9.
(g) The Limited Partners expressly acknowledge and agree
that the General Partner, the Board of Directors or any
committee thereof and each other Indemnitee is under no
obligation to consider the separate interests of the Limited
Partners (including, without limitation, the tax consequences to
Limited Partners) in deciding whether to cause the Partnership
to take (or decline to take) any actions, and that neither the
General Partner nor any other Indemnitee shall be liable to the
Limited Partners for monetary damages or equitable relief or
losses sustained, liabilities incurred or benefits not derived
by Limited Partners in connection with such decisions.
Section 7.10 Other
Matters Concerning the General Partner.
(a) The General Partner and each other Indemnitee may rely
upon, and shall be protected in acting upon, or refraining from
acting based upon, any resolution, certificate, statement,
instrument, opinion, report, notice, request, consent, order,
bond, debenture or other paper or document believed by it to be
genuine and to have been signed or presented by the proper party
or parties.
(b) The General Partner and each other Indemnitee may
consult with legal counsel, accountants, appraisers, management
consultants, investment bankers and other consultants and
advisers selected by it, and any act taken or omitted to be
taken in reliance upon the advice or opinion (including an
Opinion of Counsel) of such Persons as to matters that the
General Partner reasonably believes to be within such
Persons professional or expert competence shall be
A-42
conclusively deemed to have been done or omitted in good faith
and in accordance with such advice or opinion.
(c) The General Partner shall have the right, in respect of
any of its powers or obligations hereunder, to act through any
of its duly authorized officers, a duly appointed attorney or
attorneys-in-fact or the duly authorized officers of the
Partnership or any Group Member.
Section 7.11 Purchase
or Sale of Partnership Interests.
The General Partner may cause the Partnership to purchase or
otherwise acquire Partnership Interests or other securities. As
long as Partnership Interests or other securities are held by
any Group Member, such Partnership Interests or other securities
shall not be considered Outstanding for any purpose, except as
otherwise provided herein. The General Partner or any Affiliate
of the General Partner may also purchase or otherwise acquire
and sell or otherwise dispose of Partnership Interests for its
own account, subject to the provisions of Articles IV and X.
Section 7.12 Registration
Rights of the General Partner and its Affiliates.
(a) If (i) the General Partner or any Affiliate of the
General Partner, including, for purposes of this
Section 7.12, any Person that is an Affiliate of the
General Partner at the date hereof notwithstanding that it may
later cease to be an Affiliate of the General Partner, but
excluding any individual who is an Affiliate of the General
Partner based on such individuals status as an officer,
director or employee of the General Partner or an Affiliate of
the General Partner, holds Partnership Interests that it desires
to sell and (ii) Rule 144 of the Securities Act (or
any successor rule or regulation to Rule 144) or
another exemption from registration is not available to enable
such holder of Partnership Interests (the
Holder) to dispose of the number of
Partnership Interests it desires to sell at the time it desires
to do so without registration under the Securities Act, then at
the option and upon the request of the Holder, the Partnership
shall file with the Commission as promptly as practicable after
receiving such request, and use all commercially reasonable
efforts to cause to become effective and remain effective for a
period of not less than six months following its effective date
or such shorter period as shall terminate when all Partnership
Interests covered by such registration statement have been sold,
a registration statement under the Securities Act (which may be
a shelf registration statement as contemplated under
Rule 415 under the Securities Act) registering the offering
and sale of the number of Partnership Interests specified by the
Holder; provided, however, that the Partnership shall not
be required to effect more than three registrations pursuant to
this Section 7.12(a); provided, further, that if the
General Partner determines that a postponement of the requested
registration would be in the best interests of the Partnership
and its Partners due to a pending transaction, investigation or
other event, the filing of such registration statement or the
effectiveness thereof may be deferred until such time as the
General Partner determines that such pending transaction,
investigation or other event no longer requires such
postponement; provided, further, that any
postponement shall not exceed more than six months. In
connection with any registration pursuant to the immediately
preceding sentence, the Partnership shall (i) promptly
prepare and file (A) such documents as may be necessary to
register or qualify the securities subject to such registration
under the securities laws of such states as the Holder shall
reasonably request; provided, however, that no such
qualification shall be required in any jurisdiction where, as a
result thereof, the Partnership would become subject to general
service of process or to taxation or qualification to do
business as a foreign corporation or partnership doing business
in such jurisdiction solely as a result of such registration,
and (B) such documents as may be necessary to apply for
listing or to list the Partnership Interests subject to such
registration on such National Securities Exchange as the Holder
shall reasonably request and (ii) do any and all other acts
and things that may be necessary or appropriate to enable the
Holder to consummate a public sale of such Partnership Interests
in such states. Except as set forth in Section 7.12(c)
below, all costs and expenses of any such registration and
offering (other
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than the underwriting fees, discounts and commissions) shall be
paid by the Partnership, without reimbursement by the Holder.
(b) If the Partnership shall at any time propose to file a
registration statement under the Securities Act for an offering
of Partnership Interests for cash (other than a registration
relating solely to a benefit plan, a registration statement
relating solely to a transaction subject to Rule 145 under
the Securities Act or on any registration form which does not
permit secondary sales), the Partnership shall use all
commercially reasonable efforts to include such number or amount
of Partnership Interests held by any Holder in such registration
statement as the Holder shall request; provided, however,
that the Partnership is not required to make any effort or take
any action to so include the Partnership Interests of the Holder
once the registration statement becomes or is declared effective
by the Commission, including any registration statement
providing for the offering from time to time of Partnership
Interests pursuant to Rule 415 of the Securities Act. If
the proposed offering pursuant to this Section 7.12(b)
shall be an underwritten offering, then, in the event that the
managing underwriter or managing underwriters of such offering
advise the Partnership and the Holder in writing that in their
opinion the inclusion of all or some of the Holders
Partnership Interests would adversely and materially affect the
timing or success of the offering, the Partnership shall include
in such offering only that number or amount, if any, of
Partnership Interests held by the Holder that, in the opinion of
the managing underwriter or managing underwriters, will not so
adversely and materially affect the offering. Except as set
forth in Section 7.12(c), all costs and expenses of any
such registration and offering (other than the underwriting
fees, discounts and commissions) shall be paid by the
Partnership, without reimbursement by the Holder. During the two
year period set forth in Section 7.12(d), the Partnership
shall not grant to any other party registration rights similar
to the rights set forth in this Section 7.12(b) that are
superior to such rights without the consent of the General
Partner (and any of its Affiliates).
(c) If underwriters are engaged in connection with any
registration referred to in this Section 7.12, the
Partnership shall provide indemnification, representations,
covenants, opinions, comfort letters and other assurance to the
underwriters in form and substance reasonably satisfactory to
such underwriters. Further, in addition to and not in limitation
of the Partnerships obligation under Section 7.7, the
Partnership shall, to the fullest extent permitted by law,
indemnify and hold harmless the Holder, its officers, directors
and each Person who controls the Holder (within the meaning of
the Securities Act) and any agent thereof (collectively,
Indemnified Persons) from and against
any and all losses, claims, damages, liabilities, joint or
several, expenses (including legal fees and expenses),
judgments, fines, penalties, interest, settlements or other
amounts arising from any and all claims, demands, actions, suits
or proceedings, whether civil, criminal, administrative or
investigative, in which any Indemnified Person may be involved,
or is threatened to be involved, as a party or otherwise, under
the Securities Act or otherwise (hereinafter referred to in this
Section 7.12(c) as a claim and in the plural as
claims) based upon, arising out of or resulting from
any untrue statement or alleged untrue statement of any material
fact contained in any registration statement under which any
Partnership Interests held by an Indemnified Person were
registered under the Securities Act or any state securities or
Blue Sky laws, in any preliminary prospectus (if used prior to
the effective date of such registration statement), or in any
summary or final prospectus or any free writing prospectus or in
any amendment or supplement thereto (if used during the period
the Partnership is required to keep the registration statement
current), or arising out of, based upon or resulting from the
omission or alleged omission to state therein a material fact
required to be stated therein or necessary to make the
statements made therein (if applicable, in the light of the
circumstances in which they were made) not misleading;
provided, however, that the Partnership shall not be
liable to any Indemnified Person to the extent that any such
claim arises out of, is based upon or results from an untrue
statement or alleged untrue statement or omission or alleged
omission made in such registration statement, such preliminary,
summary or final prospectus or any free writing prospectus or
such amendment or supplement, in reliance upon and in conformity
with
A-44
written information furnished to the Partnership by or on behalf
of such Indemnified Person specifically for use in the
preparation thereof.
(d) The provisions of Section 7.12(a),
Section 7.12(b) and Section 7.12(c) shall continue to
be applicable with respect to the General Partner (and any of
the General Partners Affiliates) after it ceases to be a
general partner of the Partnership, during a period of two years
subsequent to the effective date of such cessation and for so
long thereafter as is required for the Holder to sell all of the
Partnership Interests with respect to which it has requested
during such two-year period inclusion in a registration
statement otherwise filed or that a registration statement be
filed; provided, however, that the Partnership shall not
be required to file successive registration statements covering
the same Partnership Interests for which registration was
demanded during such two-year period. The provisions of
Section 7.12(c) shall continue in effect thereafter.
(e) The rights to cause the Partnership to register
Partnership Interests pursuant to this Section 7.12 may be
assigned (but only with all related obligations) by a Holder to
a transferee or assignee of such Partnership Interests, provided
that (i) each such transferee or assignee (or group of
transferees and assignees if affiliated) holds Partnership
Interests representing at least 20% (after giving effect to such
transfer or assignment) of the Partnership Interests held by
such Holder as of the date hereof; (ii) the Partnership is
given written notice prior to any said transfer or assignment,
stating the name and address of such transferee or assignee and
the Partnership Interests with respect to which such
registration rights are being transferred or assigned; and
(iii) such transferee or assignee agrees in writing to be
bound by and subject to the terms set forth in this
Section 7.12.
(f) Any request to register Partnership Interests pursuant
to this Section 7.12 shall (i) specify the Partnership
Interests intended to be offered and sold by the Person making
the request, (ii) express such Persons present intent
to offer such Partnership Interests for distribution,
(iii) describe the nature or method of the proposed offer
and sale of Partnership Interests, and (iv) contain the
undertaking of such Person to provide all such information and
materials and take all action as may be required in order to
permit the Partnership to comply with all applicable
requirements in connection with the registration of such
Partnership Interests.
(g) The Partnership may enter into separate registration
rights agreements with the General Partner or any of its
Affiliates.
Section 7.13 Reliance
by Third Parties.
Notwithstanding anything to the contrary in this Agreement, any
Person dealing with the Partnership shall be entitled to assume
that the General Partner and any officer of the General Partner
authorized by the General Partner to act on behalf of and in the
name of the Partnership has full power and authority to
encumber, sell or otherwise use in any manner any and all assets
of the Partnership and to enter into any authorized contracts on
behalf of the Partnership, and such Person shall be entitled to
deal with the General Partner or any such officer as if it were
the Partnerships sole party in interest, both legally and
beneficially. Each Limited Partner hereby waives, to the fullest
extent permitted by law, any and all defenses or other remedies
that may be available against such Person to contest, negate or
disaffirm any action of the General Partner or any such officer
in connection with any such dealing. In no event shall any
Person dealing with the General Partner or any such officer or
its representatives be obligated to ascertain that the terms of
this Agreement have been complied with or to inquire into the
necessity or expedience of any act or action of the General
Partner or any such officer or its representatives. Each and
every certificate, document or other instrument executed on
behalf of the Partnership by the General Partner or its
representatives shall be conclusive evidence in favor of any and
every Person relying thereon or claiming thereunder that
(a) at the time of the execution and delivery of such
certificate, document or instrument, this Agreement was in full
force and effect, (b) the Person executing and delivering
such certificate, document or instrument was duly authorized and
empowered to do so for and on behalf of the Partnership and
(c) such
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certificate, document or instrument was duly executed and
delivered in accordance with the terms and provisions of this
Agreement and is binding upon the Partnership.
Section 7.14 Modification
of Duties.
Except as expressly set forth in this Agreement, to the fullest
extent permitted by law, none of the General Partner, the Board
of Directors, any committee thereof or any other Indemnitee
shall have any duties or liabilities, including fiduciary
duties, to the Partnership, any Limited Partner, any Person who
acquires an interest in a Partnership Interest or any other
Person bound by this Agreement, and, to the fullest extent
permitted by law, the provisions of this Agreement are agreed
to, supersede and replace the duties (including fiduciary
duties) and liabilities of the General Partner, the Board of
Directors, any committee thereof and each other Indemnitee that
otherwise exist at law, in equity or otherwise. Notwithstanding
any other provision of this Agreement, to the extent that any
provision of this Agreement (i) replaces, restricts or
eliminates the duties (including fiduciary duties) that might
otherwise, as a result of Delaware or other applicable law, be
owed by the General Partner, its Affiliates, the Board of
Directors, any committee thereof or any other Indemnitee to the
Partnership, the Limited Partners, any other Person who acquires
an interest in a Partnership Interest or any other Person who is
bound by this Agreement, or (ii) constitutes a waiver or
consent by the Partnership, the Limited Partners, any other
Person who acquires an interest in a Partnership Interest or any
other Person who is bound by this Agreement to any such
replacement, restriction or elimination, such provision is
hereby approved by the Partnership, all the Partners, each other
Person who acquires an interest in a Partnership Interest and
each other Person who is bound by this Agreement.
ARTICLE VIII
BOOKS,
RECORDS, ACCOUNTING AND REPORTS
Section 8.1 Records
and Accounting.
The General Partner shall keep or cause to be kept at the
principal office of the Partnership appropriate books and
records with respect to the Partnerships business,
including all books and records necessary to provide to the
Limited Partners any information required to be provided
pursuant to Section 3.4(a). Any books and records
maintained by or on behalf of the Partnership in the regular
course of its business, including the record of the Record
Holders of Units or other Partnership Interests, books of
account and records of Partnership proceedings, may be kept on,
or be in the form of, computer disks, hard drives, magnetic
tape, photographs, micrographics or any other information
storage device; provided, however, that the books
and records so maintained are convertible into clearly legible
written form within a reasonable period of time. The books of
the Partnership shall be maintained, for financial reporting
purposes, on an accrual basis in accordance with U.S. GAAP.
Section 8.2 Fiscal
Year.
The fiscal year of the Partnership shall be a fiscal year ending
December 31.
Section 8.3 Reports.
(a) As soon as practicable, but in no event later than
100 days after the close of each fiscal year of the
Partnership, the General Partner shall cause to be mailed or
made available, by any reasonable means to each Record Holder of
a Unit or other Partnership Interest as of a date selected by
the General Partner, an annual report containing financial
statements of the Partnership for such fiscal year of the
Partnership, presented in accordance with U.S. GAAP,
including a balance sheet and statements of operations,
Partnership equity and cash flows, such statements to be audited
by a firm of independent public accountants selected by the
General Partner.
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(b) As soon as practicable, but in no event later than
50 days after the close of each Quarter except the last
Quarter of each fiscal year, the General Partner shall cause to
be mailed or made available, by any reasonable means to each
Record Holder of a Unit or other Partnership Interest, as of a
date selected by the General Partner, a report containing
unaudited financial statements of the Partnership and such other
information as may be required by applicable law, regulation or
rule of any National Securities Exchange on which the Units are
listed or admitted to trading, or as the General Partner
determines to be necessary or appropriate.
(c) The General Partner shall be deemed to have made a
report available to each Record Holder as required by this
Section 8.3 if it has either (i) filed such report
with the Commission via its Electronic Data Gathering, Analysis
and Retrieval system, or any successor system, and such report
is publicly available on such system or (ii) made such
report available on any publicly available website maintained by
the Partnership.
ARTICLE IX
TAX MATTERS
Section 9.1 Tax
Returns and Information.
The Partnership shall timely file all returns of the Partnership
that are required for U.S. federal, state and local income
tax purposes on the basis of the accrual method and the taxable
period or years that it is required by law to adopt, from time
to time, as determined by the General Partner. In the event the
Partnership is required to use a taxable period other than a
year ending on December 31, the General Partner shall use
reasonable efforts to change the taxable period of the
Partnership to a year ending on December 31. The tax
information reasonably required by Record Holders for
U.S. federal, state and local income tax reporting purposes
with respect to a taxable period shall be furnished to them
within 90 days of the close of the calendar year in which
the Partnerships taxable period ends. The classification,
realization and recognition of income, gain, losses and
deductions and other items shall be on the accrual method of
accounting for U.S. federal income tax purposes.
Section 9.2 Tax
Elections.
(a) The Partnership shall make the election under
Section 754 of the Code in accordance with applicable
regulations thereunder, subject to the reservation of the right
to seek to revoke any such election upon the General
Partners determination that such revocation is in the best
interests of the Limited Partners. Notwithstanding any other
provision herein contained, for the purposes of computing the
adjustments under Section 743(b) of the Code, the General
Partner shall be authorized (but not required) to adopt a
convention whereby the price paid by a transferee of a Limited
Partner Interest will be deemed to be the lowest quoted closing
price of the Limited Partner Interests on any National
Securities Exchange on which such Limited Partner Interests are
listed or admitted to trading during the calendar month in which
such transfer is deemed to occur pursuant to Section 6.2(h)
without regard to the actual price paid by such transferee.
(b) Except as otherwise provided herein, the General
Partner shall determine whether the Partnership should make any
other elections permitted by the Code.
Section 9.3 Tax
Controversies.
Subject to the provisions hereof, the General Partner is
designated as the Tax Matters Partner (as defined in the Code)
and is authorized and required to represent the Partnership (at
the Partnerships expense) in connection with all
examinations of the Partnerships affairs by tax
authorities, including resulting administrative and judicial
proceedings, and to expend Partnership funds for professional
services and costs associated therewith. Each Partner agrees to
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cooperate with the General Partner and to do or refrain from
doing any or all things reasonably required by the General
Partner to conduct such proceedings.
Section 9.4 Withholding;
Tax Payments.
(a) The General Partner may treat taxes paid by the
Partnership on behalf of, all or less than all of the Partners,
either as a distribution of cash to such Partners or as a
general expense of the Partnership, as determined appropriate
under the circumstances by the General Partner.
(b) Notwithstanding any other provision of this Agreement,
the General Partner is authorized to take any action that may be
required to cause the Partnership and other Group Members to
comply with any withholding requirements established under the
Code or any other federal, state or local law including pursuant
to Sections 1441, 1442, 1445 and 1446 of the Code. To the
extent that the Partnership is required or elects to withhold
and pay over to any taxing authority any amount resulting from
the allocation of income or from a distribution to any Partner
(including by reason of Section 1446 of the Code), the
General Partner may treat the amount withheld as a distribution
of cash pursuant to Section 6.3 in the amount of such
withholding from such Partner.
ARTICLE X
ADMISSION OF
PARTNERS
Section 10.1 Admission
of Limited Partners.
(a) By acceptance of the transfer of any Limited Partner
Interests in accordance with Article IV or the acceptance
of any Limited Partner Interests issued pursuant to
Article V or pursuant to a merger or consolidation or
conversion pursuant to Article XIV, and except as provided
in Sections 4.7 and 7.11, each transferee of, or other such
Person acquiring, a Limited Partner Interest (including any
nominee holder or an agent or representative acquiring such
Limited Partner Interests for the account of another Person)
(i) shall be admitted to the Partnership as a Limited
Partner with respect to the Limited Partner Interests
transferred or issued to such Person when any such transfer,
issuance or admission is reflected in the books and records of
the Partnership and such Limited Partner becomes the Record
Holder of the Limited Partner Interests so transferred or
issued, (ii) shall become bound, and shall be deemed to
have agreed to be bound, by the terms of this Agreement,
(iii) represents that the transferee has the capacity,
power and authority to enter into this Agreement and
(iv) makes the consents, acknowledgements and waivers
contained in this Agreement, all with or without execution of
this Agreement by such Person. A Person may become a Limited
Partner or Record Holder of a Limited Partner Interest without
the consent or approval of any of the Partners. The transfer of
any Limited Partner Interests and the admission of any new
Limited Partner shall not constitute an amendment to this
Agreement. A Person may not become a Limited Partner without
acquiring a Limited Partner Interest and until such Person is
reflected in the books and records of the Partnership as the
Record Holder of such Limited Partner Interest. The rights and
obligations of a Person who is an Ineligible Citizen Holder
shall be determined in accordance with Section 4.8.
(b) The name and mailing address of each Record Holder
shall be listed on the books and records of the Partnership
maintained for such purpose by the General Partner or the
Transfer Agent. The General Partner shall update the books and
records of the Partnership from time to time as necessary to
reflect accurately the information therein (or shall cause the
Transfer Agent to do so, as applicable). A Limited Partner
Interest may be represented by a Certificate, as provided in
Section 4.1.
(c) Any transfer of a Limited Partner Interest shall not
entitle the transferee to share in the profits and losses, to
receive distributions, to receive allocations of income, gain,
loss, deduction
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or credit or any similar item or to any other rights to which
the transferor was entitled until the transferee becomes a
Limited Partner pursuant to Section 10.1(a).
Section 10.2 Admission
of Successor or Additional General Partner.
A successor General Partner approved pursuant to
Section 11.1 or 11.2 or the transferee of or successor to
all or part of the General Partner Interest pursuant to
Section 4.6 who is proposed to be admitted as a successor
General Partner shall be admitted to the Partnership as the
General Partner, effective immediately prior to the withdrawal
or removal of the predecessor or transferring General Partner,
pursuant to Section 11.1 or 11.2 or the transfer of the
General Partner Interest pursuant to Section 4.6,
provided, however, that no such Person shall be admitted
to the Partnership as a successor or additional General Partner
until compliance with the terms of Section 4.6 has occurred
and such Person has executed and delivered such other documents
or instruments as may be required to effect such admission,
including a counterpart to this Agreement. Any such successor or
additional General Partner is hereby authorized to, and shall,
subject to the terms hereof, carry on the business of the
members of the Partnership Group without dissolution.
Section 10.3 Amendment
of Agreement and Certificate of Limited Partnership.
To effect the admission to the Partnership of any Partner, the
General Partner shall take all steps necessary or appropriate
under the Delaware Act to amend the records of the Partnership
to reflect such admission and, if necessary, to prepare as soon
as practicable an amendment to this Agreement and, if required
by law, the General Partner shall prepare and file an amendment
to the Certificate of Limited Partnership.
ARTICLE XI
WITHDRAWAL
OR REMOVAL OF PARTNERS
Section 11.1 Withdrawal
of the General Partner.
(a) The General Partner shall be deemed to have withdrawn
from the Partnership upon the occurrence of any one of the
following events (each such event herein referred to as an
Event of Withdrawal):
(i) The General Partner voluntarily withdraws from the
Partnership by giving written notice to the other Partners;
(ii) The General Partner transfers all of its General
Partner Interest (including its Notional General Partner Units)
pursuant to Section 4.6;
(iii) The General Partner is removed pursuant to
Section 11.2;
(iv) The General Partner (A) makes a general
assignment for the benefit of creditors, (B) files a
voluntary bankruptcy petition for relief under Chapter 7 of
the United States Bankruptcy Code, (C) files a petition or
answer seeking for itself a liquidation, dissolution or similar
relief (but not a reorganization) under any law, (D) files
an answer or other pleading admitting or failing to contest the
material allegations of a petition filed against the General
Partner in a proceeding of the type described in clauses (A)-(C)
of this Section 11.1(a)(iv) or (E) seeks, consents to
or acquiesces in the appointment of a trustee (but not a
debtor-in-possession),
receiver or liquidator of the General Partner or of all or any
substantial part of its properties;
(v) A final and non-appealable order of relief under
Chapter 7 of the United States Bankruptcy Code is entered
by a court with appropriate jurisdiction pursuant to a voluntary
or involuntary petition by or against the General
Partner; or
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(vi) (A) in the event the General Partner is a
corporation, a certificate of dissolution or its equivalent is
filed for the General Partner, or 90 days expire after the
date of notice to the General Partner of revocation of its
charter without a reinstatement of its charter, under the laws
of its state of incorporation, (B) in the event the General
Partner is a partnership or a limited liability company, the
dissolution and commencement of winding up of the General
Partner, (C) in the event the General Partner is acting in
such capacity by virtue of being a trustee of a trust, the
termination of the trust, (D) in the event the General
Partner is a natural person, his death or adjudication of
incompetency and (E) otherwise in the event of the
termination of the General Partner.
If an Event of Withdrawal specified in Section 11.1(a)(iv),
(v) or (vi)(A), (B), (C) or (E) occurs, the
withdrawing General Partner shall give notice to the Limited
Partners within 30 days after such occurrence. The Partners
hereby agree that only the Events of Withdrawal described in
this Section 11.1 shall result in the withdrawal of the
General Partner from the Partnership.
(b) Withdrawal of the General Partner from the Partnership
upon the occurrence of an Event of Withdrawal shall not
constitute a breach of this Agreement under the following
circumstances: (i) at any time during the period beginning
on the Closing Date and ending at 12:00 am, prevailing Central
Time, on December 31, 2021, the General Partner voluntarily
withdraws by giving at least 90 days advance notice
of its intention to withdraw to the Limited Partners;
provided, however, that prior to the effective
date of such withdrawal, the withdrawal is approved by
Unitholders holding at least a majority of the Outstanding
Common Units (excluding Common Units held by the General Partner
and its Affiliates) and the General Partner delivers to the
Partnership an Opinion of Counsel (Withdrawal
Opinion of Counsel) that such withdrawal
(following the selection of the successor General Partner) would
not result in the loss of the limited liability under the
Delaware Act of any Limited Partner or cause any Group Member to
be treated as an association taxable as a corporation or
otherwise to be taxed as an entity for federal income tax
purposes (to the extent not already so treated or taxed);
(ii) at any time after 12:00 am, prevailing Central Time,
on December 31, 2021, the General Partner voluntarily
withdraws by giving at least 90 days advance notice
to the Unitholders, such withdrawal to take effect on the date
specified in such notice; (iii) at any time that the
General Partner ceases to be the General Partner pursuant to
Section 11.1(a)(ii) or is removed pursuant to
Section 11.2; or (iv) notwithstanding clause (i)
of this sentence, at any time that the General Partner
voluntarily withdraws by giving at least 90 days
advance notice of its intention to withdraw to the Limited
Partners, such withdrawal to take effect on the date specified
in the notice, if at the time such notice is given one Person
and its Affiliates (other than the General Partner and its
Affiliates) own beneficially or of record or control at least
50% of the Outstanding Units. The withdrawal of the General
Partner from the Partnership upon the occurrence of an Event of
Withdrawal shall also constitute the withdrawal of the General
Partner as general partner or managing member, if any, to the
extent applicable, of the other Group Members. If the General
Partner gives a notice of withdrawal pursuant to
Section 11.1(a)(i), the holders of a Unit Majority, may,
prior to the effective date of such withdrawal, elect a
successor General Partner. The Person so elected as successor
General Partner shall, upon admission pursuant to
Section 10.2, automatically become the successor general
partner or managing member, to the extent applicable, of the
other Group Members of which the General Partner is a general
partner or a managing member. If, prior to the effective date of
the General Partners withdrawal pursuant to
Section 11.1(a)(i), a successor is not selected by the
Unitholders as provided herein or the Partnership does not
receive a Withdrawal Opinion of Counsel, the Partnership shall
be dissolved in accordance with Section 12.1 unless the
Partnership is continued without dissolution pursuant to
Section 12.2. Any successor General Partner elected in
accordance with the terms of this Section 11.1 shall be
subject to the provisions of Section 10.2.
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Section 11.2 Removal
of the General Partner.
The General Partner may be removed if such removal is approved
by the Unitholders holding at least
662/3%
of the Outstanding Units (including Units held by the General
Partner and its Affiliates) voting as a single class. Any such
action by such holders for removal of the General Partner must
also provide for the election of a successor General Partner by
the Unitholders holding a majority of the outstanding Common
Units (including Common Units held by the General Partner and
its Affiliates). Such removal shall be effective immediately
following the admission of a successor General Partner pursuant
to Section 10.2. To the fullest extent permitted by law,
the removal of the General Partner shall also automatically
constitute the removal of the General Partner as general partner
or managing member, to the extent applicable, of the other Group
Members of which the General Partner is a general partner or a
managing member. To the fullest extent permitted by law, if a
Person is elected as a successor General Partner in accordance
with the terms of this Section 11.2, such Person shall,
upon admission pursuant to Section 10.2, automatically become a
successor general partner or managing member, to the extent
applicable, of the other Group Members of which the General
Partner is a general partner or a managing member. The right of
the holders of Outstanding Units to remove the General Partner
shall not exist or be exercised unless the Partnership has
received an opinion opining as to the matters covered by a
Withdrawal Opinion of Counsel. Any successor General Partner
elected in accordance with the terms of this Section 11.2
shall be subject to the provisions of Section 10.2.
Section 11.3 Interest
of Departing General Partner and Successor General Partner.
(a) In the event of (i) withdrawal of the General
Partner under circumstances where such withdrawal does not
violate this Agreement or (ii) removal of the General
Partner by the holders of Outstanding Units under circumstances
where Cause does not exist, if the successor General Partner is
elected in accordance with the terms of Section 11.1 or
Section 11.2, the Departing General Partner shall have the
option, exercisable prior to the effective date of the
withdrawal or removal of such Departing General Partner, to
require its successor to purchase its General Partner Interest
and its or its Affiliates general partner interest (or
equivalent interest), if any, in the other Group Members
(collectively, the Combined Interest)
in exchange for an amount in cash equal to the fair market value
of such Combined Interest, such amount to be determined and
payable as of the effective date of its withdrawal or removal.
If the General Partner is removed by the Unitholders under
circumstances where Cause exists or if the General Partner
withdraws under circumstances where such withdrawal violates
this Agreement, and if a successor General Partner is elected in
accordance with the terms of Section 11.1 or
Section 11.2 (or if the Partnership is continued without
dissolution pursuant to Section 12.2 and the successor
General Partner is not the former General Partner), such
successor shall have the option, exercisable prior to the
effective date of the withdrawal or removal of such Departing
General Partner (or, in the event the Partnership is continued
without dissolution pursuant to Section 12.2, prior to the
date the business of the Partnership is continued), to purchase
the Combined Interest in exchange for an amount in cash equal to
the fair market value of such Combined Interest of the Departing
General Partner. In either event, the Departing General Partner
shall be entitled to receive all reimbursements due such
Departing General Partner pursuant to Section 7.4,
including any employee-related liabilities (including severance
liabilities), incurred in connection with the termination of any
employees employed by the Departing General Partner or its
Affiliates (other than any Group Member) for the benefit of the
Partnership or the other Group Members.
For purposes of this Section 11.3(a), the fair market value
of the Combined Interest shall be determined by agreement
between the Departing General Partner and its successor or,
failing agreement within 30 days after the effective date
of such Departing General Partners withdrawal or removal,
by an independent investment banking firm or other independent
expert selected by the Departing General Partner and its
successor, which, in turn, may rely on other
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experts, and the determination of which shall be conclusive as
to such matter. If such parties cannot agree upon one
independent investment banking firm or other independent expert
within 45 days after the effective date of such withdrawal
or removal, then the Departing General Partner shall designate
an independent investment banking firm or other independent
expert, the Departing General Partners successor shall
designate an independent investment banking firm or other
independent expert, and such firms or experts shall mutually
select a third independent investment banking firm or
independent expert, which third independent investment banking
firm or other independent expert shall determine the fair market
value of the Combined Interest. In making its determination,
such third independent investment banking firm or other
independent expert may consider the value of the Units,
including the then current trading price of Units on any
National Securities Exchange on which Units are then listed or
admitted to trading, the value of the Partnerships assets,
the rights and obligations of the Departing General Partner and
other factors it may deem relevant.
(b) If the Combined Interest is not purchased in the manner
set forth in Section 11.3(a), the Departing General Partner
(or its transferee) shall become a Limited Partner and the
Combined Interest shall be converted into Common Units pursuant
to a valuation made by an investment banking firm or other
independent expert selected pursuant to Section 11.3(a),
without reduction in such Partnership Interest (but subject to
proportionate dilution by reason of the admission of its
successor). Any successor General Partner shall indemnify the
Departing General Partner (or its transferee) as to all debts
and liabilities of the Partnership arising on or after the date
on which the Departing General Partner (or its transferee)
becomes a Limited Partner. For purposes of this Agreement,
conversion of the Combined Interest of the Departing General
Partner to Common Units will be characterized as if the
Departing General Partner (or its transferee) contributed the
Combined Interest to the Partnership in exchange for the newly
issued Common Units.
(c) If a successor General Partner is elected in accordance
with the terms of Section 11.1 or Section 11.2 (or if
the business of the Partnership is continued pursuant to
Section 12.2 and the successor General Partner is not the
former General Partner) and the option described in
Section 11.3(a) is not exercised by the party entitled to
do so, the successor General Partner shall, at the effective
date of its admission to the Partnership, contribute to the
Partnership cash in the amount equal to the product of
(x) the quotient obtained by dividing (A) the
Percentage Interest of the General Partner Interest of the
Departing General Partner by (B) a percentage equal to 100%
less the Percentage Interest of the General Partner Interest of
the Departing General Partner and (y) the Net Agreed Value
of the Partnerships assets on such date. In such event,
such successor General Partner shall, subject to the following
sentence, be entitled to its Percentage Interest of all
Partnership allocations and distributions to which the Departing
General Partner was entitled in respect of its General Partner
Interest. In addition, the successor General Partner shall cause
this Agreement to be amended to reflect that, from and after the
date of such successor General Partners admission, the
successor General Partners interest in all Partnership
distributions and allocations shall be its Percentage Interest.
Section 11.4 Withdrawal
of Limited Partners.
No Limited Partner shall have any right to withdraw from the
Partnership; provided, however, that when a transferee of
a Limited Partners Limited Partner Interest becomes a
Record Holder of the Limited Partner Interest so transferred,
such transferring Limited Partner shall cease to be a Limited
Partner with respect to the Limited Partner Interest so
transferred.
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ARTICLE XII
DISSOLUTION
AND LIQUIDATION
Section 12.1 Dissolution.
The Partnership shall not be dissolved by the admission of
additional Limited Partners or by the admission of a successor
or additional General Partner in accordance with the terms of
this Agreement. Upon the removal or other event of withdrawal of
the General Partner, if a successor General Partner is elected
pursuant to Section 11.1, Section 11.2 or
Section 12.2, the Partnership shall not be dissolved and
such successor General Partner is hereby authorized to, and
shall, continue the business of the Partnership. The Partnership
shall dissolve, and (subject to Section 12.2) its affairs
shall be wound up, upon:
(a) an Event of Withdrawal of the General Partner as
provided in Section 11.1(a), unless a successor is elected
pursuant to this Agreement and such successor admitted to the
Partnership pursuant to Section 10.2;
(b) an election to dissolve the Partnership by the General
Partner that is approved by the holders of a Unit Majority;
(c) the entry of a decree of judicial dissolution of the
Partnership pursuant to the provisions of the Delaware
Act; or
(d) at any time there are no Limited Partners, unless the
Partnership is continued without dissolution in accordance with
the Delaware Act.
Section 12.2 Continuation
of the Business of the Partnership After Dissolution.
Upon (a) dissolution of the Partnership following an Event
of Withdrawal caused by the withdrawal or removal of the General
Partner as provided in Section 11.1(a)(i) or 11.1(a)(iii)
and the failure of the Partners to select a successor to such
Departing General Partner pursuant to Section 11.1 or 11.2,
then, to the fullest extent permitted by law, within
90 days thereafter, or (b) dissolution of the
Partnership upon an event constituting an Event of Withdrawal as
defined in Section 11.1(a)(iv), (v) or (vi), then, to
the maximum extent permitted by law, within 180 days
thereafter, the holders of a Unit Majority may elect in writing
to continue the business of the Partnership on the same terms
and conditions set forth in this Agreement by appointing,
effective as of the date of the Event of Withdrawal, as a
successor General Partner a Person approved by the holders of a
Unit Majority. Unless such an election is made within the
applicable time period as set forth above, the Partnership shall
dissolve and conduct only activities necessary to wind up its
affairs. If such an election is so made, then:
(i) the Partnership shall continue without dissolution
unless earlier dissolved in accordance with this
Article XII;
(ii) if the successor General Partner is not the former
General Partner, then the interest of the former General Partner
shall be treated in the manner provided in
Section 11.3; and
(iii) the successor General Partner shall be admitted to
the Partnership as General Partner, effective as of the Event of
Withdrawal, by agreeing in writing to such admission and be
bound by this Agreement;
provided, that the right of the holders of a Unit
Majority to approve a successor General Partner and to continue
the business of the Partnership shall not exist and may not be
exercised unless the Partnership has received an Opinion of
Counsel that (x) the exercise of the right would not result
in the loss of limited liability under the Delaware Act of any
Limited Partner and (y) neither the Partnership nor any
Group Member would be treated as an association taxable as a
corporation or otherwise be taxable as an entity for
U.S. federal income tax purposes upon the exercise of such
right to continue (to the extent not already so treated or
taxed).
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Section 12.3 Liquidator.
Upon dissolution of the Partnership, the General Partner, or if
none, the holders of a Unit Majority, shall select one or more
Persons to act as Liquidator. The Liquidator (if other than the
General Partner) shall be entitled to receive such compensation
for its services as may be approved by holders of at least a
majority of the Outstanding Common Units. The Liquidator (if
other than the General Partner) shall agree not to resign at any
time without 15 days prior notice and may be removed
at any time, with or without cause, by notice of removal
approved by holders of at least a majority of the Outstanding
Common Units. Upon dissolution, removal or resignation of the
Liquidator, a successor and substitute Liquidator (who shall
have and succeed to all rights, powers and duties of the
original Liquidator) shall within 30 days thereafter be
approved by holders of at least a majority of the Outstanding
Common Units. The right to approve a successor or substitute
Liquidator in the manner provided herein shall be deemed to
refer also to any such successor or substitute Liquidator
approved in the manner herein provided. Except as expressly
provided in this Article XII, the Liquidator approved in
the manner provided herein shall have and may exercise, without
further authorization or consent of any of the parties hereto,
all of the powers conferred upon the General Partner under the
terms of this Agreement (but subject to all of the applicable
limitations, contractual and otherwise, upon the exercise of
such powers, other than the limitation on sale set forth in
Section 7.3) necessary or appropriate to carry out the
duties and functions of the Liquidator hereunder for and during
the period of time required to complete the winding up and
liquidation of the Partnership as provided for herein.
Section 12.4 Liquidation.
The Liquidator shall proceed to dispose of the assets of the
Partnership, discharge its liabilities, and otherwise wind up
its affairs in such manner and over such period as determined by
the Liquidator, subject to
Section 17-804
of the Delaware Act and the following:
(a) The assets may be disposed of by public or private sale
or by distribution in kind to one or more Partners on such terms
as the Liquidator and such Partner or Partners may agree. If any
property is distributed in kind, the Partner receiving the
property shall be deemed for purposes of Section 12.4(c) to
have received cash equal to its fair market value; and
contemporaneously therewith, appropriate cash distributions must
be made to the other Partners. The Liquidator may defer
liquidation or distribution of the Partnerships assets for
a reasonable time if it determines that an immediate sale or
distribution of all or some of the Partnerships assets
would be impractical or would cause undue loss to the Partners.
The Liquidator may distribute the Partnerships assets, in
whole or in part, in kind if it determines that a sale would be
impractical or would cause undue loss to the Partners.
(b) The Liquidator shall first satisfy the liabilities of
the Partnership. Liabilities of the Partnership include amounts
owed to the Liquidator as compensation for serving in such
capacity (subject to the terms of Section 12.3) and amounts
to Partners otherwise than in respect of their distribution
rights under Article VI. With respect to any liability that
is contingent, conditional or unmatured or is otherwise not yet
due and payable, the Liquidator shall either settle such claim
for such amount as it thinks appropriate or establish a reserve
of cash or other assets to provide for its payment. When paid,
any unused portion of the reserve shall be applied as additional
liquidation proceeds.
(c) All property and all cash in excess of that required to
discharge liabilities as provided in Section 12.4(b) shall
be distributed to the Partners in accordance with, and to the
extent of, the positive balances in their respective Capital
Accounts, as determined after taking into account all Capital
Account adjustments (other than those made by reason of
distributions pursuant to this Section 12.4(c)) for the
taxable period of the Partnership during which the liquidation
of the Partnership occurs (with such date of occurrence being
determined pursuant to Treasury
Regulation Section 1.704-1(b)(2)(ii)(g)),
and such distribution shall be
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made by the end of such taxable period (or, if later, within
90 days after said date of such occurrence).
Section 12.5 Cancellation
of Certificate of Limited Partnership.
Upon the completion of the distribution of Partnership cash and
property as provided in Section 12.4 in connection with the
winding up of the Partnership, the Certificate of Limited
Partnership and all qualifications of the Partnership as a
foreign limited partnership in jurisdictions other than the
State of Delaware shall be canceled and such other actions as
may be necessary to terminate the Partnership shall be taken.
Section 12.6 Return
of Contributions.
The General Partner shall not be personally liable for, and
shall have no obligation to contribute or loan any money or
property to the Partnership to enable it to effectuate, the
return of the Capital Contributions of the Limited Partners or
Unitholders, or any portion thereof, it being expressly
understood that any such return shall be made solely from
Partnership assets.
Section 12.7 Waiver
of Partition.
To the maximum extent permitted by law, each Partner hereby
waives any right to partition of the Partnership property.
Section 12.8 Capital
Account Restoration.
No Limited Partner shall have any obligation to restore any
negative balance in its Capital Account upon liquidation of the
Partnership. The General Partner shall be obligated to restore
any negative balance in its Capital Account upon liquidation of
its interest in the Partnership by the end of the taxable period
of the Partnership during which such liquidation occurs, or, if
later, within 90 days after the date of such liquidation.
ARTICLE XIII
AMENDMENT OF
PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE
Section 13.1 Amendments
to be Adopted Solely by the General Partner.
Each Partner agrees that the General Partner, without the
approval of any Partner, may amend any provision of this
Agreement and execute, swear to, acknowledge, deliver, file and
record whatever documents may be required in connection
therewith, to reflect:
(a) a change in the name of the Partnership, the location
of the principal place of business of the Partnership, the
registered agent of the Partnership or the registered office of
the Partnership;
(b) the admission, substitution, withdrawal or removal of
Partners in accordance with this Agreement;
(c) a change that the General Partner determines to be
necessary or appropriate to qualify or continue the
qualification of the Partnership as a limited partnership or
other entity in which the Limited Partners have limited
liability under the laws of any state or to ensure that the
Group Members will not be treated as associations taxable as
corporations or otherwise taxed as entities for federal income
tax purposes;
(d) a change that the General Partner determines
(1) does not adversely affect the Limited Partners
considered as a whole (or any particular class of Partnership
Interests as compared to other classes of Partnership Interests)
in any material respect (except as permitted by
subsection (g) hereof); provided, however, that for
purposes of determining whether an amendment satisfies the
requirements of this Section 13.1(d)(1), the General
Partner may in its sole discretion disregard any adverse effect
on any class or classes of
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Partnership Interests the holders of which have approved such
amendment pursuant to Section 13.3(c),(2) to be necessary
or appropriate to (A) satisfy any requirements, conditions
or guidelines contained in any opinion, directive, order, ruling
or regulation of any federal or state agency or judicial
authority or contained in any federal or state statute
(including the Delaware Act) or (B) facilitate the trading
of the Units (including the division of any class or classes of
Outstanding Units into different classes to facilitate
uniformity of tax consequences within such classes of Units) or
comply with any rule, regulation, guideline or requirement of
any National Securities Exchange on which any class of
Partnership Interests are or will be listed or admitted to
trading, (3) to be necessary or appropriate in connection
with action taken by the General Partner pursuant to
Section 5.8 or (4) is required to effect the intent
expressed in the Registration Statement or the intent of the
provisions of this Agreement or is otherwise contemplated by
this Agreement;
(e) a change in the fiscal year or taxable period of the
Partnership and any other changes that the General Partner
determines to be necessary or appropriate as a result of a
change in the fiscal year or taxable period of the Partnership
including, if the General Partner shall so determine, a change
in the definition of Quarter and the dates on
which distributions are to be made by the Partnership;
(f) an amendment that is necessary, in the Opinion of
Counsel, to prevent the Partnership, or the General Partner or
its directors, officers, trustees or agents from in any manner
being subjected to the provisions of the Investment Company Act
of 1940, as amended, the Investment Advisers Act of 1940, as
amended, or plan asset regulations adopted under the
Employee Retirement Income Security Act of 1974, as amended,
regardless of whether such are substantially similar to plan
asset regulations currently applied or proposed by the United
States Department of Labor;
(g) an amendment that the General Partner determines to be
necessary or appropriate in connection with the creation,
authorization or issuance of any class or series of Partnership
Interests or options, rights, warrants, restricted units,
appreciation rights, tracking or phantom interests or other
economic interests in the Partnership relating to Partnership
Interests pursuant to the terms of Section 5.6;
(h) any amendment expressly permitted in this Agreement to
be made by the General Partner acting alone;
(i) an amendment effected, necessitated or contemplated by
a Merger Agreement approved in accordance with Section 14.3;
(j) an amendment that the General Partner determines to be
necessary or appropriate to reflect and account for the
formation by the Partnership of, or investment by the
Partnership in, any corporation, partnership, limited liability
company, joint venture or other entity, in connection with the
conduct by the Partnership of activities permitted by
Section 2.4 or 7.1(a);
(k) a merger, conveyance or conversion pursuant to
Section 14.3(d); or
(l) any other amendments substantially similar to the
foregoing.
Section 13.2 Amendment
Procedures.
Except as provided in Section 13.1 and Section 13.3,
all amendments to this Agreement shall be made in accordance
with the requirements contained in this Section 13.2.
Amendments to this Agreement may be proposed only by the General
Partner; provided, however, that, to the fullest extent
permitted by law, the General Partner shall have no duty or
obligation to propose or approve any amendment to this Agreement
and may decline to do so free of any duty (including any
fiduciary duty) or obligation whatsoever to the Partnership, any
Limited Partner or any other Person bound by this Agreement and,
in declining to propose or approve an amendment, to
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the fullest extent permitted by law shall not be required to
act in good faith or pursuant to any other standard imposed by
this Agreement, any Group Member Agreement, any other agreement
contemplated hereby or under the Delaware Act or any other law,
rule or regulation or at equity. A proposed amendment shall be
effective upon its approval by the General Partner and, except
as otherwise provided by Sections 13.1 and 13.3, the
holders of a Unit Majority, unless a greater or different
percentage is expressly required under this Agreement. Each
proposed amendment that requires the approval of the holders of
a specified percentage of Outstanding Units shall be set forth
in a writing that contains the text of the proposed amendment.
If such an amendment is proposed, the General Partner shall seek
the written approval of the requisite percentage of Outstanding
Units or call a meeting of the Unitholders to consider and vote
on such proposed amendment, in each case in accordance with the
other provisions of this Article XIII. The General Partner
shall notify all Record Holders upon final adoption of any such
proposed amendments. The General Partner shall be deemed to have
notified all Record Holders as required by this
Section 13.2 if it has either (i) filed such amendment
with the Commission via its Electronic Data Gathering, Analysis
and Retrieval system, or any successor system, and such
amendment is publicly available on such system or (ii) made
such amendment available on any publicly available website
maintained by the Partnership.
Section 13.3 Amendment
Requirements.
(a) Notwithstanding the provisions of Section 13.1 and
Section 13.2, no provision of this Agreement (other than a
provision of the Delaware Act that becomes part of this
Agreement by operation of law) that establishes a percentage of
Outstanding Units (including Units deemed owned by the General
Partner) or requires a vote or approval of Partners (or a subset
of the Partners) holding a specified Percentage Interest
required to take any action shall be amended, altered, changed,
repealed or rescinded in any respect that would have the effect
of, (i) in the case of any provision of this Agreement
other than Section 11.2 or Section 13.4, reducing such
percentage or, (ii) in the case of Section 11.2 or
Section 13.4, increasing such percentage, unless such
amendment is approved by the written consent or the affirmative
vote of holders of Outstanding Units whose aggregate Outstanding
Units constitute not less than the voting requirement sought to
be reduced or increased, as applicable.
(b) Notwithstanding the provisions of Section 13.1 and
Section 13.2, no amendment to this Agreement may
(i) enlarge the obligations of any Limited Partner
(including requiring any holder of a class of Partnership
Interests to make additional Capital Contributions to the
Partnership) without its consent, unless such shall be deemed to
have occurred as a result of an amendment approved pursuant to
Section 13.3(c), or (ii) enlarge the obligations of,
restrict, change or modify in any way any action by or rights
of, or reduce in any way the amounts distributable, reimbursable
or otherwise payable to, the General Partner or any of its
Affiliates without the General Partners consent, which
consent may be given or withheld in its sole discretion.
(c) Except as provided in Section 14.3, and without
limitation of the General Partners authority to adopt
amendments to this Agreement without the approval of any other
Partners as contemplated by Section 13.1 (this Section
13.3(c) being subject to the General Partners authority to
unilaterally approve amendments pursuant to Section 13.1), any
amendment that would have a material adverse effect on the
rights or preferences of any class of Partnership Interests in
relation to other classes of Partnership Interests must be
approved by the holders of not less than a majority of the
Outstanding Partnership Interests of the class affected. If the
General Partner determines an amendment does not satisfy the
requirements of Section 13.1(d)(1) because it adversely
affects one or more classes of Partnership Interests, as
compared to other classes of Partnership Interests, in any
material respect, such amendment shall only be required to be
approved by the adversely affected class or classes.
(d) Notwithstanding any other provision of this Agreement,
except for amendments pursuant to Section 13.1 and except
as otherwise provided by Section 14.3(b), no amendments
shall become
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effective without the approval of the holders of at least 90% of
the Percentage Interests of all Limited Partners voting as a
single class unless the Partnership obtains an Opinion of
Counsel to the effect that such amendment will not affect the
limited liability of any Limited Partner under the Delaware Act
or the applicable partnership law of the state under whose laws
the Partnership is organized.
(e) Except as provided in Section 13.1, this
Section 13.3 shall only be amended with the approval of the
Partners (including the General Partner and its Affiliates)
holding at least 90% of the Percentage Interests of all Limited
Partners.
Section 13.4 Special
Meetings.
All acts of Limited Partners to be taken pursuant to this
Agreement shall be taken in the manner provided in this
Article XIII. Special meetings of the Limited Partners may
be called by the General Partner or by Limited Partners owning
20% or more of the Outstanding Partnership Interests of the
class or classes for which a meeting is proposed. Limited
Partners shall call a special meeting by delivering to the
General Partner one or more requests in writing stating that the
signing Limited Partners wish to call a special meeting and
indicating the general or specific purposes for which the
special meeting is to be called. Within 60 days after
receipt of such a call from Limited Partners or within such
greater time as may be reasonably necessary for the Partnership
to comply with any statutes, rules, regulations, listing
agreements or similar requirements governing the holding of a
meeting or the solicitation of proxies for use at such a
meeting, the General Partner shall send a notice of the meeting
to the Limited Partners either directly or indirectly through
the Transfer Agent. A meeting shall be held at a time and place
determined by the General Partner on a date not less than
10 days nor more than 60 days after the time notice of
the meeting is given as provided in Section 16.1. Limited
Partners shall not vote on matters that would cause the Limited
Partners to be deemed to be taking part in the management and
control of the business and affairs of the Partnership so as to
jeopardize the Limited Partners limited liability under
the Delaware Act or the law of any other state in which the
Partnership is qualified to do business.
Section 13.5 Notice
of a Meeting.
Notice of a meeting called pursuant to Section 13.4 shall
be given to the Record Holders of the class or classes of
Partnership Interests for which a meeting is proposed in writing
by mail or other means of written communication in accordance
with Section 16.1. The notice shall be deemed to have been
given at the time when deposited in the mail or sent by other
means of written communication.
Section 13.6 Record
Date.
For purposes of determining the Limited Partners entitled to
notice of or to vote at a meeting of the Limited Partners or to
give approvals without a meeting as provided in
Section 13.11 the General Partner may set a Record Date,
which shall not be less than 10 nor more than 60 days
before (a) the date of the meeting (unless such requirement
conflicts with any rule, regulation, guideline or requirement of
any National Securities Exchange on which the Units are listed
or admitted to trading or U.S. federal securities laws, in
which case the rule, regulation, guideline or requirement of
such National Securities Exchange or U.S. federal
securities laws shall govern) or (b) in the event that
approvals are sought without a meeting, the date by which
Limited Partners are requested in writing by the General Partner
to give such approvals. If the General Partner does not set a
Record Date, then (a) the Record Date for determining the
Limited Partners entitled to notice of or to vote at a meeting
of the Limited Partners shall be the close of business on the
day next preceding the day on which notice is given and
(b) the Record Date for determining the Limited Partners
entitled to give approvals without a meeting shall be the date
the first written approval is deposited with or electronic
transmission is transmitted to the Partnership in care of the
General Partner in accordance with Section 13.11.
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Section 13.7 Adjournment.
When a meeting is adjourned to another time or place, notice
need not be given of the adjourned meeting and a new Record Date
need not be fixed, if the time and place thereof are announced
at the meeting at which the adjournment is taken, unless such
adjournment shall be for more than 45 days. At the
adjourned meeting, the Partnership may transact any business
that might have been transacted at the original meeting. If the
adjournment is for more than 45 days or if a new Record
Date is fixed for the adjourned meeting, a notice of the
adjourned meeting shall be given in accordance with this
Article XIII.
Section 13.8 Waiver
of Notice; Approval of Meeting.
The transaction of any meeting of Limited Partners, however
called and noticed, and whenever held, shall be as valid as if
such transaction of business had occurred at a meeting duly held
after regular call and notice, if a quorum is present either in
person or by proxy. Attendance of a Limited Partner at a meeting
shall constitute a waiver of notice of the meeting, except when
the Limited Partner attends the meeting for the express purpose
of objecting, at the beginning of the meeting, to the
transaction of any business because the meeting is not lawfully
called or convened; and except that attendance at a meeting is
not a waiver of any right to disapprove the consideration of
matters required to be included in the notice of the meeting,
but not so included, if the disapproval is expressly made at the
meeting.
Section 13.9 Quorum
and Voting.
The holders of a majority, by Percentage Interest, of the
Outstanding Partnership Interests of the class or classes for
which a meeting has been called represented in person or by
proxy shall constitute a quorum at a meeting of Limited Partners
of such class or classes unless any such action by the Limited
Partners requires approval by holders of a greater Percentage
Interest, in which case the quorum shall be such greater
percentage. At any meeting of the Limited Partners duly called
and held in accordance with this Agreement at which a quorum is
present, the act of Limited Partners holding Partnership
Interests that in the aggregate represent a majority of the
Percentage Interest of those present in person or by proxy and
entitled to vote at such meeting shall be deemed to constitute
the act of all Limited Partners, unless a greater or different
percentage is required with respect to such action under the
provisions of this Agreement, in which case the act of the
Limited Partners holding Partnership Interests that in the
aggregate represent at least such greater or different
percentage shall be required; provided that if, as a
matter of law, approval by a plurality vote of Partners (or any
class thereof) is required to approve any action, no minimum
quorum shall be required. The Limited Partners present at a duly
called or held meeting at which a quorum is present may continue
to transact business until adjournment, notwithstanding the
withdrawal of enough Limited Partners to leave less than a
quorum, if any action taken (other than adjournment) is approved
by Partners holding the required Percentage Interest specified
in this Agreement. In the absence of a quorum any meeting of
Limited Partners may be adjourned from time to time by the
affirmative vote of Partners with at least a majority, by
Percentage Interest, of the Outstanding Partnership Interests
present and entitled to vote at such meeting represented either
in person or by proxy, but no other business may be transacted,
except as provided in Section 13.7.
Section 13.10 Conduct
of a Meeting.
The General Partner shall have full power and authority
concerning the manner of conducting any meeting of the Limited
Partners or solicitation of approvals in writing or by
electronic transmission, including the determination of Persons
entitled to vote, the existence of a quorum, the satisfaction of
the requirements of Section 13.4, the conduct of voting,
the validity and effect of any proxies and the determination of
any controversies, votes or challenges arising in connection
with or during the meeting or voting. The General Partner shall
designate a Person to serve as chairman of any meeting and shall
further designate a Person to take the minutes of
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any meeting. All minutes shall be kept with the records of the
Partnership maintained by the General Partner. The General
Partner may make such other regulations consistent with
applicable law and this Agreement as it may deem advisable
concerning the conduct of any meeting of the Limited Partners or
solicitation of approvals in writing or by electronic
transmission, including regulations in regard to the appointment
of proxies, the appointment and duties of inspectors of votes
and approvals, the submission and examination of proxies and
other evidence of the right to vote, and the revocation of
approvals in writing or by electronic transmission.
Section 13.11 Action
Without a Meeting.
If authorized by the General Partner, any action that may be
taken at a meeting of the Limited Partners may be taken without
a meeting, without a vote and without prior notice, if an
approval in writing or by electronic transmission is signed or
transmitted by Limited Partners owning not less than the minimum
percentage, by Percentage Interest, of the Outstanding
Partnership Interests of the class or classes for which a
meeting has been or would have been called (including
Partnership Interests deemed owned by the General Partner) that
would be necessary to authorize or take such action at a meeting
at which all the Limited Partners entitled to vote at such
meeting were present and voted (unless such provision conflicts
with any rule, regulation, guideline or requirement of any
National Securities Exchange on which the Units are listed or
admitted to trading, in which case the rule, regulation,
guideline or requirement of such National Securities Exchange
shall govern). Prompt notice of the taking of action without a
meeting shall be given to the Limited Partners who have not
consented. The General Partner may specify that any written
ballot, if any, submitted to Limited Partners for the purpose of
taking any action without a meeting shall be returned to the
Partnership within the time period, which shall be not less than
20 days, specified by the General Partner. If a ballot
returned to the Partnership does not vote all of the Partnership
Interests held by a Limited Partner, the Partnership shall be
deemed to have failed to receive a ballot for the Partnership
Interests that were not voted. If approval of the taking of any
action by the Limited Partners is solicited by any Person other
than by or on behalf of the General Partner, any written
approvals or approvals transmitted by electronic transmission
shall have no force and effect unless and until (a) they
are deposited with or transmitted to the Partnership in care of
the General Partner and (b) an Opinion of Counsel is
delivered to the General Partner to the effect that the exercise
of such right and the action proposed to be taken with respect
to any particular matter (i) will not cause the Limited
Partners to be deemed to be taking part in the management and
control of the business and affairs of the Partnership so as to
jeopardize the Limited Partners limited liability, and
(ii) is otherwise permissible under the state statutes then
governing the rights, duties and liabilities of the Partnership
and the Partners. Nothing contained in this Section 13.11
shall be deemed to require the General Partner to solicit all
Limited Partners in connection with a matter approved by the
holders of the requisite Percentage Interest of Partnership
Interests acting by written consent or consent by electronic
transmission without a meeting.
Section 13.12 Right
to Vote and Related Matters.
(a) Only those Record Holders of the Outstanding
Partnership Interests on the Record Date set pursuant to
Section 13.6 (and also subject to the limitations contained
in the definition of Outstanding)
shall be entitled to notice of, and to vote at, a meeting of
Limited Partners or to act with respect to matters as to which
the holders of the Outstanding Partnership Interests have the
right to vote or to act. All references in this Agreement to
votes of, or other acts that may be taken by, the Outstanding
Partnership Interests shall be deemed to be references to the
votes or acts of the Record Holders of such Outstanding
Partnership Interests.
(b) With respect to Partnership Interests that are held for
a Persons account by another Person (such as a broker,
dealer, bank, trust company or clearing corporation, or an agent
of any of the foregoing), in whose name such Partnership
Interests are registered, such other Person shall, in exercising
the voting rights in respect of such Partnership Interests on
any matter, and
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unless the arrangement between such Persons provides otherwise,
vote such Partnership Interests on behalf of, and at the
direction of, the Person who is the beneficial owner, and the
Partnership shall be entitled to assume it is so acting without
further inquiry. The provisions of this Section 13.12(b)
(as well as all other provisions of this Agreement) are subject
to the provisions of Section 4.3.
ARTICLE XIV
MERGER,
CONSOLIDATION OR CONVERSION
Section
14.1 Authority.
The Partnership may merge or consolidate with or into one or
more corporations, limited liability companies, statutory trusts
or associations, real estate investment trusts, common law
trusts or unincorporated businesses, including a partnership
(whether general or limited (including a limited liability
partnership)) or convert into any such entity, whether such
entity is formed under the laws of the State of Delaware or any
other state of the United States of America, pursuant to a
written plan of merger or consolidation (Merger
Agreement) or a written plan of conversion
(Plan of Conversion), as the case may
be, in accordance with this Article XIV.
Section
14.2 Procedure for Merger, Consolidation or
Conversion.
(a) Merger, consolidation or conversion of the Partnership
pursuant to this Article XIV requires the prior consent of
the General Partner, provided, however, that, to the
fullest extent permitted by law, the General Partner shall have
no duty or obligation to consent to any merger, consolidation or
conversion of the Partnership and may decline to do so free of
any duty (including any fiduciary duty) or obligation whatsoever
to the Partnership, any Limited Partner and, in declining to
consent to a merger, consolidation or conversion, to fullest
extent permitted under the law shall not be required to act in
good faith or pursuant to any other standard imposed by this
Agreement, any Group Member Agreement or any other agreement
contemplated hereby or under the Delaware Act or any other law,
rule or regulation or at equity.
(b) If the General Partner shall determine to consent to
the merger or consolidation, the General Partner shall approve
the Merger Agreement, which shall set forth:
(i) the name and jurisdiction of formation or organization
of each of the business entities proposing to merge or
consolidate;
(ii) the name and jurisdiction of formation or organization
of the business entity that is to survive the proposed merger or
consolidation (the Surviving Business
Entity);
(iii) the terms and conditions of the proposed merger or
consolidation;
(iv) the manner and basis of exchanging or converting the
equity interests, securities or rights of each constituent
business entity for, or into, cash, property or interests,
rights, securities or obligations of the Surviving Business
Entity; and (A) if any equity interests, securities or
rights of any constituent business entity are not to be
exchanged or converted solely for, or into, cash, property or
interests, rights, securities or obligations of the Surviving
Business Entity, then the cash, property or interests, rights,
securities or obligations of any general or limited partnership,
corporation, trust, limited liability company, unincorporated
business or other entity (other than the Surviving Business
Entity) that the holders of such equity interests, securities or
rights are to receive in exchange for, or upon conversion of,
their equity interests, securities or rights, and (B) in
the case of equity interests represented by certificates, upon
the surrender of such certificates, which cash, property or
interests, rights, securities or obligations of the Surviving
Business Entity or any general or limited partnership,
corporation, trust, limited liability company, unincorporated
business or other entity (other than the Surviving Business
Entity), or evidences thereof, are to be delivered;
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(v) a statement of any changes in the constituent documents
or the adoption of new constituent documents (the articles or
certificate of incorporation, articles of trust, declaration of
trust, certificate or agreement of limited partnership,
certificate of formation or limited liability company agreement
or other similar charter or governing document) of the Surviving
Business Entity to be effected by such merger or consolidation;
(vi) the effective time of the merger, which may be the
date of the filing of the certificate of merger pursuant to
Section 14.4 or a later date specified in or determinable
in accordance with the Merger Agreement (provided,
however, that if the effective time of the merger is to
be later than the date of the filing of such certificate of
merger, the effective time shall be fixed at a date or time
certain and stated in the certificate of merger); and
(vii) such other provisions with respect to the proposed
merger or consolidation that the General Partner determines to
be necessary or appropriate.
(c) If the General Partner shall determine to consent to
the conversion, the General Partner shall approve the Plan of
Conversion, which shall set forth:
(i) the name of the converting entity and the converted
entity;
(ii) a statement that the Partnership is continuing its
existence in the organizational form of the converted entity;
(iii) a statement as to the type of entity that the
converted entity is to be and the state or country under the
laws of which the converted entity is to be incorporated, formed
or organized;
(iv) the manner and basis of exchanging or converting the
equity securities, interests or rights of each constituent
business entity for, or into, cash, property, interests, rights,
securities or obligations of the converted entity or, in
addition to or in lieu thereof, cash, property, interests,
rights, securities or obligations of another entity, or the
cancellation of such equity securities, interests or rights;
(v) in an attachment or exhibit, the certificate of
conversion;
(vi) in an attachment or exhibit, the certificate of
limited partnership, articles of incorporation, or other
organizational documents of the converted entity;
(vii) the effective time of the conversion, which may be
the date of the filing of the certificate of conversion or a
later date specified in or determinable in accordance with the
Plan of Conversion (provided, however, that if the
effective time of the conversion is to be later than the date of
the filing of such certificate of conversion, the effective time
shall be fixed at a date or time certain and stated in such
certificate of conversion); and
(viii) such other provisions with respect to the proposed
conversion that the General Partner determines to be necessary
or appropriate.
Section
14.3 Approval by Limited Partners.
(a) Except as provided in Section 14.3(d), the General
Partner, upon its approval of the Merger Agreement or the Plan
of Conversion, as the case may be, shall direct that the Merger
Agreement or the Plan of Conversion and the merger,
consolidation or conversion contemplated thereby, as applicable,
be submitted to a vote of Limited Partners, whether at a special
meeting or by written consent or consent by electronic
transmission, in either case in accordance with the requirements
of Article XIII. A copy or a summary of the Merger
Agreement or the Plan of Conversion, as the case may be, shall
be included in or enclosed with the notice of a special meeting
or solicitation of written consent or consent by electronic
transmission.
(b) Except as provided in Sections 14.3(d) and
14.3(e), the Merger Agreement or Plan of Conversion, as the case
may be, shall be approved upon receiving the affirmative vote or
consent
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of the holders of a Unit Majority unless the Merger Agreement or
Plan of Conversion, as the case may be, contains any provision
that, if contained in an amendment to this Agreement, the
provisions of this Agreement or the Delaware Act would require
for its approval the vote or consent of the holders of a greater
percentage of the Outstanding Units or of any class of Limited
Partners, in which case such greater percentage vote or consent
shall be required for approval of the Merger Agreement or the
Plan of Conversion, as the case may be.
(c) Except as provided in Sections 14.3(d) and
14.3(e), after such approval by vote or consent of the Limited
Partners, and at any time prior to the filing of the certificate
of merger or certificate of conversion pursuant to
Section 14.4, the merger, consolidation or conversion may
be abandoned pursuant to provisions therefor, if any, set forth
in the Merger Agreement or Plan of Conversion, as the case may
be.
(d) Notwithstanding anything else contained in this
Article XIV or in this Agreement, the General Partner is
permitted, without Limited Partner approval, to convert the
Partnership or any Group Member into a new limited liability
entity, to merge the Partnership or any Group Member into, or
convey all of the Partnerships assets to, another limited
liability entity that shall be newly formed and shall have no
assets, liabilities or operations at the time of such
conversion, merger or conveyance other than those it receives
from the Partnership or other Group Member if (i) the
General Partner has received an Opinion of Counsel that the
conversion, merger or conveyance, as the case may be, would not
result in the loss of the limited liability of any Limited
Partner as compared to its limited liability under the Delaware
Act or cause the Partnership or any Group Member to be treated
as an association taxable as a corporation or otherwise to be
taxed as an entity for U.S. federal income tax purposes (to
the extent not already treated as such), (ii) the sole
purpose of such conversion, merger, or conveyance is to effect a
mere change in the legal form of the Partnership into another
limited liability entity and (iii) the governing
instruments of the new entity provide the Limited Partners and
the General Partner with substantially the same rights and
obligations as are herein contained.
(e) Additionally, notwithstanding anything else contained
in this Article XIV or in this Agreement, the General
Partner is permitted, without Limited Partner approval, to merge
or consolidate the Partnership with or into another entity if
(A) the General Partner has received an Opinion of Counsel
that the merger or consolidation, as the case may be, would not
result in the loss of the limited liability of any Limited
Partner as compared to its limited liability under the Delaware
Act or cause the Partnership or any Group Member to be treated
as an association taxable as a corporation or otherwise to be
taxed as an entity for U.S. federal income tax purposes (to
the extent not already treated as such), (B) the merger or
consolidation would not result in an amendment to this
Agreement, other than any amendments that could be adopted
pursuant to Section 13.1, (C) the Partnership is the
Surviving Business Entity in such merger or consolidation,
(D) each Partnership Interest Outstanding immediately prior
to the effective date of the merger or consolidation is to be an
identical Partnership Interest of the Partnership after the
effective date of the merger or consolidation, and (E) the
number of Partnership Interests to be issued by the Partnership
in such merger or consolidation does not exceed 20% of the
Partnership Interests Outstanding immediately prior to the
effective date of such merger or consolidation.
(f) Pursuant to
Section 17-211(g)
of the Delaware Act, an agreement of merger or consolidation
approved in accordance with this Article XIV may
(a) effect any amendment to this Agreement or
(b) effect the adoption of a new partnership agreement for
the Partnership if it is the Surviving Business Entity. Any such
amendment or adoption made pursuant to this Section 14.3
shall be effective at the effective time or date of the merger
or consolidation.
Section
14.4 Certificate of Merger.
Upon the required approval by the General Partner and the
Unitholders of a Merger Agreement or a Plan of Conversion, as
the case may be, a certificate of merger or certificate of
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conversion, as applicable, shall be executed and filed with the
Secretary of State of the State of Delaware in conformity with
the requirements of the Delaware Act.
Section
14.5 Effect of Merger, Consolidation or
Conversion.
(a) At the effective time of the certificate of merger:
(i) all of the rights, privileges and powers of each of the
business entities that has merged or consolidated, and all
property, real, personal and mixed, and all debts due to any of
those business entities and all other things and causes of
action belonging to each of those business entities, shall be
vested in the Surviving Business Entity and after the merger or
consolidation shall be the property of the Surviving Business
Entity to the extent they were of each constituent business
entity;
(ii) the title to any real property vested by deed or
otherwise in any of those constituent business entities shall
not revert and is not in any way impaired because of the merger
or consolidation;
(iii) all rights of creditors and all liens on or security
interests in property of any of those constituent business
entities shall be preserved unimpaired; and
(iv) all debts, liabilities and duties of those constituent
business entities shall attach to the Surviving Business Entity
and may be enforced against it to the same extent as if the
debts, liabilities and duties had been incurred or contracted
by it.
(b) At the effective time of the certificate of conversion:
(i) the Partnership shall continue to exist, without
interruption, but in the organizational form of the converted
entity rather than in its prior organizational form;
(ii) all rights, title, and interests in and to all real
estate and other property owned by the Partnership shall
continue to be owned by the converted entity in its new
organizational form without reversion or impairment, without
further act or deed, and without any transfer or assignment
having occurred, but subject to any existing liens or other
encumbrances thereon;
(iii) all liabilities and obligations of the Partnership
shall continue to be liabilities and obligations of the
converted entity in its new organizational form without
impairment or diminution by reason of the conversion;
(iv) all rights of creditors or other parties with respect
to or against the prior interest holders or other owners of the
Partnership in their capacities as such in existence as of the
effective time of the conversion will continue in existence as
to those liabilities and obligations and may be pursued by such
creditors and obligees as if the conversion did not occur;
(v) a proceeding pending by or against the Partnership or
by or against any of Partners in their capacities as such may be
continued by or against the converted entity in its new
organizational form and by or against the prior partners without
any need for substitution of parties; and
(vi) the Partnership Interests or other rights, securities
or interests of the Partnership that are to be converted into
cash, property, rights, securities or interests in the converted
entity, or rights, securities or interests in any other entity,
as provided in the Plan of Conversion shall be so converted, and
Partners shall be entitled only to the rights provided in the
Plan of Conversion.
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ARTICLE XV
RIGHT TO
ACQUIRE LIMITED PARTNER INTERESTS
Section
15.1 Right to Acquire Limited Partner
Interests.
(a) Notwithstanding any other provision of this Agreement,
if at any time the General Partner and its Affiliates hold more
than 80% of the total Limited Partner Interests of any class
then Outstanding, the General Partner shall then have the right,
which right it may assign and transfer in whole or in part to
the Partnership or any Affiliate of the General Partner,
exercisable at its option, to purchase all, but not less than
all, of such Limited Partner Interests of such class then
Outstanding held by Persons other than the General Partner and
its Affiliates, at the greater of (x) the Current Market
Price as of the date three days prior to the date that the
notice described in Section 15.1(b) is mailed and
(y) the highest price paid by the General Partner or any of
its Affiliates for any such Limited Partner Interest of such
class purchased during the
90-day
period preceding the date that the notice described in
Section 15.1(b) is mailed.
(b) If the General Partner, any Affiliate of the General
Partner or the Partnership elects to exercise the right to
purchase Limited Partner Interests granted pursuant to
Section 15.1(a), the General Partner shall deliver to the
Transfer Agent notice of such election to purchase (the
Notice of Election to Purchase) and
shall cause the Transfer Agent to mail a copy of such Notice of
Election to Purchase to the Record Holders of Limited Partner
Interests of such class or classes (as of a Record Date selected
by the General Partner) at least 10, but not more than 60, days
prior to the Purchase Date. Such Notice of Election to Purchase
shall also be published for a period of at least three
consecutive days in at least two daily newspapers of general
circulation printed in the English language and published in the
Borough of Manhattan, New York. The Notice of Election to
Purchase shall specify the Purchase Date and the price
(determined in accordance with Section 15.1(a)) at which
Limited Partner Interests will be purchased and state that the
General Partner, its Affiliate or the Partnership, as the case
may be, elects to purchase such Limited Partner Interests, upon
surrender of such Limited Partner Interests (including
Certificates representing such Limited Partner Interests in the
case of Limited Partner Interests evidenced by Certificates) in
exchange for payment of the purchase price, at such office or
offices of the Transfer Agent as the Transfer Agent may specify,
or as may be required by any National Securities Exchange on
which such Limited Partner Interests are listed or admitted to
trading. Any such Notice of Election to Purchase mailed to a
Record Holder of Limited Partner Interests at his address as
reflected in the records of the Transfer Agent shall be
conclusively deemed to have been given regardless of whether the
owner receives such notice. On or prior to the Purchase Date,
the General Partner, its Affiliate or the Partnership, as the
case may be, shall deposit with the Transfer Agent cash in an
amount sufficient to pay the aggregate purchase price of all of
such Limited Partner Interests to be purchased in accordance
with this Section 15.1. If the Notice of Election to
Purchase shall have been duly given as aforesaid at least
10 days prior to the Purchase Date, and if on or prior to
the Purchase Date the deposit described in the preceding
sentence has been made for the benefit of the holders of Limited
Partner Interests subject to purchase as provided herein, then
from and after the Purchase Date, notwithstanding that any such
Limited Partner Interest shall not have been surrendered for
purchase, all rights of the holders of such Limited Partner
Interests (including any rights pursuant to Article III,
Article IV, Article V, Article VI, and
Article XII) shall thereupon cease, except the right
to receive the purchase price (determined in accordance with
Section 15.1(a)) therefor, without interest, upon surrender
to the Transfer Agent of such Limited Partner Interests
(including the Certificates representing such Limited Partner
Interests in the case of Limited Partner Interests represented
by Certificates), and such Limited Partner Interests shall
thereupon be deemed to be transferred to the General Partner,
its Affiliate or the Partnership, as the case may be, on the
record books of the Transfer Agent and the Partnership, and the
General Partner or any Affiliate of the General Partner, or the
Partnership, as the case may be, shall be deemed to be the owner
of all such Limited Partner Interests from and after the
Purchase Date and shall have all rights
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as the owner of such Limited Partner Interests (including all
rights as owner of such Limited Partner Interests pursuant to
Article III, Article IV, Article V,
Article VI and Article XII).
(c) In the case of Limited Partner Interests evidenced by
Certificates, at any time from and after the Purchase Date, a
holder of an Outstanding Limited Partner Interest subject to
purchase as provided in this Section 15.1 may surrender his
Certificate evidencing such Limited Partner Interest to the
Transfer Agent in exchange for payment of the amount described
in Section 15.1(a), therefor, without interest thereon.
ARTICLE XVI
GENERAL
PROVISIONS
Section
16.1 Addresses and Notices; Written
Communications.
(a) Any notice, demand, request, report or proxy materials
required or permitted to be given or made to a Partner under
this Agreement shall be in writing and shall be deemed given or
made when delivered in person or when sent by first
class United States mail or by other means of written
communication to the Partner at the address described below. Any
notice, payment or report to be given or made to a Partner
hereunder shall be deemed conclusively to have been given or
made, and the obligation to give such notice or report or to
make such payment shall be deemed conclusively to have been
fully satisfied, upon sending of such notice, payment or report
to the Record Holder of such Partnership Interests at his
address as shown on the records of the Transfer Agent or as
otherwise shown on the records of the Partnership, regardless of
any claim of any Person who may have an interest in such
Partnership Interests by reason of any assignment or otherwise.
Notwithstanding the foregoing, if (i) a Partner shall
consent to receiving notices, demands, requests, reports or
proxy materials via electronic mail or by the Internet or
(ii) the rules of the Commission shall permit any report or
proxy materials to be delivered electronically or made available
via the Internet, any such notice, demand, request, report or
proxy materials shall be deemed given or made when delivered or
made available via such mode of delivery. An affidavit or
certificate of making of any notice, payment or report in
accordance with the provisions of this Section 16.1
executed by the General Partner, the Transfer Agent or the
mailing organization shall be prima facie evidence of the giving
or making of such notice, payment or report. If any notice,
payment or report given or made in accordance with the
provisions of this Section 16.1 is returned marked to
indicate that such notice, payment or report was unable to be
delivered, such notice, payment or report and, in the case of
notices, payments or reports returned by the United States
Postal Service (or other physical mail delivery mail service
outside the United States of America), any subsequent notices,
payments and reports shall be deemed to have been duly given or
made without further mailing (until such time as such Record
Holder or another Person notifies the Transfer Agent or the
Partnership of a change in his address) or other delivery if
they are available for the Partner at the principal office of
the Partnership for a period of one year from the date of the
giving or making of such notice, payment or report to the other
Partners. Any notice to the Partnership shall be deemed given if
received by the General Partner at the principal office of the
Partnership designated pursuant to Section 2.3. The General
Partner may rely and shall be protected in relying on any notice
or other document from a Partner or other Person if believed by
it to be genuine.
(b) The terms in writing,
written communications, written
notice and words of similar import shall be deemed
satisfied under this Agreement by use of
e-mail and
other forms of electronic communication.
Section
16.2 Further Action.
The parties shall execute and deliver all documents, provide all
information and take or refrain from taking action as may be
necessary or appropriate to achieve the purposes of this
Agreement.
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Section
16.3 Binding Effect.
This Agreement shall be binding upon and inure to the benefit of
the parties hereto and their heirs, executors, administrators,
successors, legal representatives and permitted assigns.
Section 16.4 Integration.
This Agreement constitutes the entire agreement among the
parties hereto pertaining to the subject matter hereof and
supersedes all prior agreements and understandings pertaining
thereto.
Section
16.5 Creditors.
Except as provided in Section 16.7, none of the provisions
of this Agreement shall be for the benefit of, or shall be
enforceable by, any creditor of the Partnership.
Section
16.6 Waiver.
No failure by any party to insist upon the strict performance of
any covenant, duty, agreement or condition of this Agreement or
to exercise any right or remedy consequent upon a breach thereof
shall, to the fullest extent permitted by law, constitute waiver
of any such breach of any other covenant, duty, agreement or
condition.
Section
16.7 Third-Party Beneficiaries.
Each Partner agrees that (a) any Indemnitee shall be
entitled to assert rights and remedies hereunder as a
third-party beneficiary hereto with respect to those provisions
of this Agreement affording a right, benefit or privilege to
such Indemnitee and (b) any Unrestricted Person shall be
entitled to assert rights and remedies hereunder as a
third-party beneficiary hereto with respect to those provisions
of this Agreement affording a right, benefit or privilege to
such Unrestricted Person.
Section
16.8 Counterparts.
This Agreement may be executed in counterparts, all of which
together shall constitute an agreement binding on all the
parties hereto, notwithstanding that all such parties are not
signatories to the original or the same counterpart. Each party
shall become bound by this Agreement immediately upon affixing
its signature hereto or, in the case of a Person acquiring a
Limited Partner Interest, pursuant to Section 10.1(a)
without execution hereof.
Section
16.9 Applicable Law; Forum, Venue and
Jurisdiction.
(a) This Agreement shall be construed in accordance with
and governed by the laws of the State of Delaware, without
regard to the principles of conflicts of law.
(b) To the fullest extent permitted by law, each of the
Partners, each Person holding any beneficial interest in the
Partnership (whether through a broker, dealer, bank, trust
company or clearing corporation or an agent of any of the
foregoing or otherwise and each other Person bound by this
Agreement):
(i) irrevocably agrees that any claims, suits, actions or
proceedings (A) arising out of or relating in any way to
this Agreement (including any claims, suits or actions to
interpret, apply or enforce the provisions of this Agreement or
the duties, obligations or liabilities of the Partnership, among
Partners or of Partners to the Partnership, or the rights or
powers of, or restrictions on, the Partners or the Partnership),
(B) brought in a derivative manner on behalf of the
Partnership, (C) asserting a claim of breach of duty
(including any fiduciary duty) owed by any member, director,
officer, or other employee of the Partnership or the General
Partner, or owed by the General Partner to the Partnership or
the Partners, (D) asserting a claim arising pursuant to or
to interpret or enforce any provision of the Delaware Act or
(E) asserting a claim governed by the internal affairs
doctrine, shall be
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exclusively brought in the Court of Chancery of the State of
Delaware (or, if such court does not have subject matter
jurisdiction thereof, any other court in the State of Delaware
with subject matter jurisdiction), in each case regardless of
whether such claims, suits, actions or proceedings sound in
contract, tort, fraud or otherwise, are based on common law,
statutory, equitable, legal or other grounds, or are derivative
or direct claims;
(ii) irrevocably submits to the exclusive jurisdiction of
such courts in connection with any such claim, suit, action or
proceeding;
(iii) irrevocably agrees not to, and waives any right to,
assert in any such claim, suit, action or proceeding that
(A) it is not personally subject to the jurisdiction of
such courts or of any other court to which proceedings in such
courts may be appealed, (B) such claim, suit, action or
proceeding is brought in an inconvenient forum, or (C) the
venue of such claim, suit, action or proceeding is improper;
(iv) expressly waives any requirement for the posting of a
bond by a party bringing such claim, suit, action or proceeding;
(v) consents to process being served in any such claim,
suit, action or proceeding by mailing, certified mail, return
receipt requested, a copy thereof to such party at the address
in effect for notices hereunder, and agrees that such services
shall constitute good and sufficient service of process and
notice thereof; provided, however, nothing in this
clause (v) hereof shall affect or limit any right to serve
process in any other manner permitted by law; and
(vi) IRREVOCABLY WAIVES ANY AND ALL RIGHT TO TRIAL BY JURY
IN ANY SUCH CLAIM, SUIT, ACTION OR PROCEEDING.
(v) consents to process being served in any such claim,
suit, action or proceeding by mailing, certified mail, return
receipt requested, a copy thereof to such party at the address
in effect for notices hereunder, and agrees that such services
shall constitute good and sufficient service of process and
notice thereof; provided, however, nothing in this
clause (v) hereof shall affect or limit any right to serve
process in any other manner permitted by law; and
(vi) IRREVOCABLY WAIVES ANY AND ALL RIGHT TO TRIAL BY JURY
IN ANY SUCH CLAIM, SUIT, ACTION OR PROCEEDING.
Section
16.10 Invalidity of Provisions.
If any provision or part of a provision of this Agreement is or
becomes for any reason, invalid, illegal or unenforceable in any
respect, the validity, legality and enforceability of the
remaining provisions and part thereof contained herein shall not
be affected thereby and this Agreement shall, to the fullest
extent permitted by law, be reformed and construed as if such
invalid, illegal or unenforceable provision, or part of a
provision, had never been contained herein, and such provision
or part reformed so that it would be valid, legal and
enforceable to the maximum extent possible.
Section
16.11 Consent of Partners.
Each Partner hereby expressly consents and agrees that, whenever
in this Agreement it is specified that an action may be taken
upon the affirmative vote or consent of less than all of the
Partners, such action may be so taken upon the concurrence of
less than all of the Partners and each Partner and each other
Person bound by the provisions of this Agreement shall be bound
by the results of such action.
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Section
16.12 Facsimile Signatures.
The use of facsimile signatures affixed in the name and on
behalf of the transfer agent and registrar of the Partnership on
Certificates representing Partnership Interests is expressly
permitted by this Agreement.
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IN WITNESS WHEREOF, the parties hereto have executed this
Agreement as of the date first written above.
GENERAL PARTNER:
MID-CON ENERGY GP, LLC
Name: Charles R. Olmstead
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Title:
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Chief Executive Officer
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ORGANIZATIONAL LIMITED PARTNER:
S. Craig George
LIMITED PARTNERS:
All limited partners now or hereafter admitted as Limited
Partners of the Partnership without execution hereof pursuant to
Section 10.1(a).
[Signature
Page First Amended and Restated Agreement of Limited
Partnership
of
Mid-Con Energy Partners, LP]
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EXHIBIT A
to the First Amended and Restated
Agreement of Limited Partnership of
Mid-Con Energy Partners, LP
Certificate
Evidencing Common Units
Representing Limited Partner Interests in
Mid-Con Energy Partners, LP
In accordance with Section 4.1 of the First Amended and
Restated Agreement of Limited Partnership of Mid-Con Energy
Partners, LP, as amended, supplemented or restated from time to
time (the Partnership Agreement),
Mid-Con Energy Partners, LP, a Delaware limited partnership (the
Partnership), hereby certifies that
(the Holder) is the registered owner
of Common Units representing limited partner interests in the
Partnership (the Common Units)
transferable on the books of the Partnership, in person or by
duly authorized attorney, upon surrender of this Certificate
properly endorsed. The rights, preferences and limitations of
the Common Units are set forth in, and this Certificate and the
Common Units represented hereby are issued and shall in all
respects be subject to the terms and provisions of, the
Partnership Agreement. Copies of the Partnership Agreement are
on file at, and will be furnished without charge on delivery of
written request to the Partnership at, the principal office of
the Partnership located at 2431 E. 61st Street,
Suite 850, Tulsa, Oklahoma 74136. Capitalized terms used
herein but not defined shall have the meanings given them in the
Partnership Agreement.
THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF
MID-CON ENERGY PARTNERS, LP THAT THIS SECURITY MAY NOT BE SOLD,
OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH
TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR
STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE
SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES
COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION
OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR
QUALIFICATION OF MID-CON ENERGY PARTNERS, LP UNDER THE LAWS OF
THE STATE OF DELAWARE, (C) CAUSE MID-CON ENERGY PARTNERS,
LP TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR
OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX
PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED) OR
(D) VIOLATE THE TERMS AND CONDITIONS OF THE PARTNERSHIP
AGREEMENT. MID-CON ENERGY GP, LLC, THE GENERAL PARTNER OF
MID-CON ENERGY PARTNERS, LP, MAY IMPOSE ADDITIONAL RESTRICTIONS
ON THE TRANSFER OF THIS SECURITY IF IT DETERMINES WITH THE
ADVICE OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY OR
ADVISABLE TO AVOID A SIGNIFICANT RISK OF MID-CON ENERGY
PARTNERS, LP BECOMING TAXABLE AS A CORPORATION OR OTHERWISE
BECOMING TAXABLE AS AN ENTITY FOR U.S. FEDERAL INCOME TAX
PURPOSES OR TO PRESERVE THE UNIFORMITY OF THE LIMITED PARTNER
INTERESTS REPRESENTED BY THIS SECURITY (OR ANY CLASS OR
CLASSES THEREOF). THE RESTRICTIONS SET FORTH ABOVE SHALL
NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS
SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL
SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED
TO TRADING.
The Holder, by accepting this Certificate, is deemed to have
(i) requested admission as, and agreed to become, a Limited
Partner and to have agreed to be bound by the terms of the
Partnership Agreement, (ii) represented and warranted that
the Holder has all capacity, power and authority to enter into
the Partnership Agreement and (iii) made the consents,
acknowledgements and waivers contained in the Partnership
Agreement.
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This Certificate shall not be valid for any purpose unless it
has been countersigned and registered by the Transfer Agent and
Registrar. This Certificate shall be governed by and construed
in accordance with the laws of the State of Delaware.
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Dated: Countersigned and Registered by: As Transfer Agent and Registrar
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Mid-Con Energy Partners, LP
By: MID-CON ENERGY GP, LLC
By:
Name:
Title:
By:
Name:
Title:
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[Reverse of
Certificate]
ABBREVIATIONS
The following abbreviations, when used in the inscription on the
face of this Certificate, shall be construed as follows
according to applicable laws or regulations:
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TEN COM as tenants in common
TEN ENT as tenants by the entireties
JT TEN as joint tenants with right of
survivorship and not as tenants in
common
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UNIF GIFT/TRANSFERS MIN ACT
Custodian
(Cust) Minor)
Under Uniform Gifts/Transfers to CD Minors Act (State)
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Additional abbreviations, though not in the above list, may also
be used.
ASSIGNMENT
OF COMMON UNITS OF
MID-CON ENERGY PARTNERS, LP
FOR VALUE RECEIVED,
hereby assigns, conveys, sells and transfers unto
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(Please print or typewrite name and address of assignee)
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(Please insert Social Security or other identifying number of
assignee)
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Common Units representing limited partner interests evidenced by
this Certificate, subject to the Partnership Agreement, and does
hereby irrevocably constitute and appoint
as its attorney-in-fact with full power of substitution to
transfer the same on the books of Mid-Con Energy Partners, LP
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Date:
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NOTE: The signature to any endorsement hereon must correspond
with the name as written upon the face of this Certificate in
every particular without alteration, enlargement or change.
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THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR
INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS
AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE
GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C.
RULE 17Ad-15
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No transfer of the Common Units evidenced hereby will be
registered on the books of the Partnership, unless the
Certificate evidencing the Common Units to be transferred is
surrendered for registration or transfer.
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The following includes a description of the meanings of some of
the oil and gas industry terms used in this prospectus. The
definitions of proved developed reserves, proved reserves and
proved undeveloped reserves have been excerpted from the
applicable definitions contained in
Rule 4-10(a)
of
Regulation S-X.
Basin: A large depression on the earths
surface in which sediments accumulate.
Bbl: One stock tank barrel, or 42
U.S. gallons liquid volume, used in reference to oil or
other liquid hydrocarbons.
Bbl/d: One Bbl per day.
Behind Pipe: Reserves associated with
recompletion projects which have not been previously produced.
Boe: One Boe is equal to six Mcf of natural
gas or one Bbl of oil based on a rough energy equivalency. This
is a physical correlation of heat content and does not reflect a
value or price relationship between the commodities.
Boe/d: One Boe per day.
Btu: One British thermal unit, the quantity of
heat required to raise the temperature of a one-pound mass of
water by one degree Fahrenheit.
Conventional Hydraulic Fracturing: Hydraulic
fracturing is used to stimulate production from new and existing
oil and gas wells. Large volumes of fracturing fluids, or
fracing fluids, are pumped deep into the well at
high pressures sufficient to cause the reservoir rock to break
or fracture. Almost all frac fluid mixtures are comprised of
more than 95 percent water. As the pressure builds within
the well, rock beds begin to crack. More fluid is added while
the pressure is increased until the rock beds finally fracture,
creating channels for trapped oil and natural gas to flow into
the well and up to the surface. The fractures are kept open with
proppants made of small granular solids (generally sand) to
ensure the continued flow of fluids. By creating or even
restoring fractures, the surface area of a formation exposed to
the borehole increases and the fracture provides a conductive
path that connects the reservoir to the well. These new paths
increase the rate that fluids can be produced from the reservoir
formations, in some cases by many hundreds of percent.
Developed Acreage: Acres spaced or assigned to
productive wells or wells capable of production.
Development Well: A well drilled within the
proved area of an oil or natural gas reservoir to the depth of a
stratigraphic horizon known to be productive.
Dry Hole or Well: A well found to be incapable
of producing hydrocarbons in sufficient quantities such that
proceeds from the sale of such production would exceed
production expenses and taxes.
Exploitation: Drilling or other projects that
may target proven or unproven reserves (such as probable or
possible reserves), but that generally have a lower risk than
that associated with exploration projects.
Exploratory Well: A well drilled to find and
produce oil and natural gas reserves not classified as proved,
to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir or to
extend a known reservoir.
Field: An area comprised of multiple leases in
close proximity to one another that typically produce from the
same reservoirs and may or may not be produced under waterflood.
B-1
Injection Well: A well employed for the
introduction into an underground stratum of water, gas or other
fluid under pressure.
MBbls: One thousand Bbls.
MBoe: One thousand Boe.
MBoe/d One thousand Boe per day.
MBtu: One thousand Btu.
Mcf: One thousand cubic feet of natural gas.
Mcf/d One thousand cubic feet of natural gas
per day.
MMBoe: One million Boe.
MMBtu: One million Btu.
MMcf: One million cubic feet of natural gas.
Net Production: Production that is owned by us
less royalties and production due others.
Net Revenue Interest: A working interest
owners gross working interest in production less the
royalty, overriding royalty, production payment and net profits
interests.
NYMEX: New York Mercantile Exchange.
Oil: Oil, condensate and natural gas liquids.
Proved Developed Reserves: Proved reserves
that can be expected to be recovered from existing wells with
existing equipment and operating methods.
Proved Reserves: Those quantities of oil and
gas, which, by analysis of geoscience and engineering data, can
be estimated with reasonable certainty to be economically
producible, from a given date forward, from known reservoirs,
and under existing economic conditions, operating methods, and
government regulations, prior to the time at which contracts
providing the right to operate expire, unless evidence indicates
that renewal is reasonably certain, regardless of whether
deterministic or probabilistic methods are used for the
estimation. The project to extract the hydrocarbons must have
commenced, or the operator must be reasonably certain that it
will commence the project, within a reasonable time. The area of
the reservoir considered as proved includes (i) the area
identified by drilling and limited by fluid contacts, if any,
and (ii) adjacent undrilled portions of the reservoir that
can, with reasonable certainty, be judged to be continuous with
it and to contain economically producible oil or gas on the
basis of available geoscience and engineering data. In the
absence of data on fluid contacts, proved quantities in a
reservoir are limited by the lowest known hydrocarbons, LKH, as
seen in a well penetration unless geoscience, engineering or
performance data and reliable technology establishes a lower
contact with reasonable certainty. Where direct observation from
well penetrations has defined a highest known oil, HKO,
elevation and the potential exists for an associated gas cap,
proved oil reserves may be assigned in the structurally higher
portions of the reservoir only if geoscience, engineering, or
performance data and reliable technology establish the higher
contact with reasonable certainty. Reserves which can be
produced economically through application of improved recovery
techniques (including, but not limited to, fluid injection) are
included in the proved classification when (i) successful
testing by a pilot project in an area of the reservoir with
properties no more favorable than in the reservoir as a whole,
the operation of an installed program in the reservoir or an
analogous reservoir or other evidence using reliable technology
establishes the reasonable certainty of the engineering analysis
on which the project or program was based; and (ii) the
project has been approved for development by all necessary
parties and entities, including governmental entities. Existing
economic conditions include prices and costs at which economic
producibility from a reservoir is to be determined. The price
shall be the average price during the
B-2
twelve-month period prior to the ending date of the period
covered by the report, determined as an unweighted arithmetic
average of the
first-day-of-the-month
price for each month within such period, unless prices are
defined by contractual arrangements, excluding escalations based
upon future conditions.
Proved Undeveloped Reserves: Proved oil and
natural gas reserves that are expected to be recovered from new
wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Reserves on undrilled acreage shall be limited to those drilling
units offsetting productive units that are reasonably certain of
production when drilled. Proved reserves for other undrilled
units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the
existing productive formation. Under no circumstances should
estimates for proved undeveloped reserves be attributable to any
acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the
area and in the same reservoir.
Realized Price: The cash market price less all
expected quality, transportation and demand adjustments.
Recompletion: The completion for production of
an existing wellbore in another formation from that which the
well has been previously completed. Reserves associated with
recompletion are also referred to as Behind Pipe.
Reserve: That part of a mineral deposit which
could be economically and legally extracted or produced at the
time of the reserve determination.
Reservoir: A porous and permeable underground
formation containing a natural accumulation of producible oil
and/or
natural gas that is confined by impermeable rock or water
barriers and is individual and separate from other reserves.
Spacing: The distance between wells producing
from the same reservoir. Spacing is often expressed in terms of
acres (e.g.,
40-acre
spacing) and is often established by regulatory agencies.
Spot Price: The cash market price without
reduction for expected quality, transportation and demand
adjustments.
Standardized Measure: The present value of
estimated future net revenue to be generated from the production
of proved reserves, determined in accordance with the rules and
regulations of the SEC (using prices and costs in effect as of
the date of estimation), less future development, production and
income tax expenses, and discounted at 10% per annum to reflect
the timing of future net revenue. Because we are a limited
partnership, we are generally not subject to federal or state
income taxes and thus make no provision for federal or state
income taxes in the calculation of our standardized measure.
Standardized measure does not give effect to derivative
transactions.
Unit: A contiguous geographic area that was
established and approved by state oil and gas commissions for
the express purpose of secondary recovery.
Unitization: The process of obtaining approval
from working interest owners, mineral owners and regulatory
agencies to conduct secondary (e.g., waterflooding) or tertiary
operations.
Wellbore: The hole drilled by the bit that is
equipped for oil or natural gas production on a completed well.
Also called well or borehole.
Working Interest: The operating interest that
gives the owner the right to drill, produce and conduct
operating activities on the property and a share of production.
Workover: Operations on a producing well to
restore or increase production.
WTI: A crude oil produced in West Texas that
is used as a benchmark for oil prices in the United States.
B-3
November 28,
2011
Mr. Robbin W. Jones
Vice President & COO
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
2431 E. 61st
St., Suite 850
Tulsa, Oklahoma 74136
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Re:
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Reserve Audit
Mid-Con Energy I, LLC and
Mid-Con Energy II, LLC Interests
Total Proved Reserves
As of September 30, 2011
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Pursuant to the Guidelines of the
Securities and Exchange Commission for
Reporting Corporate Reserves and
Future Net Revenue
Dear Mr. Jones:
At your request, this letter was prepared for Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC (MCE)
on November 28, 2011 for the purpose of describing our
audit of your estimates of proved reserves and forecasts of
economics attributable to the subject interests. We examined
100% of MCE reserves, which are made up of oil and gas
properties in various fields in Oklahoma and Colorado. This
examination utilized an effective date of September 30,
2011, was prepared using constant prices and costs, and conforms
to Item 1202(a)(8) of
Regulation S-K
and other rules of the Securities and Exchange Commission (SEC).
Our examination included all methods and procedures as we
considered necessary under the circumstances to render the
opinion set forth herein. The estimates as prepared by MCE are
summarized as follows:
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Cumulative
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Net
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Net
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Cash Flow
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Oil
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Gas
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Net
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Disc. @ 10%
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(Mbbls)
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(MMcf)
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MBOE
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(M$)
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Total Proved
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9,730
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1,069
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9,908
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312,013
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Proved Developed Producing
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5,092
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1,093
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5,274
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171,587
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Proved Developed Non-Producing
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1,330
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0
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1,331
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58,244
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Proved Developed Behind Pipe
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197
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0
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197
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5,535
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Proved Undeveloped
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3,111
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−24
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3,106
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76,647
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Future revenue is prior to deducting state production taxes and
ad valorem taxes. Future net cash flow is after deducting these
taxes, future capital costs and operating expenses, but before
consideration of federal income taxes. In accordance with SEC
guidelines, the future net cash flow has been discounted at an
annual rate of ten percent to determine its present
worth.
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Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
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Page 2
The present worth is shown to indicate the effect of time on the
value of money and should not be construed as being the fair
market value of the properties.
The oil reserves include oil and condensate. Oil volumes are
expressed in barrels (42 U.S. gallons). Gas volumes are
expressed in thousands of standard cubic feet (Mcf) at contract
temperature and pressure base. Our audit involved proved
reserves only and did not include any probable or possible
reserves nor have any values been attributed to interest in
acreage beyond the location for which undeveloped reserves have
been estimated.
Hydrocarbon
Pricing
The base SEC oil and gas prices calculated for
September 30, 2011 were $94.50/bbl and $4.17/MMBTU,
respectively. As specified by the SEC, a company must use a
12-month
average price, calculated as the unweighted arithmetic average
of the
first-day-of-the-month
price for each month within the
12-month
period prior to the end of the reporting period. The base oil
and gas prices are based upon WTI-Cushing and Henry Hub spot
prices, respectively, as published by the EIA for
October 1, 2010 through September 1, 2011.
The base prices shown above were adjusted for differentials on a
per-property basis, which may include local basis differentials,
transportation, gas shrinkage, gas heating value (BTU content)
and/or crude
quality and gravity corrections. After these adjustments, the
net realized prices for the SEC price case over the life of the
proved properties was estimated to be $91.60 per barrel for oil
and $7.36 per MCF for gas. All economic factors were held
constant in accordance with SEC guidelines.
Economic
Parameters
Ownership was accepted as furnished and has not been
independently confirmed. Oil and gas price differentials, gas
shrinkage, ad valorem taxes, severance taxes, lease operating
expenses and investments were calculated and prepared by MCE and
were reviewed by us for reasonableness. Lease operating expenses
were either determined at the field or individual well level
using averages calculated from historical lease operating
statements. All economic parameters, including lease operating
expenses and investments, were held constant (not escalated)
throughout the life of these properties.
SEC
Conformance and Regulations
The reserve classifications and the economic considerations used
herein conform to the criteria of the SEC as defined in pages 6
and 7 following this letter. The reserves and economics are
predicated on regulatory agency classifications, rules,
policies, laws, taxes and royalties currently in effect except
as noted herein. Government policies and market conditions
different from those employed in this report may cause
(1) the total quantity of oil or gas to be recovered,
(2) actual production rates, (3) prices received, or
(4) operating and capital costs to vary from those
presented in this report. However, we do not anticipate nor are
we aware of any legislative changes or restrictive regulatory
actions that may impact the recovery of reserves.
This evaluation includes 68 proved undeveloped locations, which
includes two (2) locations in the Harker Ranch Field in
Colorado and 66 locations in various fields in Oklahoma. Each of
these drilling locations proposed as part of MCEs
development plans conforms to the proved undeveloped standards
as set forth by the SEC. In our opinion, MCE has indicated they
have every intent to complete this development plan within the
next five years. Furthermore, MCE
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November 28, 2011
Page 3
has demonstrated that they have the proper company staffing,
financial backing and prior development success to ensure this
five year development plan will be fully executed.
Reserve
Estimation Methods
The methods employed in estimating reserves are described in
page 5 following this letter. Reserves for proved developed
producing wells were estimated using production performance
methods for the vast majority of properties. Certain new
producing properties with very little production history were
forecast using a combination of production performance and
analogy to similar production, both of which are considered to
provide a relatively high degree of accuracy.
Non-producing reserve estimates, for both developed and
undeveloped properties, were forecast using either volumetric or
analogy methods, or a combination of both. For certain fields
either being waterflooded or prepared for a waterflood, proved
undeveloped reserves were based upon results from either a pilot
waterflood (in the field) or an analogous, nearby waterflood
deemed to be relevant. These methods provide a relatively high
degree of accuracy for predicting proved developed non-producing
and proved undeveloped reserves for MCE properties, due to the
mature nature of their properties targeted for development and
an abundance of subsurface control data. The assumptions, data,
methods and procedures used herein are appropriate for the
purpose served by this audit. Negative gas reserve volumes shown
in the attached cash flow tables for the proved undeveloped
category reflect a minor loss of reserves associated with
conversion of producing wells to water injection.
General
Discussion
An on-site
field inspection of the properties has not been performed. The
mechanical operation or condition of the wells and their related
facilities have not been examined nor have the
wells been tested by Cawley, Gillespie & Associates,
Inc. (CG&A). Possible environmental liability
related to the properties has not been investigated nor
considered. The cost of plugging and the salvage value of
equipment at abandonment have not been included.
The estimates and forecasts were based upon interpretations of
data furnished by your office and available from our files. To
some extent information from public records has been used to
check and/or
supplement these data. The basic engineering and geological data
were subject to third party reservations and qualifications.
Nothing has come to our attention, however, that would cause us
to believe that we are not justified in relying on such data.
All estimates represent our best judgment based on the data
available at the time of preparation. Due to inherent
uncertainties in future production rates, commodity prices and
geologic conditions, it should be realized that the reserve
estimates, the reserves actually recovered, the revenue derived
therefrom and the actual cost incurred could be more or less
than the estimated amounts.
It should be understood that our audit and the development of
our reserves forecasts do not constitute a complete reserve
study of the oil and gas properties of MCE. In the conduct of
our audit, we have not independently verified the accuracy and
completeness of information and data furnished by MCE with
respect to ownership interests, oil and gas production,
historical costs of operation and developments, product prices,
agreements relating to current and future operations and sales
of production. Furthermore, if in the course of our examination
something came to our attention which brought into question the
validity or sufficiency of any of such information or
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Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
Reserve Audit
November 28, 2011
Page 4
data, we did not rely on such information or data until we had
satisfactorily resolved our questions relating thereto or
independently verified such information or data.
Please be advised that, based upon the foregoing, in our opinion
the above-described estimates of Mid-Con Energy I, LLC and
Mid-Con Energy II, LLCs total proved reserves are, in the
aggregate, reasonable within the established audit tolerance
guidelines of (+ or −) 10%. Also, these estimates have
been prepared in accordance with generally accepted petroleum
engineering and evaluation principles as set forth in the
Standards Pertaining to the Estimating and Auditing of Oil and
Gas Reserve Information promulgated by the Society of Petroleum
Engineers and as mandated by the SEC.
Cawley, Gillespie & Associates, Inc. is a Texas
Registered Engineering Firm (F-693), made up of independent
registered professional engineers and geologists that have
provided petroleum consulting services to the oil and gas
industry for over 50 years. This evaluation was supervised
by Robert D. Ravnaas, Executive Vice President at Cawley,
Gillespie & Associates, Inc. and a State of Texas
Licensed Professional Engineer (License #61304). We do not
own an interest in the properties, Mid-Con Energy I, LLC or
Mid-Con Energy II, LLC and are not employed on a contingent
basis. We have used all methods and procedures that we consider
necessary under the circumstances to prepare this audit. Our
work-papers and related data utilized in the preparation of
these estimates are available in our office.
Sincerely,
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Robert D. Ravnaas, P.E.
Executive Vice President
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Page 5
Methods
Employed in the Estimation of Reserves
The four methods customarily employed in the estimation of
reserves are (1) production performance,
(2) material balance,
(3) volumetric and
(4) analogy. Most estimates, although based
primarily on one method, utilize other methods depending on the
nature and extent of the data available and the characteristics
of the reservoirs.
Basic information includes production, pressure, geological and
laboratory data. However, a large variation exists in the
quality, quantity and types of information available on
individual properties. Operators are generally required by
regulatory authorities to file monthly production reports and
may be required to measure and report periodically such
data as well pressures, gas-oil ratios, well tests, etc. As a
general rule, an operator has complete discretion in obtaining
and/or
making available geological and engineering data. The resulting
lack of uniformity in data renders impossible the application of
identical methods to all properties, and may result in
significant differences in the accuracy and reliability of
estimates.
A brief discussion of each method, its basis, data requirements,
applicability and generalization as to its relative degree of
accuracy follows:
Production performance. This method
employs graphical analyses of production data on the premise
that all factors which have controlled the performance to date
will continue to control and that historical trends can be
extrapolated to predict future performance. The only information
required is production history. Capacity production can usually
be analyzed from graphs of rates versus time or cumulative
production. This procedure is referred to as decline
curve analysis. Both capacity and restricted production
can, in some cases, be analyzed from graphs of producing rate
relationships of the various production components. Reserve
estimates obtained by this method are generally considered to
have a relatively high degree of accuracy with the degree of
accuracy increasing as production history accumulates.
Material balance. This method employs
the analysis of the relationship of production and pressure
performance on the premise that the reservoir volume and its
initial hydrocarbon content are fixed and that this initial
hydrocarbon volume and recoveries therefrom can be estimated by
analyzing changes in pressure with respect to production
relationships. This method requires reliable pressure and
temperature data, production data, fluid analyses and knowledge
of the nature of the reservoir. The material balance method is
applicable to all reservoirs, but the time and expense required
for its use is dependent on the nature of the reservoir and its
fluids. Reserves for depletion type reservoirs can be estimated
from graphs of pressures corrected for compressibility versus
cumulative production, requiring only data that are usually
available. Estimates for other reservoir types require extensive
data and involve complex calculations most suited to computer
models which makes this method generally applicable only to
reservoirs where there is economic justification for its use.
Reserve estimates obtained by this method are generally
considered to have a degree of accuracy that is directly related
to the complexity of the reservoir and the quality and quantity
of data available.
Volumetric. This method employs
analyses of physical measurements of rock and fluid properties
to calculate the volume of hydrocarbons in-place. The data
required are well information sufficient to determine reservoir
subsurface datum, thickness, storage volume, fluid content and
location. The volumetric method is most applicable to reservoirs
which are not susceptible to analysis by production performance
or material balance methods. These are most commonly newly
developed
and/or
no-pressure depleting reservoirs. The amount of hydrocarbons
in-place that can be recovered is not an integral part of the
volumetric calculations but is an estimate
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Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
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November 28, 2011
Page 6
inferred by other methods and a knowledge of the nature of the
reservoir. Reserve estimates obtained by this method are
generally considered to have a low degree of accuracy; but the
degree of accuracy can be relatively high where rock quality and
subsurface control is good and the nature of the reservoir is
uncomplicated.
Analogy. This method which employs
experience and judgment to estimate reserves, is based on
observations of similar situations and includes consideration of
theoretical performance. The analogy method is applicable where
the data are insufficient or so inconclusive that reliable
reserve estimates cannot be made by other methods. Reserve
estimates obtained by this method are generally considered to
have a relatively low degree of accuracy.
Much of the information used in the estimation of reserves is
itself arrived at by the use of estimates. These estimates are
subject to continuing change as additional information becomes
available. Reserve estimates which presently appear to be
correct may be found to contain substantial errors as time
passes and new information is obtained about well and reservoir
performance.
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Page 7
Reserve
Definitions and Classifications
The Securities and Exchange Commission, in SX Reg. 210.4-10
dated November 18, 1981, as amended on September 19,
1989 and January 1, 2010, requires adherence to the
following definitions of oil and gas reserves:
(22) Proved oil and gas reserves.
Proved oil and gas reserves are those quantities of oil and gas,
which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically
produciblefrom a given date forward, from known
reservoirs, and under existing economic conditions, operating
methods, and government regulationsprior to the time at
which contracts providing the right to operate expire, unless
evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are
used for the estimation. The project to extract the hydrocarbons
must have commenced or the operator must be reasonably certain
that it will commence the project within a reasonable time.
(i) The area of a reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid
contacts, if any, and (B) Adjacent undrilled portions of
the reservoir that can, with reasonable certainty, be judged to
be continuous with it and to contain economically producible oil
or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved
quantities in a reservoir are limited by the lowest known
hydrocarbons (LKH) as seen in a well penetration unless
geoscience, engineering, or performance data and reliable
technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has
defined a highest known oil (HKO) elevation and the potential
exists for an associated gas cap, proved oil reserves may be
assigned in the structurally higher portions of the reservoir
only if geoscience, engineering, or performance data and
reliable technology establish the higher contact with reasonable
certainty.
(iv) Reserves which can be produced economically through
application of improved recovery techniques (including, but not
limited to, fluid injection) are included in the proved
classification when: (A) Successful testing by a pilot
project in an area of the reservoir with properties no more
favorable than in the reservoir as a whole, the operation of an
installed program in the reservoir or an analogous reservoir, or
other evidence using reliable technology establishes the
reasonable certainty of the engineering analysis on which the
project or program was based; and (B) The project has been
approved for development by all necessary parties and entities,
including governmental entities.
(v) Existing economic conditions include prices and costs
at which economic producibility from a reservoir is to be
determined. The price shall be the average price during the
12-month
period prior to the ending date of the period covered by the
report, determined as an unweighted arithmetic average of the
first-day-of-the-month
price for each month within such period, unless prices are
defined by contractual arrangements, excluding escalations based
upon future conditions.
(6) Developed oil and gas reserves.
Developed oil and gas reserves are reserves of any category that
can be expected to be recovered:
(i) Through existing wells with existing equipment and
operating methods or in which the cost of the required equipment
is relatively minor compared to the cost of a new well; and
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Page 8
(ii) Through installed extraction equipment and
infrastructure operational at the time of the reserves estimate
if the extraction is by means not involving a well.
(31) Undeveloped oil and gas reserves.
Undeveloped oil and gas reserves are reserves of any category
that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major
expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to
those directly offsetting development spacing areas that are
reasonably certain of production when drilled, unless evidence
using reliable technology exists that establishes reasonable
certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having
undeveloped reserves only if a development plan has been adopted
indicating that they are scheduled to be drilled within five
years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for
undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery
technique is contemplated, unless such techniques have been
proved effective by actual projects in the same reservoir or an
analogous reservoir, as defined in paragraph (a)(2) of this
section, or by other evidence using reliable technology
establishing reasonable certainty.
(18) Probable reserves. Probable
reserves are those additional reserves that are less certain to
be recovered than proved reserves but which, together with
proved reserves, are as likely as not to be recovered.
(i) When deterministic methods are used, it is as likely
as not that actual remaining quantities recovered will exceed
the sum of estimated proved plus probable reserves. When
probabilistic methods are used, there should be at least a 50%
probability that the actual quantities recovered will equal or
exceed the proved plus probable reserves estimates.
(ii) Probable reserves may be assigned to areas of a
reservoir adjacent to proved reserves where data control or
interpretations of available data are less certain, even if the
interpreted reservoir continuity of structure or productivity
does not meet the reasonable certainty criterion. Probable
reserves may be assigned to areas that are structurally higher
than the proved area if these areas are in communication with
the proved reservoir.
(iii) Probable reserves estimates also include potential
incremental quantities associated with a greater percentage
recovery of the hydrocarbons in place than assumed for proved
reserves.
(iv) See also guidelines in paragraphs (17)(iv) and
(17)(vi) of this section (below).
(17) Possible reserves. Possible
reserves are those additional reserves that are less certain to
be recovered than probable reserves.
(i) When deterministic methods are used, the total
quantities ultimately recovered from a project have a low
probability of exceeding proved plus probable plus possible
reserves. When probabilistic methods are used, there should be
at least a 10% probability that the total quantities ultimately
recovered will equal or exceed the proved plus probable plus
possible reserves estimates.
(ii) Possible reserves may be assigned to areas of a
reservoir adjacent to probable reserves where data control and
interpretations of available data are progressively less
certain.
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Page 9
Frequently, this will be in areas where geoscience and
engineering data are unable to define clearly the area and
vertical limits of commercial production from the reservoir by a
defined project.
(iii) Possible reserves also include incremental
quantities associated with a greater percentage recovery of the
hydrocarbons in place than the recovery quantities assumed for
probable reserves.
(iv) The proved plus probable and proved plus probable
plus possible reserves estimates must be based on reasonable
alternative technical and commercial interpretations within the
reservoir or subject project that are clearly documented,
including comparisons to results in successful similar projects.
(v) Possible reserves may be assigned where geoscience and
engineering data identify directly adjacent portions of a
reservoir within the same accumulation that may be separated
from proved areas by faults with displacement less than
formation thickness or other geological discontinuities and that
have not been penetrated by a wellbore, and the registrant
believes that such adjacent portions are in communication with
the known (proved) reservoir. Possible reserves may be assigned
to areas that are structurally higher or lower than the proved
area if these areas are in communication with the proved
reservoir.
(vi) Pursuant to paragraph (22)(iii) of this section
(above), where direct observation has defined a highest known
oil (HKO) elevation and the potential exists for an associated
gas cap, proved oil reserves should be assigned in the
structurally higher portions of the reservoir above the HKO only
if the higher contact can be established with reasonable
certainty through reliable technology. Portions of the reservoir
that do not meet this reasonable certainty criterion may be
assigned as probable and possible oil or gas based on reservoir
fluid properties and pressure gradient interpretations.
Instruction 4 of Item 2(b) of Securities and Exchange
Commission
Regulation S-K
was revised January 1, 2010 to state that a
registrant engaged in oil and gas producing activities shall
provide the information required by Subpart 1200 of
Regulation S K. This is relevant in that
Instruction 2 to paragraph (a)(2) states: The
registrant is permitted, but not required, to disclose
probable or possible reserves pursuant to paragraphs (a)(2)(iv)
through (a)(2)(vii) of this Item.
(26) Reserves. Reserves are estimated
remaining quantities of oil and gas and related substances
anticipated to be economically producible, as of a given date,
by application of development projects to known accumulations.
In addition, there must exist, or there must be a reasonable
expectation that there will exist, the legal right to produce or
a revenue interest in the production, installed means of
delivering oil and gas or related substances to market, and all
permits and financing required to implement the project.
Note to paragraph (26): Reserves should
not be assigned to adjacent reservoirs isolated by major,
potentially sealing, faults until those reservoirs are
penetrated and evaluated as economically producible. Reserves
should not be assigned to areas that are clearly separated from
a known accumulation by a non-productive reservoir (i.e.,
absence of reservoir, structurally low reservoir, or negative
test results). Such areas may contain prospective resources
(i.e., potentially recoverable resources from undiscovered
accumulations).
C-9
Through and
including
(the 25th
day after the date of this prospectus), all dealers effecting
transactions in these securities, whether or not participating
in this offering, may be required to deliver a prospectus. This
is in addition to the dealers obligation to deliver a
prospectus when acting as underwriters and with respect to their
unsold allotments or subscriptions.
Common Units
Mid-Con Energy Partners,
LP
5,400,000 Common
Units
Representing Limited Partner
Interests
PRICE
$
PER COMMON UNIT
RBC
Capital Markets
Raymond James
Wells Fargo Securities
Baird
Oppenheimer & Co
PRELIMINARY PROSPECTUS
,
2011
PART II
|
|
Item 13.
|
Other
Expenses of Issuance and Distribution
|
Set forth below are the expenses (other than underwriting
discounts, a structuring fee and commissions) expected to be
incurred in connection with the issuance and distribution of the
securities registered hereby. With the exception of the
Securities and Exchange Commission registration fee, the FINRA
filing fee and the NASDAQ Global Market listing fee, the amounts
set forth below are estimates. The underwriters have agreed to
reimburse us for a portion of our expenses.
|
|
|
|
|
SEC registration fee
|
|
$
|
16,254
|
|
FINRA filing fee
|
|
$
|
14,500
|
|
NASDAQ Global Market listing fee
|
|
$
|
25,000
|
|
Printing and engraving expenses
|
|
$
|
650,000
|
|
Accounting fees and expenses
|
|
$
|
350,000
|
|
Legal fees and expenses
|
|
$
|
1,500,000
|
|
Engineering expenses
|
|
$
|
86,426
|
|
Transfer agent and registrar fees
|
|
$
|
20,000
|
|
Miscellaneous
|
|
$
|
53,200
|
|
Total
|
|
$
|
2,715,380
|
|
|
|
Item 14.
|
Indemnification
of Directors and Officers
|
The partnership agreement of Mid-Con Energy Partners, LP
provides that the partnership will, to the fullest extent
permitted by law but subject to the limitations expressly
provided therein, indemnify and hold harmless its general
partner, any Departing Partner (as defined therein), any person
who is or was an affiliate of the general partner, including any
person who is or was a member, partner, officer, director,
fiduciary or trustee of the general partner, any Departing
Partner, any Group Member (as defined therein) or any affiliate
of the general partner, any Departing Partner or any Group
Member, or any person who is or was serving at the request of
the general partner, including any affiliate of the general
partner or any Departing Partner or any affiliate of any
Departing Partner as an officer, director, member, partner,
fiduciary or trustee of another person, or any person that the
general partner designates as a Partnership Indemnitee for
purposes of the partnership agreement (each, a Partnership
Indemnitee) from and against any and all losses, claims,
damages, liabilities (joint or several), expenses (including
legal fees and expenses), judgments, fines, penalties, interest,
settlements or other amounts arising from any and all claims,
demands, actions, suits or proceedings, whether civil, criminal,
administrative or investigative, in which any Partnership
Indemnitee may be involved, or is threatened to be involved, as
a party or otherwise, by reason of its status as a Partnership
Indemnitee, provided that the Partnership Indemnitee shall not
be indemnified and held harmless if there has been a final and
non-appealable judgment entered by a court of competent
jurisdiction determining that, in respect of the matter for
which the Partnership Indemnitee is seeking indemnification, the
Partnership Indemnitee engaged in fraud, willful misconduct or
gross negligence or, a breach of its obligations under the
partnership agreement of Mid-Con Energy Partners, LP or a breach
of its fiduciary duty in the case of a criminal matter, acted
with knowledge that the Partnership Indemnitees conduct
was unlawful. This indemnification would under certain
circumstances include indemnification for liabilities under the
Securities Act. To the fullest extent permitted by law, expenses
(including legal fees and expenses) incurred by a Partnership
Indemnitee who is indemnified pursuant to the partnership
agreement in defending any claim, demand, action, suit or
proceeding shall, from time to time, be advanced by the
partnership prior to a determination that the Partnership
Indemnitee is not entitled to be indemnified upon receipt by the
partnership of any undertaking by or on behalf of the
II-1
Partnership Indemnitee to repay such amount if it shall be
determined that the Partnership Indemnitee is not entitled to be
indemnified under the partnership agreement provided,
however, there shall be no advancement of costs or fees to
any Partnership Indemnitee in the event of a derivative or
direct action against such Person brought by at least a Majority
in Interest of the Limited Partners. Any indemnification under
these provisions will be only out of the assets of the
partnership.
Section 17-108
of the Delaware Revised Uniform Limited Partnership Act empowers
a Delaware limited partnership to indemnify and hold harmless
any partner or other persons from and against all claims and
demands whatsoever.
Mid-Con Energy Partners, LP is authorized to purchase (or to
reimburse its general partner for the costs of) insurance
against liabilities asserted against and expenses incurred by
its general partner, its affiliates and such other persons as
the respective general partners may determine and described in
the paragraph above in connection with their activities, whether
or not they would have the power to indemnify such person
against such liabilities under the provisions described in the
paragraphs above. The general partner has purchased insurance
covering its officers and directors against liabilities asserted
and expenses incurred in connection with their activities as
officers and directors of our general partner or any of its
direct or indirect subsidiaries.
Any underwriting agreement entered into in connection with the
sale of the securities offered pursuant to this registration
statement will provide for indemnification of officers and
directors of our general partner, including liabilities under
the Securities Act.
|
|
Item 15.
|
Recent
Sales of Unregistered Securities.
|
On July 29, 2011, in connection with the formation of
Mid-Con Energy Partners, LP, we issued (i) the 2.0% general
partner interest in us to Mid-Con Energy GP, LLC for $20 and
(ii) the 98.0% limited partner interest in us to S. Craig
George for $980, in each case, in an offering exempt from
registration under Section 4(2) of the Securities Act.
There have been no other sales of unregistered securities within
the past three years.
|
|
Item 16.
|
Exhibits
and Financial Statement Schedules.
|
(a) Exhibit Index
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
1
|
.1***
|
|
|
|
Form of Underwriting Agreement
|
|
3
|
.1*
|
|
|
|
Certificate of Limited Partnership of Mid-Con Energy Partners, LP
|
|
3
|
.2*
|
|
|
|
Agreement of Limited Partnership of Mid-Con Energy Partners, LP
|
|
3
|
.3***
|
|
|
|
Form of First Amended and Restated Agreement of Limited
Partnership of Mid-Con Energy Partners, LP (included as Appendix
A to the prospectus)
|
|
3
|
.4*
|
|
|
|
Certificate of Formation of Mid-Con Energy GP, LLC
|
|
3
|
.5***
|
|
|
|
Limited Liability Company Agreement of Mid-Con Energy GP, LLC
|
|
3
|
.6***
|
|
|
|
Form of Amended and Restated Limited Liability Company Agreement
of Mid-Con Energy GP, LLC
|
|
5
|
.1
|
|
|
|
Opinion of GableGotwals as to the legality of the securities
being registered
|
|
8
|
.1
|
|
|
|
Opinion of Andrews Kurth LLP relating to tax matters
|
|
10
|
.1***
|
|
|
|
Form of Credit Agreement
|
|
10
|
.2***
|
|
|
|
Form of Contribution, Conveyance, Assumption and Merger Agreement
|
|
10
|
.3***
|
|
|
|
Form of Mid-Con Energy GP, LLC Long-Term Incentive Program
|
|
10
|
.4***
|
|
|
|
Form of Services Agreement
|
|
10
|
.5**
|
|
|
|
Form of Crude Oil Purchase Agreement between RDT Properties Inc.
(now known as Mid-Con Energy Operating, Inc.) and Sunoco
Partners Marketing & Terminals, L.P.
|
|
10
|
.6**
|
|
|
|
Form of Crude Oil Purchase Agreement between Mid-Con Energy
Operating, Inc. and Enterprise Crude Oil LLC
|
|
10
|
.7***
|
|
|
|
Form of Employment Agreement
|
II-2
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
21
|
.1*
|
|
|
|
List of Subsidiaries of Mid-Con Energy Partners, LP
|
|
23
|
.1
|
|
|
|
Consent of Grant Thornton LLP
|
|
23
|
.2
|
|
|
|
Consent of Cawley, Gillespie & Associates, Inc.
|
|
23
|
.3
|
|
|
|
Consent of GableGotwals (contained in Exhibit 5.1)
|
|
23
|
.4
|
|
|
|
Consent of Andrews Kurth LLP (contained in Exhibit 8.1)
|
|
24
|
.1*
|
|
|
|
Powers of Attorney (included on signature page)
|
|
99
|
.1
|
|
|
|
Report of Cawley, Gillespie & Associates, Inc. (included as
Appendix C to the prospectus) of reserves as of September 30,
2011
|
|
99
|
.2**
|
|
|
|
Report of Cawley, Gillespie & Associates, Inc. of reserves
as of December 31, 2010
|
|
|
|
*
|
|
Previously filed as an exhibit to
the Registration Statement (Registration
No. 333-176265)
filed on August 12, 2011.
|
|
|
|
**
|
|
Previously filed as an exhibit to
Amendment No. 1 the Registration Statement (Registration
No. 333-176265)
filed on October 5, 2011.
|
|
|
|
***
|
|
Previously filed as an exhibit to
Amendment No. 2 the Registration Statement (Registration
No. 333-176265)
filed on November 18, 2011.
|
The undersigned registrant hereby undertakes to provide to the
underwriters at the closing specified in the underwriting
agreement certificates in such denominations and registered in
such names as required by the underwriters to permit prompt
delivery to each purchaser.
Insofar as indemnification for liabilities arising under the
Securities Act may be permitted to directors, officers and
controlling persons of the registrant pursuant to the foregoing
provisions, or otherwise, the registrant has been advised that
in the opinion of the Securities and Exchange Commission such
indemnification is against public policy as expressed in the
Securities Act and is, therefore, unenforceable. In the event
that a claim for indemnification against such liabilities (other
than the payment by the registrant of expenses incurred or paid
by a director, officer or controlling person of the registrant
in the successful defense of any action, suit or proceeding) is
asserted by such director, officer or controlling person in
connection with the securities being registered, the registrant
will, unless in the opinion of its counsel the matter has been
settled by controlling precedent, submit to a court of
appropriate jurisdiction of the question whether such
indemnification by it is against public policy as expressed in
the Securities Act and will be governed by the final
adjudication of such issue.
The undersigned registrant hereby undertakes that:
(1) For purposes of determining any liability under the
Securities Act, the information omitted from the form of
prospectus filed as part of this registration statement in
reliance upon Rule 430A and contained in a form of
prospectus filed by the registrant pursuant to
Rule 424(b)(1) or (4) or 497(h) under the Securities
Act shall be deemed to be part of this registration statement as
of the time it was declared effective.
(2) For the purpose of determining any liability under the
Securities Act, each post-effective amendment that contains a
form of prospectus shall be deemed to be a new registration
statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be
the initial bona fide offering thereof.
The registrant undertakes to send to each limited partner at
least on an annual basis a detailed statement of any
transactions with Mid-Con Energy GP, LLC, our general partner,
or its affiliates, and of fees, commissions, compensation and
other benefits paid, or accrued to Mid-Con Energy GP, LLC or its
affiliates for the fiscal year completed, showing the amount
paid or accrued to each recipient and the services performed.
The registrant undertakes to provide to the limited partners the
financial statements required by
Form 10-K
for the first full fiscal year of operations of the partnership.
II-3
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as
amended, the registrant has duly caused this registration
statement to be signed on its behalf by the undersigned,
thereunto duly authorized, in the City of Tulsa, State of
Oklahoma, on December 1, 2011.
MID-CON
ENERGY PARTNERS, LP
By:
Mid-Con Energy GP, LLC, its general partner
|
|
|
|
By:
|
/s/ CHARLES
R. OLMSTEAD
|
Charles R. Olmstead, Chief Executive
Officer and Director
Pursuant to the requirements of the Securities Act of 1933, as
amended, this Registration Statement has been signed below by
the following persons in the capacities and on the dates
presented.
|
|
|
|
|
|
|
Name
|
|
Title
|
|
Date
|
|
|
|
|
|
|
*
S.
Craig George
|
|
Executive Chairman of the
Board of Directors
|
|
December 1, 2011
|
|
|
|
|
|
/s/ CHARLES
R. OLMSTEAD
Charles
R. Olmstead
|
|
Chief Executive Officer and Director
(Principal Executive Officer)
|
|
December 1, 2011
|
|
|
|
|
|
*
Jeffrey
R. Olmstead
|
|
Chief Financial Officer and Director
(Principal Financial Officer)
|
|
December 1, 2011
|
|
|
|
|
|
*
Dave
A. Culbertson
|
|
Chief Accounting Officer (Principal
Accounting Officer)
|
|
December 1, 2011
|
|
|
|
|
|
*
Peter
A. Leidel
|
|
Director
|
|
December 1, 2011
|
|
|
|
|
|
*
Cameron
O. Smith
|
|
Director
|
|
December 1, 2011
|
|
|
|
|
|
*
Robert
W. Berry
|
|
Director
|
|
December 1, 2011
|
|
|
|
|
|
*
Peter
Adamson III
|
|
Director
|
|
December 1, 2011
|
|
|
*By: |
/s/ Charles
R. Olmstead
Charles
R. Olmstead
Attorney-in-fact
|
II-4
EXHIBIT INDEX
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
1
|
.1***
|
|
|
|
Form of Underwriting Agreement
|
|
3
|
.1*
|
|
|
|
Certificate of Limited Partnership of Mid-Con Energy Partners, LP
|
|
3
|
.2*
|
|
|
|
Agreement of Limited Partnership of Mid-Con Energy Partners, LP
|
|
3
|
.3***
|
|
|
|
Form of First Amended and Restated Agreement of Limited
Partnership of Mid-Con Energy Partners, LP (included as
Appendix A to the prospectus)
|
|
3
|
.4*
|
|
|
|
Certificate of Formation of Mid-Con Energy GP, LLC
|
|
3
|
.5*
|
|
|
|
Limited Liability Company Agreement of Mid-Con Energy GP, LLC
|
|
3
|
.6***
|
|
|
|
Form of Amended and Restated Limited Liability Company Agreement
of Mid-Con Energy GP, LLC
|
|
5
|
.1
|
|
|
|
Opinion of GableGotwals as to the legality of the securities
being registered
|
|
8
|
.1
|
|
|
|
Opinion of Andrews Kurth LLP relating to tax matters
|
|
10
|
.1***
|
|
|
|
Form of Credit Agreement
|
|
10
|
.2***
|
|
|
|
Form of Contribution, Conveyance, Assumption and Merger Agreement
|
|
10
|
.3***
|
|
|
|
Form of Mid-Con Energy GP, LLC Long-Term Incentive Program
|
|
10
|
.4***
|
|
|
|
Form of Services Agreement
|
|
10
|
.5**
|
|
|
|
Form of Crude Oil Purchase Agreement between RDT Properties Inc.
(now known as
Mid-Con
Energy Operating, Inc.) and Sunoco Partners Marketing &
Terminals, L.P.
|
|
10
|
.6**
|
|
|
|
Form of Crude Oil Purchase Agreement between Mid-Con Energy
Operating, Inc. and Enterprise Crude Oil LLC
|
|
10
|
.7***
|
|
|
|
Form of Employment Agreement
|
|
21
|
.1*
|
|
|
|
List of Subsidiaries of Mid-Con Energy Partners, LP
|
|
23
|
.1
|
|
|
|
Consent of Grant Thornton LLP
|
|
23
|
.2
|
|
|
|
Consent of Cawley, Gillespie & Associates, Inc.
|
|
23
|
.3
|
|
|
|
Consent of GableGotwals (contained in Exhibit 5.1)
|
|
23
|
.4
|
|
|
|
Consent of Andrews Kurth LLP (contained in Exhibit 8.1)
|
|
24
|
.1*
|
|
|
|
Powers of Attorney (included on signature page)
|
|
99
|
.1
|
|
|
|
Report of Cawley, Gillespie & Associates, Inc.
(included as Appendix C to the prospectus) of reserves as
of September 30, 2011
|
|
99
|
.2**
|
|
|
|
Report of Cawley, Gillespie & Associates, Inc. of
reserves as of December 31, 2010
|
|
|
|
*
|
|
Previously filed as an exhibit to
the Registration Statement (Registration No. 333-176265) filed
on August 12, 2011.
|
|
|
|
**
|
|
Previously filed as an exhibit to
Amendment No. 1 the Registration Statement (Registration No.
333-176265) filed on October 5, 2011.
|
|
|
|
***
|
|
Previously filed as an exhibit to
Amendment No. 2 the Registration Statement (Registration No.
333-176265) filed on November 18, 2011.
|