As filed with the Securities and Exchange Commission on
October 5, 2011
Registration
No. 333-176265
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Amendment No. 1
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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2431 E. 61st Street, Suite 850
Tulsa, Oklahoma 74136
(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
October 5, 2011
PRELIMINARY
PROSPECTUS
Mid-Con Energy Partners,
LP
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 $ and
$ per common unit.
We have applied 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 June 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 % 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 45, 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
common units on the same terms and conditions as set forth above
if the underwriters sell more
than common
units in this offering.
The underwriters expect to deliver the common units on or
about ,
2011.
RBC
Capital Markets
,
2011
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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47
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48
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49
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49
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51
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53
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55
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56
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58
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59
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65
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69
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69
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69
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70
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71
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74
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74
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74
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79
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80
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84
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88
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88
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89
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92
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92
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93
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93
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94
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94
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96
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96
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98
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99
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100
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101
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108
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113
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117
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122
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123
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123
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123
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124
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124
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125
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127
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128
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128
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129
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130
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131
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131
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135
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137
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137
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138
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139
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140
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141
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141
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147
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150
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150
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150
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152
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152
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152
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152
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152
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153
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154
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154
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155
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156
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158
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159
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159
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159
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161
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161
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161
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161
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162
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163
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163
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163
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164
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164
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164
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165
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166
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167
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168
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169
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175
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180
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182
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183
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183
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186
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187
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188
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190
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194
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195
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196
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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
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
June 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 June 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 June 30, 2011, our total estimated proved reserves
were 7.9 MMBoe, of which approximately 98% were oil and 71%
were proved developed, both on a Boe basis. As of June 30,
2011, we operated 98% 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 June 30, 2011
was approximately 1,248 Boe per day and our total estimated
proved reserves had a
reserve-to-production
ratio of approximately 17 years. Our management team
developed approximately two-thirds 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 June 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 June 30, 2011 reserve report,
the average estimated decline rate for our proved developed
producing reserves is approximately 4% for 2011 and, on a
compounded average decline basis, approximately 11% for the
subsequent five years and approximately 10% thereafter.
Additionally, based on production estimates from this reserve
report, we believe that we have the ability to increase our
average net production from our existing proved reserves to
approximately 1,700 Boe per day during the next three years.
The following table summarizes information by core area
regarding our estimated oil and natural gas reserves as of
June 30, 2011 and our average net production for the month
ended June 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 June 30, 2011
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June 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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4,783
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100
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%
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99
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%
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58
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%
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1,892
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700
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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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2,043
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100
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%
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99
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%
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91
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%
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593
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340
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16
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154
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59
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Hugoton Basin
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720
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100
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%
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99
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%
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85
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%
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234
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141
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14
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43
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18
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Other
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361
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77
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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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231
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67
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15
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13
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4
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Total
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7,907
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99
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%
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98
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%
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71
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%
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2,950
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1,248
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17
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275
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123
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(1) |
The average
reserve-to-production
ratio is calculated by dividing estimated net proved reserves as
of June 30, 2011 by average net production for the month
ended June 30, 2011.
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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 June 30, 2011. We achieved approximately 75% of this
production increase primarily through ongoing waterflood
response from existing development activities and approximately
25% of the 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 43%, 44% and 24%,
respectively, of our estimated oil production from proved
reserves as of June 30, 2011. All of our derivative
contracts for 2012 and 2013 are either swaps with fixed price
settlements or collars with floors of at least $100. 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 $100.00 to $104.28 covering
approximately 13% and 31%, respectively, of our total proved
estimated production. In 2013, we have collars with a floor of
$100.00 and swaps with fixed price settlements of $105.80
covering 12% and 12%, respectively, of our total proved
estimated 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 derivative contracts at
predetermined times or on prescribed terms. Additionally, we may
take
3
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.
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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.
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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 % 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 June 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.
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Risks
Inherent in an Investment in Us
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Our general partner controls us, and the Founders and Yorktown
own a % 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.
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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
Mid-Con Energy Operating for aggregate consideration of
approximately $ million
immediately prior to the closing of this offering;
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We will enter into a merger and contribution 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
$ million credit facility
under which we expect to borrow approximately
$ million at the closing of
this offering to distribute approximately
$ 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, and to repay in full the
outstanding borrowings under our existing credit facilities;
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We will
issue
common units to the public, representing
a % limited partner interest in us;
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We will issue common
units to the Contributing Parties as additional consideration
for the merger;
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We will
issue
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 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
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We will enter into an omnibus agreement with our general partner
that will address certain indemnification matters.
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The number of common units that we will issue to the public and
the Contributing Parties, as reflected in the third and fourth
bullet points above, assume that the underwriters do not
exercise their option to purchase up to an
additional
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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%
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Common units held by the Contributing Parties:
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Common units held by the Founders
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%
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Common units held by Yorktown
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%
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Common units held by the other Contributing Parties
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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.
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(2)
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The Founders are S. Craig George,
Charles R. Olmstead and Jeffrey R. Olmstead.
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(3)
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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.
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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. Immediately prior to 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 operating
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 in Dallas, Texas
at . 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
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
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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.
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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 % 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
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Common units offered by us |
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common
units,
or
common units if the underwriters exercise in full their option
to purchase additional common units. |
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Units outstanding after this offering |
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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 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
$ million from this offering,
based upon the assumed initial public offering price of
$ per common unit, after deducting
underwriting discounts, a structuring fee and estimated
expenses, together with borrowings of approximately
$ million under our new
revolving credit facility, to: |
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distribute approximately
$ 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; and
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repay in full
$ million of indebtedness
outstanding under our existing revolving credit facilities.
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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 $ million. The
net proceeds from any exercise of such option will be used to
distribute additional cash consideration in respect of the
merger to the Contributing Parties. Please read Use of
Proceeds. |
11
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Cash distributions |
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We intend to pay an initial quarterly distribution of
$ per unit per quarter on all
common and general partner units
($ 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
June 30, 2011 was approximately
$ million and
$ 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
$ million (or an average of
approximately $ 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 $ per unit
per quarter ($ on an annualized
basis), or approximately % of the
initial quarterly distribution on our common units during that
period. For the twelve months ended June 30, 2011, we would
have generated available cash sufficient to pay a cash
distribution of $ per unit per
quarter ($ on an annualized
basis), or approximately % 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
June 30, 2011, please read Our Cash Distribution
Policy and Restrictions on DistributionsUnaudited Pro
Forma Available Cash for the Year Ended December 31, 2010
and the Twelve Months Ended June 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
$ per unit on all common and
general partner units for the four quarters ending
December 31, 2012. |
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Issuance of additional units |
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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. |
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Limited voting rights |
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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 % 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 % 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 ,
such unitholders will be allocated, on a cumulative basis, an
amount of federal taxable income for that period that will be
less than % 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 applied to list our common units on the NASDAQ Global
Market, subject to official notice of issuance, 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 June 30, 2011 and
for the six months ended June 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 June 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
June 30, 2011 and for the six months ended June 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
approximately 2% of our proved reserves by value, as calculated
using the standardized measure, as of June 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
common units and $ million in
cash;
|
|
|
|
|
|
the issuance to our general partner
of
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
common units in this offering and the application of the net
proceeds as described in Use of Proceeds; and
|
|
|
|
our borrowing of approximately
$ million under our new
credit facility and the application of the proceeds as described
in Use of Proceeds.
|
The unaudited pro forma balance sheet data assume the events
listed above occurred as of June 30, 2011. The unaudited
pro forma statement of operations data for the six months ended
June 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
|
|
|
Six Months
|
|
|
|
(consolidated)
|
|
|
|
Ended
|
|
|
Year Ended
|
|
|
Six Months Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Year Ended June 30,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
June 30,
|
|
|
December 31,
|
|
|
June 30,
|
|
Statement of Operations
Data:
|
|
2008
|
|
|
2009
|
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
(in thousands)
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
|
|
(restated)
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
13,667
|
|
|
$
|
10,246
|
|
|
|
$
|
5,729
|
|
|
$
|
16,853
|
|
|
$
|
7,482
|
|
|
$
|
15,609
|
|
|
$
|
15,516
|
|
|
$
|
14,888
|
|
Natural gas sales
|
|
|
618
|
|
|
|
2,172
|
|
|
|
|
743
|
|
|
|
1,418
|
|
|
|
803
|
|
|
|
657
|
|
|
|
1,392
|
|
|
|
657
|
|
Realized loss on derivatives, net
|
|
|
(804
|
)
|
|
|
(669
|
)
|
|
|
|
(350
|
)
|
|
|
(90
|
)
|
|
|
(91
|
)
|
|
|
(714
|
)
|
|
|
(90
|
)
|
|
|
(714
|
)
|
Unrealized gain (loss) on derivatives, net
|
|
|
(2,035
|
)
|
|
|
1,679
|
|
|
|
|
(147
|
)
|
|
|
(707
|
)
|
|
|
545
|
|
|
|
1,046
|
|
|
|
(707
|
)
|
|
|
984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
11,446
|
|
|
|
13,428
|
|
|
|
|
5,975
|
|
|
|
17,474
|
|
|
|
8,739
|
|
|
|
16,598
|
|
|
|
16,111
|
|
|
|
15,815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
5,005
|
|
|
|
5,369
|
|
|
|
|
2,431
|
|
|
|
6,237
|
|
|
|
3,038
|
|
|
|
3,550
|
|
|
|
4,788
|
|
|
|
2,967
|
|
Oil and gas production taxes
|
|
|
946
|
|
|
|
631
|
|
|
|
|
269
|
|
|
|
822
|
|
|
|
384
|
|
|
|
655
|
|
|
|
741
|
|
|
|
609
|
|
Dry holes and abandonments of unproved properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,418
|
|
|
|
44
|
|
|
|
772
|
|
|
|
514
|
|
|
|
772
|
|
Geological and geophysical
|
|
|
1,296
|
|
|
|
507
|
|
|
|
|
|
|
|
|
394
|
|
|
|
287
|
|
|
|
58
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
1,599
|
|
|
|
2,293
|
|
|
|
|
2,552
|
|
|
|
5,851
|
|
|
|
3,445
|
|
|
|
2,419
|
|
|
|
3,014
|
|
|
|
2,081
|
|
Accretion of discount on asset retirement obligations
|
|
|
56
|
|
|
|
78
|
|
|
|
|
58
|
|
|
|
127
|
|
|
|
64
|
|
|
|
32
|
|
|
|
63
|
|
|
|
32
|
|
General and administrative
|
|
|
1,871
|
|
|
|
1,767
|
|
|
|
|
704
|
|
|
|
982
|
|
|
|
587
|
|
|
|
476
|
|
|
|
982
|
|
|
|
476
|
|
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
|
|
|
|
7,849
|
|
|
|
7,962
|
|
|
|
11,362
|
|
|
|
6,937
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
673
|
|
|
|
2,783
|
|
|
|
|
(9,247
|
)
|
|
|
(243
|
)
|
|
|
890
|
|
|
|
8,636
|
|
|
|
4,749
|
|
|
|
8,878
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expenses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income and other
|
|
|
115
|
|
|
|
119
|
|
|
|
|
35
|
|
|
|
218
|
|
|
|
151
|
|
|
|
62
|
|
|
|
126
|
|
|
|
4
|
|
Interest expense
|
|
|
(3
|
)
|
|
|
(93
|
)
|
|
|
|
(2
|
)
|
|
|
(98
|
)
|
|
|
(17
|
)
|
|
|
(237
|
)
|
|
|
(1,200
|
)
|
|
|
(600
|
)
|
Gain on sale of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
354
|
|
|
|
353
|
|
|
|
1,209
|
|
|
|
|
|
|
|
|
|
Other revenue and expenses, net
|
|
|
108
|
|
|
|
298
|
|
|
|
|
118
|
|
|
|
847
|
|
|
|
299
|
|
|
|
576
|
|
|
|
|
|
|
|
|
|
Income tax expensecurrent
|
|
|
|
|
|
|
(625
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (expense) benefitdeferred
|
|
|
(261
|
)
|
|
|
502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
632
|
|
|
$
|
2,984
|
|
|
|
$
|
(9,096
|
)
|
|
$
|
1,078
|
|
|
$
|
1,676
|
|
|
$
|
10,246
|
|
|
$
|
3,675
|
|
|
$
|
8,282
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of limited partner units outstanding
(basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
4,471
|
|
|
$
|
3,773
|
|
|
|
$
|
2,836
|
|
|
$
|
10,593
|
|
|
$
|
4,197
|
|
|
$
|
11,389
|
|
|
|
10,307
|
|
|
|
10,779
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
4,221
|
|
|
$
|
10,935
|
|
|
|
$
|
965
|
|
|
$
|
11,798
|
|
|
$
|
6,685
|
|
|
$
|
5,192
|
|
|
|
|
|
|
|
|
|
Investing activities
|
|
|
(7,646
|
)
|
|
|
(12,448
|
)
|
|
|
|
(5,018
|
)
|
|
|
(22,726
|
)
|
|
|
(8,284
|
)
|
|
|
(13,351
|
)
|
|
|
|
|
|
|
|
|
Financing activities
|
|
|
147
|
|
|
|
4,841
|
|
|
|
|
(1,164
|
)
|
|
|
10,387
|
|
|
|
1,058
|
|
|
|
8,377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 June 30,
|
|
|
|
|
|
As of June 30,
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
2011
|
|
|
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
|
|
(restated)
|
|
|
|
|
|
(restated)
|
|
Working capital(1)
|
|
|
$
|
2,420
|
|
|
$
|
(1,256
|
)
|
|
|
|
|
|
$
|
4,383
|
|
|
|
|
|
|
$
|
4,383
|
|
Total assets
|
|
|
|
40,496
|
|
|
|
56,867
|
|
|
|
|
|
|
|
72,390
|
|
|
|
|
|
|
|
72,150
|
|
Total debt
|
|
|
|
337
|
|
|
|
5,513
|
|
|
|
|
|
|
|
13,310
|
|
|
|
|
|
|
|
30,000
|
|
Partners capital
|
|
|
|
36,779
|
|
|
|
43,072
|
|
|
|
|
|
|
|
56,098
|
|
|
|
|
|
|
|
39,168
|
|
|
|
|
(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; 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
|
|
|
Six Months
|
|
|
Six Months
|
|
|
Year
|
|
|
Six Months
|
|
|
|
(consolidated)
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Year Ended June 30,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
June 30,
|
|
|
June 30,
|
|
|
December 31,
|
|
|
June 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
(in thousands)
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
632
|
|
|
$
|
2,984
|
|
|
|
$
|
(9,096
|
)
|
|
$
|
1,078
|
|
|
$
|
1,676
|
|
|
$
|
10,246
|
|
|
$
|
3,675
|
|
|
$
|
8,282
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit)deferred
|
|
|
261
|
|
|
|
(502
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expensecurrent
|
|
|
|
|
|
|
625
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
3
|
|
|
|
93
|
|
|
|
|
2
|
|
|
|
98
|
|
|
|
17
|
|
|
|
237
|
|
|
|
1,200
|
|
|
|
600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
1,599
|
|
|
|
2,293
|
|
|
|
|
2,552
|
|
|
|
5,851
|
|
|
|
3,445
|
|
|
|
2,419
|
|
|
|
3,014
|
|
|
|
2,081
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of discount on asset retirement obligations
|
|
|
56
|
|
|
|
78
|
|
|
|
|
58
|
|
|
|
127
|
|
|
|
64
|
|
|
|
32
|
|
|
|
63
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized (gain) loss on derivatives, net
|
|
|
2,035
|
|
|
|
(1,679
|
)
|
|
|
|
147
|
|
|
|
707
|
|
|
|
(545
|
)
|
|
|
(1,046
|
)
|
|
|
707
|
|
|
|
(984
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of proved oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
|
9,208
|
|
|
|
1,886
|
|
|
|
|
|
|
|
|
|
|
|
1,260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dry holes and abandonments of unproved properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,418
|
|
|
|
44
|
|
|
|
772
|
|
|
|
514
|
|
|
|
772
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sales of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(354
|
)
|
|
|
(353
|
)
|
|
|
(1,209
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
(115
|
)
|
|
|
(119
|
)
|
|
|
|
(35
|
)
|
|
|
(218
|
)
|
|
|
(151
|
)
|
|
|
(62
|
)
|
|
|
(126
|
)
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
4,471
|
|
|
$
|
3,773
|
|
|
|
$
|
2,836
|
|
|
$
|
10,593
|
|
|
$
|
4,197
|
|
|
$
|
11,389
|
|
|
$
|
10,307
|
|
|
$
|
10,779
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
Six Months
|
|
|
Six Months
|
|
|
|
|
|
|
|
|
|
(consolidated)
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
|
|
|
|
|
|
Year Ended June 30,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
4,221
|
|
|
$
|
10,935
|
|
|
|
$
|
965
|
|
|
$
|
11,798
|
|
|
$
|
6,685
|
|
|
$
|
5,192
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in working capital
|
|
|
521
|
|
|
|
(7,761
|
)
|
|
|
|
1,904
|
|
|
|
(1,085
|
)
|
|
|
(2,354
|
)
|
|
|
6,022
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expensecurrent
|
|
|
|
|
|
|
625
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bad debt expense
|
|
|
(159
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
3
|
|
|
|
93
|
|
|
|
|
2
|
|
|
|
98
|
|
|
|
17
|
|
|
|
237
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
(115
|
)
|
|
|
(119
|
)
|
|
|
|
(35
|
)
|
|
|
(218
|
)
|
|
|
(151
|
)
|
|
|
(62
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
4,471
|
|
|
$
|
3,773
|
|
|
|
$
|
2,836
|
|
|
$
|
10,593
|
|
|
$
|
4,197
|
|
|
$
|
11,389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 June 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 approximately 2% of our proved reserves by
value, as calculated using the standardized measure, as of that
date.
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 51% from December 31, 2010 to June 30,
2011 as a result of production increases in our Southern
Oklahoma core area, acquisition of the War Party I and II
Units in the Hugoton Basin, and acquisitions and workovers in
our Northeastern Oklahoma core area. We spent a total of
$19.3 million and $23.3 million in capital
expenditures for the year ended December 31, 2010 and the
six months ended June 30, 2011, respectively, which
contributed to increasing the June 30, 2011 reserves.
During the first six months of 2011, we spent approximately
$12.3 million in the Southern Oklahoma core area resulting
in production increases and reclassifications of
0.7 million barrels from proved undeveloped reserves to
proved developed reserves. Additionally, we spent approximately
$7.8 million during the first six months of 2011 to acquire
new leases in the Hugoton Basin and Northeastern Oklahoma, with
proved developed reserves of approximately 0.8 million
barrels. Another $0.8 million in workover activities during
the first six months of 2011 in Northeastern Oklahoma added
0.4 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
June 30, 2011 included in this prospectus in evaluating the
material presented below.
|
|
|
|
|
|
|
|
|
|
|
Pro Forma as of
|
|
|
Pro Forma as of
|
|
|
|
December 31,
|
|
|
June 30,
|
|
|
|
2010(1)
|
|
|
2011(2)
|
|
|
Reserve Data:
|
|
|
|
|
|
|
|
|
Estimated proved reserves:
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
6,938
|
|
|
|
7,733
|
|
Natural Gas (MMcf)
|
|
|
1,070
|
|
|
|
1,053
|
|
|
|
|
|
|
|
|
|
|
Total (Mboe)
|
|
|
7,116
|
|
|
|
7,907
|
|
|
|
|
|
|
|
|
|
|
Proved developed (MBoe)
|
|
|
3,710
|
|
|
|
5,605
|
|
Oil (MBbl)
|
|
|
3,531
|
|
|
|
5,430
|
|
Natural Gas (MMcf)
|
|
|
1,082
|
|
|
|
1,053
|
|
Proved undeveloped (MBoe)
|
|
|
3,406
|
|
|
|
2,302
|
|
Oil (MBbl)
|
|
|
3,407
|
|
|
|
2,302
|
|
Natural Gas (MMcf)
|
|
|
(12
|
)
|
|
|
0
|
|
Proved developed reserves as a percentage of total proved
reserves
|
|
|
52.1
|
%
|
|
|
70.9
|
%
|
Standardized Measure (in millions)(3)
|
|
$
|
182.1
|
|
|
$
|
233.1
|
|
Oil and Natural Gas Prices(4):
|
|
|
|
|
|
|
|
|
Oil NYMEX WTI per Bbl
|
|
$
|
79.43
|
|
|
|
89.96
|
|
Natural gas NYMEX Henry Hub per MMBtu
|
|
$
|
4.37
|
|
|
$
|
4.20
|
|
|
|
|
(1)
|
|
Excludes certain properties, which
represented approximately 2% of our proved reserves by value, as
calculated using the standardized measure, as of June 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 Mid-Con Energy
Operating 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 $89.96 per Bbl for oil and $4.20 per MMBtu for natural gas
at June 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 $7.56 per Mcf, respectively, on a
pro forma basis. For the six months ended June 30, 2011,
the relevant average realized prices for oil and natural gas
were $93.55 per Bbl and $8.84 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 six months ended June 30,
2011.
|
20
|
|
|
|
|
|
|
|
|
|
|
Pro Forma(1)
|
|
|
|
|
Six Months
|
|
|
Year Ended
|
|
Ended
|
|
|
December 31,
|
|
June 30,
|
|
|
2010
|
|
2011
|
|
|
(restated)
|
|
|
|
Production and operating data:
|
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
209
|
|
|
|
159
|
|
Natural gas (MMcf)
|
|
|
187
|
|
|
|
74
|
|
Total (MBoe)
|
|
|
240
|
|
|
|
172
|
|
Average net production (Boe/d)
|
|
|
658
|
|
|
|
950
|
|
Average sales price:(2)
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
74.15
|
|
|
$
|
93.55
|
|
Natural gas (per Mcf)(3)
|
|
$
|
7.56
|
|
|
$
|
8.84
|
|
Average price per Boe
|
|
$
|
67.15
|
|
|
$
|
92.19
|
|
Average unit costs per Boe:
|
|
|
|
|
|
|
|
|
Oil and natural gas production expenses
|
|
$
|
19.95
|
|
|
$
|
17.29
|
|
Production taxes
|
|
$
|
3.09
|
|
|
$
|
3.56
|
|
General and administrative and other(4)
|
|
$
|
4.06
|
|
|
$
|
2.49
|
|
Depreciation, depletion and amortization
|
|
$
|
12.56
|
|
|
$
|
12.13
|
|
|
|
|
(1)
|
|
Excludes production from certain
properties, which represent approximately 2% of our proved
reserves by value, as calculated using the standardized measure,
as of June 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 $12.50 per Boe, for the year ended
December 31, 2010 and $1.5 million, or $8.72 per Boe,
for the six months ended June 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
$ (or
$ 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 June 30,
2011.
On a pro forma historical basis, assuming we had completed our
formation transactions on July 1, 2010, our unaudited pro
forma available cash generated during the twelve months ended
June 30, 2011 would have been approximately
$ million, which would have
been sufficient to pay only % 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 June 30, 2011, please read Our
Cash Distribution Policy and Restrictions on
DistributionsUnaudited
22
Pro Forma Available Cash for the Year Ended December 31,
2010 and the Twelve Months Ended June 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;
|
|
|
|
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.
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
24
Bbl to a low of $31.41 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 total proved developed producing 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 we do not expect that our new credit facility will require
us to hedge a minimum percentage of our production, it 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 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.
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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 as of that date on a pro forma
basis would have decreased by $36.7 million, from
$183.2 million to $146.5 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
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.
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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 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.
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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 one customer for our
production sales and we may experience a temporary decline in
revenues and production if we lose that customer.
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. Our
production is marketed to Sunoco Logistics under crude oil
purchase contracts with Mid-Con Energy Operating. By selling a
substantial majority of our production to Sunoco Logistics under
these contracts, we believe that we 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.
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.
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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.
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.
We expect that 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.
We expect that 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
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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. 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,
while we do not expect that our new credit facility will require
us to hedge a minimum percentage of our production, it 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.
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
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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, 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
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refractured. The EPA will receive public comment and hold
hearings regarding the proposed rules and must take final action
on them by February 28, 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 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
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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. 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 % 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 an aggregate of
approximately % of our outstanding
common units. 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 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.
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 consummation 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.
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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 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.
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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.
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; or
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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
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ownership of stock in a parent corporation organized under the
laws of the United States or of any state thereof.
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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
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 % of our outstanding
voting 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
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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.
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 common
units or approximately % 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.
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 $ per unit.
The initial offering price of $
per common unit exceeds our pro forma net tangible book value
after this offering of $ per
common unit. Based on the initial offering price of
$ per common unit, our unitholders
will incur immediate and substantial dilution of
$ 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, and we do not anticipate limitations 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.
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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.
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
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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.
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
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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 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.
43
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.
We will adopt certain valuation methodologies and monthly
conventions for federal income tax purposes that may result in a
shift of income, gain, loss and deduction between our general
partner and our unitholders. The IRS may challenge this
treatment, which could adversely affect the value of the
units.
When we issue additional units or engage in certain other
transactions, we will determine the fair market value of our
assets and allocate any unrealized gain or loss attributable to
our assets to the capital accounts of our unitholders and our
general partner. Our methodology may be viewed as understating
the value of our assets. In that case, there may be a shift of
income, gain, loss and deduction between certain unitholders and
our general partner, which may be unfavorable to such
unitholders. Moreover, under our valuation methods, subsequent
purchasers of units may have a greater portion of their Internal
Revenue Code Section 743(b) adjustment allocated to our
tangible assets and a lesser portion allocated to our intangible
assets. The IRS may challenge our valuation methods, or our
allocation of the Section 743(b) adjustment attributable to
our tangible and intangible assets, and allocations of taxable
income, gain, loss and deduction between our general partner and
certain of our unitholders.
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 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
44
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
$ million from this offering,
based upon the assumed initial public offering price of
$ per common unit, after deducting
underwriting discounts, a structuring fee and estimated offering
expenses, together with borrowings of approximately
$ million under our new
revolving credit facility, to:
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distribute approximately
$ 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; and
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repay in full $ million of
indebtedness outstanding under our existing credit facilities.
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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.
As of June 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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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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$
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Distribution to Contributing Parties(1)
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$
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Borrowings under our new credit facility
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$
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Repayment of indebtedness under our
existing credit facilities
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$
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Underwriting discounts, a structuring fee
and estimated offering expenses
payable by us
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$
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Total
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$
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Total
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$
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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
$ million, and the total
distribution to the Contributing Parties would be approximately
$ million.
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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
additional common units in full, the additional net proceeds
would be approximately
$ 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
additional common units in full, we will issue the number of
remaining common units to the Contributing Parties upon the
expiration of the option
( 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 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 $ 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
$ 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 $ per
common unit, would increase net proceeds to us from this
offering by approximately
$ 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 $ per common
unit, would decrease the net proceeds to us from this offering
by approximately $ million.
46
CAPITALIZATION
The following table shows:
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historical capitalization as of June 30, 2011; and
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our as adjusted capitalization as of June 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.
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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 June 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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$
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440
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$
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440
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Long-term debt
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$
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13,310
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$
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30,000
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Members/partners capital/net equity:
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Predecessor members capital
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$
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56,098
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$
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39,168
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Common units held by purchasers in this offering
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Common units held by the Contributing Parties
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General partner interest
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Total members/partners capital/net equity
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56,098
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Total capitalization
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$
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69,408
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$
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47
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
$ per common unit (the midpoint of
the price range set forth on the cover of this prospectus), on a
pro forma basis as of June 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
$ million, or
$ 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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Pro forma net tangible book value per unit before this
offering(1)
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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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Less: Pro forma net tangible book value per unit after this
offering(2)
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Immediate dilution in tangible net book value per common unit to
purchasers in the offering(3)(4)
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$
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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
( common
units to be issued to the Contributing Parties and the issuance
of 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
( common
units
and general
partner units).
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(3)
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If the initial public offering
price were to increase or decrease by $1.00 per common unit,
then dilution in net tangible book value per common unit would
equal $ and
$ , respectively.
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(4)
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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.
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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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Units Acquired
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Total Consideration
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Number
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Percent
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Amount
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Percent
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(in thousands)
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General partner and Contributing Parties(1)(2)
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%
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$
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%
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Purchasers in the offering(3)
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%
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%
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Total
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100.0
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%
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$
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100.0
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%
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(1)
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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
common units
and
general partner units.
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(2)
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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
June 30, 2011.
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(3)
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Total consideration is after
deducting underwriting discounts, a structuring fee and
estimated offering expenses.
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48
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 six
months ended June 30, 2011 and our unaudited pro forma
financial statements for the year ended December 31, 2010
and six months ended June 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 except as provided in our partnership agreement.
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,
we anticipate that 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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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
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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.
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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 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 %
of our outstanding common units
or % of our limited partner
interests. Please read The Partnership
AgreementAmendment of the Partnership Agreement.
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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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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.
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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
production or increases in our general and administrative
expenses, principal and interest payments on our outstanding
debt, tax expenses, working capital requirements or
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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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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.
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Capital expenditures reduce cash available to pay distributions
to the extent such amounts are funded from cash generated by
operating activities.
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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.
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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, nor do we expect
any limitations 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
$ per unit per quarter, or
$ 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
$ million per quarter, or
$ 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 plan 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.
51
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 $ per unit per
quarter, or $ per unit on an
annualized basis.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Initial Quarterly Distribution
|
|
|
|
Units
|
|
|
One Quarter
|
|
|
Four Quarters
|
|
|
Common units held by the public(1)(2)
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
Common units held by the Contributing Parties(1)(2)(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
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 common
units, we will issue the
additional
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 plan that our
general partner is expected to adopt prior to the closing of
this offering.
|
|
|
|
(3)
|
|
Includes
common units held by the Founders
and 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
52
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 % of our outstanding
common units, or % 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 $ per
unit for the year ending December 31, 2012. In those
sections, we present two tables, consisting of:
|
|
|
|
|
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
June 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
|
|
|
|
|
|
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 June 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 $0.1 million. This amount would
have been sufficient to pay a cash distribution of
$ per unit per quarter
($ on an annualized basis), or
approximately % of the initial
quarterly distribution on our common units during that period.
If we had completed the transactions contemplated in this
prospectus on July 1, 2010, our unaudited pro forma
available cash generated for the twelve months ended
June 30, 2011 would have been approximately
$7.3 million. This amount would have been sufficient to pay
a cash distribution of $ per unit
per quarter ($ on an annualized
basis), or approximately % of the
initial quarterly distribution on our common units during that
period.
Our unaudited pro forma cash available for distribution does not
include 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. Such
53
incremental general and administrative expenses are not
reflected in our historical and pro forma financial statements.
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 June 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 July 1, 2010, respectively. Each
of the pro forma adjustments reflected or presented below is
explained in the footnotes to such adjustments.
54
Mid-Con
Energy Partners, LP
Unaudited Pro Forma Available Cash
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
Year
|
|
|
Twelve Months
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
June 30,
|
|
|
|
2010
|
|
|
2011
|
|
|
|
(in thousands, except per unit data)
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
Net income
|
|
$
|
3,675
|
|
|
$
|
9,938
|
|
Plus:
|
|
|
|
|
|
|
|
|
Income tax expense (benefit), if any
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
1,200
|
|
|
|
1,200
|
|
Depreciation, depletion and amortization
|
|
|
3,014
|
|
|
|
3,785
|
|
Accretion of discount on asset retirement obligations
|
|
|
63
|
|
|
|
158
|
|
Unrealized (gain) loss on derivatives, net
|
|
|
707
|
|
|
|
(77
|
)
|
Impairment of proved oil and gas properties
|
|
|
1,260
|
|
|
|
1,234
|
|
Dry hole costs and abandonments of unproved properties
|
|
|
514
|
|
|
|
1,263
|
|
Interest income
|
|
|
(126
|
)
|
|
|
(31
|
)
|
(Gain) loss on sale of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA(1)
|
|
$
|
10,307
|
|
|
$
|
17,470
|
|
Less:
|
|
|
|
|
|
|
|
|
Incremental general and administrative expense(2)
|
|
|
3,000
|
|
|
|
3,000
|
|
Cash interest expense(3)
|
|
|
1,200
|
|
|
|
1,200
|
|
Maintenance capital expenditures(4)
|
|
|
1,014
|
|
|
|
1,446
|
|
|
|
|
|
|
|
|
|
|
Pro Forma Available cash
|
|
$
|
5,093
|
|
|
$
|
11,824
|
|
Pro Forma Annualized distributions per unit
|
|
|
|
|
|
|
|
|
Pro Forma Estimated annual cash distributions:
|
|
|
|
|
|
|
|
|
Distributions on common units held by purchasers in this offering
|
|
|
|
|
|
|
|
|
Distributions on common units held by affiliates of our general
partner
|
|
|
|
|
|
|
|
|
Distributions on general partner units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total estimated annual cash distributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shortfall
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent of initial quarterly distributions payable to common
unitholders
|
|
|
|
|
|
|
|
|
|
|
|
(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
$ million credit facility
under which we expect to incur approximately $30.0 million
of borrowings upon the closing of this offering. The pro forma
cash interest expense is based on $30.0 million of
borrowings at an assumed weighted-average rate of 4.0%.
|
|
|
|
(4)
|
|
We define maintenance capital
expenditures as those costs we expect to make on an ongoing
basis to maintain our production levels and asset base,
including over the long-term. We define growth capital
expenditures as those costs we expect will increase our
production levels and asset base over the long-term. 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
$18.3 million and $34.0 million of capital
expenditures for the year ended December 31, 2010 and the
twelve months ended June 30, 2011, respectively, which are
the amounts of capital expenditures that we believe would have
been growth capital expenditures in those periods.
|
55
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
$ per common unit and general
partner unit, or $ 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 $ 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 plan 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.
56
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 $ per unit for the
year ending December 31, 2012, our aggregate cash available
to pay distributions must be at least approximately
$ 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
$ million over that period is
approximately $ 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.
57
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)
|
|
$
|
49,706
|
|
Less:
|
|
|
|
|
Lease operating expenses
|
|
|
8,080
|
|
Oil and gas production taxes
|
|
|
2,364
|
|
General and administrative(2)
|
|
|
4,000
|
|
Depreciation, depletion and amortization
|
|
|
9,000
|
|
Interest expense
|
|
|
1,200
|
|
|
|
|
|
|
Net income excluding unrealized gains (losses) on derivatives
|
|
$
|
25,062
|
|
Adjustments to reconcile net income excluding unrealized
derivative gains (losses) to estimated Adjusted EBITDA:
|
|
|
|
|
Add:
|
|
|
|
|
Depreciation, depletion and amortization
|
|
$
|
9,000
|
|
Interest expense
|
|
|
1,200
|
|
|
|
|
|
|
Estimated Adjusted EBITDA(3)
|
|
$
|
35,262
|
|
Adjustments to reconcile estimated Adjusted EBITDA to
estimated cash available for distribution:
|
|
|
|
|
Less:
|
|
|
|
|
Cash interest expense
|
|
$
|
1,200
|
|
Maintenance capital expenditures(4)
|
|
|
6,000
|
|
|
|
|
|
|
Estimated cash available for distribution
|
|
$
|
28,062
|
|
Annualized initial quarterly distribution per unit
|
|
|
|
|
Estimated annual cash distributions(5):
|
|
|
|
|
Distributions on common units held by purchasers in this offering
|
|
|
|
|
Distributions on common units held by affiliates of our general
partner
|
|
|
|
|
Distributions on general partner units
|
|
|
|
|
Total estimated annual cash distributions
|
|
|
|
|
Excess cash available for distribution
|
|
|
|
|
|
|
|
(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 production levels and
asset base, including 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 plan that our general
partner is expected to adopt prior to the closing of this
offering.
|
58
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 June 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 June 30,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Annual production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
209
|
|
|
|
273
|
|
|
|
539
|
|
Natural gas (MMcf)
|
|
|
187
|
|
|
|
159
|
|
|
|
123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
240
|
|
|
|
300
|
|
|
|
560
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average net daily production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl/d)
|
|
|
573
|
|
|
|
749
|
|
|
|
1,474
|
|
Natural Gas (Mcf/d)
|
|
|
504
|
|
|
|
435
|
|
|
|
335
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Boe/d)
|
|
|
658
|
|
|
|
822
|
|
|
|
1,529
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We estimate that our total oil and natural gas production for
the year ending December 31, 2012 will be 1,529 Boe per day
as compared to 657 Boe per day on a pro forma basis for the year
59
ended December 31, 2010 and 822 Boe per day on a pro forma
basis for the twelve months ended June 30, 2011. For the
months ended June 30, 2011, July 31, 2011 and
August 31, 2011, our average net production was 1,248 Boe
per day, 1,266 Boe per day and 1,317 Boe per day, respectively.
The 2012 forecast reflects a 212 Boe per day production increase
from our August 31, 2011 production, which we believe we
will achieve through continued drilling activities, ongoing
response to our existing waterflood projects and from workovers
of existing wells.
Since January 2010 we have drilled approximately 45 gross
(26 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 $12.5 million on this drilling program in
2010 and have spent approximately $14.0 million in the
first six months of 2011. We expect to spend approximately
$8.3 million on these activities in the second half of
2011, a substantial portion of which will be completed by
October 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 1,529
Boe per day for the year ending December 31, 2012. In
addition, we estimate that we will spend $6.0 million in
2012 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 December 31, 2010 and the twelve months ended
June 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 June 30,
|
|
December 31,
|
|
|
2010
|
|
2011
|
|
2012
|
|
Average oil sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily NYMEX-WTI oil price per Bbl
|
|
$
|
79.61
|
|
|
$
|
89.51
|
|
|
$
|
90.00
|
|
Differential to NYMEX-WTI oil per Bbl
|
|
$
|
(5.46
|
)
|
|
$
|
(3.22
|
)
|
|
$
|
(4.35
|
)
|
Realized oil sales price per Bbl (excluding cash settlements of
derivatives)
|
|
$
|
74.15
|
|
|
$
|
86.29
|
|
|
$
|
85.65
|
|
Realized oil sales price per Bbl (including cash settlements of
derivatives)
|
|
$
|
74.31
|
|
|
$
|
83.23
|
|
|
$
|
90.64
|
|
Average natural gas sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily NYMEX-Henry Hub natural gas price per MMBtu
|
|
$
|
4.38
|
|
|
$
|
4.20
|
|
|
$
|
4.20
|
|
Differential to NYMEX-Henry Hub natural gas per MMBtu
|
|
$
|
3.18
|
|
|
$
|
3.81
|
|
|
$
|
2.36
|
|
Realized natural gas sales price per Mcf(1)
|
|
$
|
7.56
|
|
|
$
|
8.01
|
|
|
$
|
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
60
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 reflected in our reserve
report as of June 30, 2011:
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
Natural Gas
|
Operating Area
|
|
Per Bbl
|
|
Per Mcf(1)
|
|
Southern Oklahoma
|
|
$
|
(5.66
|
)
|
|
$
|
1.00
|
|
Northeastern Oklahoma
|
|
$
|
(1.63
|
)
|
|
$
|
(1.62
|
)
|
Hugoton Basin
|
|
$
|
(3.95
|
)
|
|
$
|
(1.20
|
)
|
Other
|
|
$
|
(1.60
|
)
|
|
$
|
4.38
|
|
Weighted Average
|
|
$
|
(4.35
|
)
|
|
$
|
2.36
|
|
|
|
|
(1)
|
|
Realized natural gas sales price
per Mcf includes the sale of natural gas liquids.
|
Use of Commodity Derivative Contracts. For
purposes of our forecast, we have assumed that our commodity
derivative contracts will cover 240 MBbl, or approximately
44%, of our forecasted total oil production of 539 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
|
|
|
168,000
|
|
|
$
|
101.83
|
|
|
|
72,000
|
|
|
$
|
100.00
|
|
|
$
|
117.00
|
|
% of forecasted oil production
|
|
|
31.15
|
%
|
|
|
|
|
|
|
13.35
|
%
|
|
|
|
|
|
|
|
|
Operating Revenues and Realized Commodity Derivative
Gains. The following table illustrates the
primary components of operating revenues and realized commodity
derivative gains on
61
a pro forma basis for the year ended December 31, 2010 and
the twelve months ended June 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 June 30,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
|
(in thousands)
|
|
|
Oil:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenues
|
|
$
|
15,516
|
|
|
$
|
23,590
|
|
|
$
|
46,195
|
|
Realized oil derivative instruments gain (loss)
|
|
|
(90
|
)
|
|
|
(837
|
)
|
|
|
2,707
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
15,426
|
|
|
$
|
22,753
|
|
|
$
|
48,902
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenues(1)
|
|
$
|
1,392
|
|
|
$
|
1,273
|
|
|
$
|
804
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
Pro Forma
|
|
|
Forecasted
|
|
|
|
Year Ended
|
|
|
Twelve Months
|
|
|
Year Ending
|
|
|
|
December 31,
|
|
|
Ended June 30,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
|
(in thousands)
|
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
16,908
|
|
|
$
|
24,863
|
|
|
$
|
46,999
|
|
Commodity derivative instruments gain (loss)
|
|
|
(90
|
)
|
|
|
(837
|
)
|
|
|
2,707
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue and realized commodity derivative instruments
gains
|
|
$
|
16,818
|
|
|
$
|
24,026
|
|
|
$
|
49,706
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 $1.4 million of our total capital
expenditures for the year ended December 31, 2010 and the
twelve months ended June 30, 2011, respectively, would have
been maintenance capital expenditures. We believe that the
balance of our capital expenditures for those periods,
$18.3 million and $34.0 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
June 30, 2011 in order to maintain our forecasted
production level of 1,529 Boe per day. For the forecast period,
we estimate that we will drill 8 gross (5 net) wells and
spend additional maintenance capital on workovers at an
aggregate net cost of approximately $6.0 million in order
to maintain this production level.
62
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 June 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 June 30,
|
|
December 31,
|
|
|
2010
|
|
2011
|
|
2012
|
|
Lease operating expenses (in thousands)
|
|
$
|
4,788
|
|
|
$
|
5,734
|
|
|
$
|
8,080
|
|
Lease operating expenses (per Boe)
|
|
$
|
19.95
|
|
|
$
|
19.11
|
|
|
$
|
14.43
|
|
We estimate that our lease operating expenses for the year
ending December 31, 2012 will be approximately
$8.1 million. On a pro forma basis, for the year ended
December 31, 2010 and the twelve months ended June 30,
2011, lease operating expenses were $4.8 million and
$5.7 million, respectively. The increase in forecasted
lease operating expenses is primarily a 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 June 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 June 30,
|
|
December 31,
|
|
|
2010
|
|
2011
|
|
2012
|
|
|
(in thousands)
|
|
Oil and natural gas revenues, excluding the effect of our
commodity derivative contracts
|
|
$
|
16,908
|
|
|
$
|
24,863
|
|
|
$
|
46,999
|
|
Production taxes
|
|
$
|
741
|
|
|
$
|
1,009
|
|
|
$
|
2,364
|
|
Production taxes as a percentage of revenue
|
|
|
4.38
|
%
|
|
|
4.05
|
%
|
|
|
5.03
|
%
|
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.
63
General and Administrative Expenses. At 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. Based on our reserve report as of
June 30, 2011, we estimate that our depreciation, depletion
and amortization expense for the year ending December 31,
2012 will be approximately $9.0 million, as compared to
$3.0 million and $3.8 million on a pro forma basis for
the year ending December 31, 2010 and the twelve months
ended June 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 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
$30.0 million in revolving debt under our new
$ million credit facility. We
estimate that the borrowings will bear interest at a weighted
average rate of approximately 4.0%. Based on these assumptions,
we estimate that our cash interest expense for the year ending
December 31, 2012 will be $1.2 million as compared to
$1.2 million on a pro forma basis for both the year ended
December 31, 2010 and the twelve months ended June 30,
2011.
We expect that our new credit facility will contain financial
covenants that require us to maintain a leverage ratio of not
more
than
to 1.0x and a current ratio of not less
than
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. We expect that the 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.
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;
|
64
|
|
|
|
|
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.
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)
|
|
|
485
|
|
|
|
539
|
|
|
|
593
|
|
Natural gas (MMcf)
|
|
|
110
|
|
|
|
123
|
|
|
|
135
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
504
|
|
|
|
560
|
|
|
|
616
|
|
Oil (Bbl/d)
|
|
|
1,326
|
|
|
|
1,474
|
|
|
|
1,621
|
|
Natural gas (Mcf/d))
|
|
|
301
|
|
|
|
335
|
|
|
|
368
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Boe/d)
|
|
|
1,376
|
|
|
|
1,529
|
|
|
|
1,682
|
|
Forecasted prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX-WTI oil price (per Bbl)
|
|
$
|
90.00
|
|
|
$
|
90.00
|
|
|
$
|
90.00
|
|
Realized oil price (per Bbl) (excluding derivatives)
|
|
$
|
85.65
|
|
|
$
|
85.65
|
|
|
$
|
85.65
|
|
Realized oil price (per Bbl) (including derivatives)
|
|
$
|
91.23
|
|
|
$
|
90.67
|
|
|
$
|
90.21
|
|
NYMEX-Henry Hub natural gas price (per MMBtu)
|
|
$
|
4.20
|
|
|
$
|
4.20
|
|
|
$
|
4.20
|
|
Realized natural gas price (per Mcf)(1)(2)
|
|
$
|
6.56
|
|
|
$
|
6.56
|
|
|
$
|
6.56
|
|
65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Forecasted
|
|
|
|
Net Production
|
|
|
|
90%
|
|
|
100%
|
|
|
110%
|
|
|
|
(in thousands, except per unit amounts)
|
|
|
Forecasted Adjusted EBITDA projection:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
42,299
|
|
|
$
|
46,999
|
|
|
$
|
51,699
|
|
Realized derivative gains (losses)
|
|
|
2,707
|
|
|
|
2,707
|
|
|
|
2,707
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue including realized derivative gains (losses)
|
|
$
|
45,006
|
|
|
$
|
49,706
|
|
|
$
|
54,406
|
|
Lease operating expenses(3)
|
|
|
7,272
|
|
|
|
8,080
|
|
|
|
8,888
|
|
Production taxes
|
|
|
2,128
|
|
|
|
2,364
|
|
|
|
2,600
|
|
General and administrative expenses
|
|
|
4,000
|
|
|
|
4,000
|
|
|
|
4,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Adjusted EBITDA
|
|
$
|
31,606
|
|
|
$
|
35,262
|
|
|
$
|
38,918
|
|
Minimum estimated Adjusted EBITDA(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess (shortfall) estimated cash available for distribution(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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
$ 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
$ 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 240 MBoe, or approximately
44% of our estimated total oil production from proved reserves
for the year ending December 31, 2012, at a weighted
average floor price of $101.28 per Bbl of oil. In addition, the
estimated Adjusted EBITDA amounts shown below are based on
forecasted realized commodity prices that take into account
assumptions based on our average historical NYMEX commodity
price differentials as set forth in our June 30, 2011
reserve report. We have assumed no changes in our production
based on changes in prices. The estimated Adjusted EBITDA
amounts shown below are based on forecasted realized commodity
prices that take into account our average
66
NYMEX commodity price differential assumptions. We have assumed
no changes in our production based on changes in prices.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands, except per unit amounts)
|
|
|
NYMEX-WTI oil price (per Bbl):
|
|
$
|
70.00
|
|
|
$
|
80.00
|
|
|
$
|
90.00
|
|
|
$
|
100.00
|
|
|
$
|
110.00
|
|
NYMEX-Henry Hub natural gas price (per MMBtu):
|
|
$
|
3.20
|
|
|
$
|
3.70
|
|
|
$
|
4.20
|
|
|
$
|
4.70
|
|
|
$
|
5.20
|
|
Forecasted net production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
539
|
|
|
|
539
|
|
|
|
539
|
|
|
|
539
|
|
|
|
539
|
|
Natural gas (MMcf)
|
|
|
123
|
|
|
|
123
|
|
|
|
123
|
|
|
|
123
|
|
|
|
123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
560
|
|
|
|
560
|
|
|
|
560
|
|
|
|
560
|
|
|
|
560
|
|
Oil (Bbl/d)
|
|
|
1,474
|
|
|
|
1,474
|
|
|
|
1,474
|
|
|
|
1,474
|
|
|
|
1,474
|
|
Natural gas (Mcf/d)
|
|
|
335
|
|
|
|
335
|
|
|
|
335
|
|
|
|
335
|
|
|
|
335
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Boe/d)
|
|
|
1,529
|
|
|
|
1,529
|
|
|
|
1,529
|
|
|
|
1,529
|
|
|
|
1,529
|
|
Forecasted prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX-WTI oil price (per Bbl)
|
|
$
|
70.00
|
|
|
$
|
80.00
|
|
|
$
|
90.00
|
|
|
$
|
100.00
|
|
|
$
|
110.00
|
|
Realized oil price (per Bbl) (excluding derivatives)
|
|
$
|
65.65
|
|
|
$
|
75.65
|
|
|
$
|
85.65
|
|
|
$
|
95.65
|
|
|
$
|
105.65
|
|
Realized oil price (per Bbl) (including derivatives)
|
|
$
|
79.57
|
|
|
$
|
85.12
|
|
|
$
|
90.67
|
|
|
$
|
96.22
|
|
|
$
|
101.77
|
|
NYMEX-Henry Hub natural gas price (per MMBtu)
|
|
$
|
3.20
|
|
|
$
|
3.70
|
|
|
$
|
4.20
|
|
|
$
|
4.70
|
|
|
$
|
5.20
|
|
Realized natural gas price (per Mcf)(1)(2)
|
|
$
|
5.56
|
|
|
$
|
6.06
|
|
|
$
|
6.56
|
|
|
$
|
7.06
|
|
|
$
|
7.56
|
|
Forecasted Adjusted EBITDA projection:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
36,089
|
|
|
$
|
41,544
|
|
|
$
|
46,999
|
|
|
$
|
52,454
|
|
|
$
|
57,908
|
|
Realized derivative gains (losses)
|
|
|
7,507
|
|
|
|
5,107
|
|
|
|
2,707
|
|
|
|
307
|
|
|
|
(2,093
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue including realized derivative gains (losses)
|
|
|
43,597
|
|
|
|
46,651
|
|
|
|
49,706
|
|
|
|
52,761
|
|
|
|
55,816
|
|
Lease operating expenses(3)
|
|
|
8,080
|
|
|
|
8,080
|
|
|
|
8,080
|
|
|
|
8,080
|
|
|
|
8,080
|
|
Production taxes
|
|
|
1,815
|
|
|
|
2,090
|
|
|
|
2,364
|
|
|
|
2,638
|
|
|
|
2,913
|
|
General and administrative expenses
|
|
|
4,000
|
|
|
|
4,000
|
|
|
|
4,000
|
|
|
|
4,000
|
|
|
|
4,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Adjusted EBITDA
|
|
$
|
29,701
|
|
|
$
|
32,482
|
|
|
$
|
35,262
|
|
|
$
|
38,042
|
|
|
$
|
40,823
|
|
Minimum estimated Adjusted EBITDA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess (shortfall) estimated cash available for distribution
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
|
67
|
|
|
(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
$ million. In the case where
the average daily NYMEX-WTI price for oil for the year ending
December 31, 2012 is $70.00 and the average daily
NYMEX-Henry Hub price for natural gas is $3.20 per MMBtu for the
same period, we would have had an excess of
$ 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 $80.00 and the average daily NYMEX-Henry Hub price for
natural gas is $3.70 per MMBtu for the same period, we would
have had an excess of
$ million over the amount of
cash available for distribution necessary to pay such aggregate
annualized distribution.
|
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.
68
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:
|
|
|
|
|
less, the amount of cash reserves established by our
general partner at the date of determination of available cash
for the quarter to:
|
|
|
|
|
|
provide for the proper conduct of our business, which could
include, but is not limited to, amounts reserved for capital
expenditures, working capital and operating expenses;
|
|
|
|
comply with applicable law, any of our 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;
|
|
|
|
|
|
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.
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:
|
|
|
|
|
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
|
69
|
|
|
|
|
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:
|
|
|
|
|
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
|
|
|
|
|
|
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.
70
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 June 30, 2011 and
for the six months ended June 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
June 30, 2011 and for the six months ended June 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:
|
|
|
|
|
the sale by Mid-Con Energy I, LLC and Mid-Con Energy II,
LLC of certain oil and natural gas properties representing
approximately 2% of our proved reserves by value, as calculated
using the standardized measure, as of June 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
common units and $ million in
cash;
|
|
|
|
|
|
the issuance to our general partner
of
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
common units in this offering and the application of the net
proceeds as described in Use of Proceeds; and
|
|
|
|
our borrowing of approximately
$ million under our new
credit facility and the application of the proceeds as described
in Use of Proceeds.
|
The unaudited pro forma balance sheet data assume the events
listed above occurred as of June 30, 2011. The unaudited
pro forma statement of operations data for the six months ended
June 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. Among other things, those historical financial
statements and unaudited pro forma condensed
71
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
Six Months
|
|
|
Year
|
|
|
Six Months
|
|
|
|
(consolidated)
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Year Ended June 30,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
June 30,
|
|
|
December 31,
|
|
|
June 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)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
5,569
|
|
|
$
|
6,944
|
|
|
$
|
13,667
|
|
|
$
|
10,246
|
|
|
|
$
|
5,729
|
|
|
$
|
16,853
|
|
|
$
|
7,482
|
|
|
$
|
15,609
|
|
|
$
|
15,516
|
|
|
$
|
14,888
|
|
Natural gas sales
|
|
|
51
|
|
|
|
64
|
|
|
|
618
|
|
|
|
2,172
|
|
|
|
|
743
|
|
|
|
1,418
|
|
|
|
803
|
|
|
|
657
|
|
|
|
1,392
|
|
|
|
657
|
|
Realized loss on derivatives, net
|
|
|
(165
|
)
|
|
|
558
|
|
|
|
(804
|
)
|
|
|
(669
|
)
|
|
|
|
(350
|
)
|
|
|
(90
|
)
|
|
|
(91
|
)
|
|
|
(714
|
)
|
|
|
(90
|
)
|
|
|
(714
|
)
|
Unrealized gain (loss) on derivatives, net
|
|
|
(294
|
)
|
|
|
45
|
|
|
|
(2,035
|
)
|
|
|
1,679
|
|
|
|
|
(147
|
)
|
|
|
(707
|
)
|
|
|
545
|
|
|
|
1,046
|
|
|
|
(707
|
)
|
|
|
984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
5,161
|
|
|
|
7,611
|
|
|
|
11,446
|
|
|
|
13,428
|
|
|
|
|
5,975
|
|
|
|
17,474
|
|
|
|
8,739
|
|
|
|
16,598
|
|
|
|
16,111
|
|
|
|
15,815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
2,252
|
|
|
|
3,429
|
|
|
|
5,005
|
|
|
|
5,369
|
|
|
|
|
2,431
|
|
|
|
6,237
|
|
|
|
3,038
|
|
|
|
3,550
|
|
|
|
4,788
|
|
|
|
2,967
|
|
Oil and gas production taxes
|
|
|
407
|
|
|
|
478
|
|
|
|
946
|
|
|
|
631
|
|
|
|
|
269
|
|
|
|
822
|
|
|
|
384
|
|
|
|
655
|
|
|
|
741
|
|
|
|
609
|
|
Dry holes and abandonments of unproved properties
|
|
|
539
|
|
|
|
220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,418
|
|
|
|
44
|
|
|
|
772
|
|
|
|
514
|
|
|
|
772
|
|
Geological and geophysical
|
|
|
146
|
|
|
|
342
|
|
|
|
1,296
|
|
|
|
507
|
|
|
|
|
|
|
|
|
394
|
|
|
|
287
|
|
|
|
58
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
931
|
|
|
|
924
|
|
|
|
1,599
|
|
|
|
2,293
|
|
|
|
|
2,552
|
|
|
|
5,851
|
|
|
|
3,445
|
|
|
|
2,419
|
|
|
|
3,014
|
|
|
|
2,081
|
|
Accretion of discount on asset retirement obligations
|
|
|
2
|
|
|
|
35
|
|
|
|
56
|
|
|
|
78
|
|
|
|
|
58
|
|
|
|
127
|
|
|
|
64
|
|
|
|
32
|
|
|
|
63
|
|
|
|
32
|
|
General and administrative
|
|
|
1,391
|
|
|
|
1,805
|
|
|
|
1,871
|
|
|
|
1,767
|
|
|
|
|
704
|
|
|
|
982
|
|
|
|
587
|
|
|
|
476
|
|
|
|
982
|
|
|
|
476
|
|
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
|
|
|
|
7,849
|
|
|
|
7,962
|
|
|
|
11,362
|
|
|
|
6,937
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(685
|
)
|
|
|
378
|
|
|
|
673
|
|
|
|
2,783
|
|
|
|
|
(9,247
|
)
|
|
|
(243
|
)
|
|
|
890
|
|
|
|
8,636
|
|
|
|
4,749
|
|
|
|
8,878
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
Six Months
|
|
|
Year
|
|
|
Six Months
|
|
|
|
(consolidated)
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Year Ended June 30,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
June 30,
|
|
|
December 31,
|
|
|
June 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)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expenses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income and other
|
|
|
63
|
|
|
|
126
|
|
|
|
115
|
|
|
|
119
|
|
|
|
|
35
|
|
|
|
218
|
|
|
|
151
|
|
|
|
62
|
|
|
|
126
|
|
|
|
4
|
|
Interest expense
|
|
|
(24
|
)
|
|
|
(11
|
)
|
|
|
(3
|
)
|
|
|
(93
|
)
|
|
|
|
(2
|
)
|
|
|
(98
|
)
|
|
|
(17
|
)
|
|
|
(237
|
)
|
|
|
(1,200
|
)
|
|
|
(600
|
)
|
Gain on sale of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
354
|
|
|
|
353
|
|
|
|
1,209
|
|
|
|
|
|
|
|
|
|
Other revenue and expenses, net
|
|
|
138
|
|
|
|
439
|
|
|
|
108
|
|
|
|
298
|
|
|
|
|
118
|
|
|
|
847
|
|
|
|
299
|
|
|
|
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
|
|
|
$
|
1,676
|
|
|
$
|
10,246
|
|
|
$
|
3,675
|
|
|
$
|
8,282
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of limited partner units outstanding
(basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
|
|
|
|
|
|
|
|
$
|
4,471
|
|
|
$
|
3,773
|
|
|
|
$
|
2,836
|
|
|
$
|
10,593
|
|
|
$
|
4,197
|
|
|
$
|
11,389
|
|
|
$
|
10,307
|
|
|
$
|
10,779
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
(282
|
)
|
|
$
|
2,052
|
|
|
$
|
4,221
|
|
|
$
|
10,935
|
|
|
|
$
|
965
|
|
|
$
|
11,798
|
|
|
$
|
6,685
|
|
|
$
|
5,192
|
|
|
|
|
|
|
|
|
|
Investing activities
|
|
|
(5,599
|
)
|
|
|
(11,143
|
)
|
|
|
(7,646
|
)
|
|
|
(12,448
|
)
|
|
|
|
(5,018
|
)
|
|
|
(22,726
|
)
|
|
|
(8,284
|
)
|
|
|
(13,351
|
)
|
|
|
|
|
|
|
|
|
Financing activities
|
|
|
4,918
|
|
|
|
9,980
|
|
|
|
147
|
|
|
|
4,841
|
|
|
|
|
(1,164
|
)
|
|
|
10,387
|
|
|
|
1,058
|
|
|
|
8,377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 June 30,
|
|
|
|
As of June 30,
|
Balance Sheet Data:
|
|
2009
|
|
2010
|
|
|
|
2011
|
|
|
|
2011
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
|
(unaudited)
|
|
|
(in thousands)
|
|
|
(restated)
|
|
(restated)
|
|
|
|
(restated)
|
|
|
|
(restated)
|
|
Working capital(1)
|
|
$
|
2,420
|
|
|
$
|
(1,256
|
)
|
|
|
|
|
|
$
|
4,383
|
|
|
|
|
|
|
$
|
4,383
|
|
Total assets
|
|
|
40,496
|
|
|
|
56,867
|
|
|
|
|
|
|
|
72,390
|
|
|
|
|
|
|
|
72,150
|
|
Total debt
|
|
|
337
|
|
|
|
5,513
|
|
|
|
|
|
|
|
13,310
|
|
|
|
|
|
|
|
30,000
|
|
Partners capital
|
|
|
36,779
|
|
|
|
43,072
|
|
|
|
|
|
|
|
56,098
|
|
|
|
|
|
|
|
39,168
|
|
|
|
|
(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.
|
73
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 June 30, 2011, our total estimated proved reserves
were approximately 7.9 MMBoe, of which approximately 98%
were oil and 71% were proved developed, both on a Boe basis. As
of June 30, 2011, we operated 98% 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
June 30, 2011 was approximately 1,248 Boe per day and our
total estimated proved reserves had a
reserve-to-production
ratio of approximately 17 years. Our management team
developed approximately two-thirds 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.
74
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 six months ended
June 30, 2011.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
|
|
|
Six Months
|
|
|
|
|
|
|
|
|
|
Ended
|
|
|
Year Ended
|
|
|
Ended
|
|
|
|
Year Ended June 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
June 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
Oil (MBbls)
|
|
|
145
|
|
|
|
153
|
|
|
|
87
|
|
|
|
228
|
|
|
|
167
|
|
Natural Gas (MMcf)
|
|
|
86
|
|
|
|
341
|
|
|
|
140
|
|
|
|
191
|
|
|
|
79
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
159
|
|
|
|
210
|
|
|
|
110
|
|
|
|
260
|
|
|
|
180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Net Production (Boe/d)
|
|
|
437
|
|
|
|
575
|
|
|
|
602
|
|
|
|
710
|
|
|
|
986
|
|
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).
Current Sales Contracts. We currently market
approximately 89% of our oil production to one party, Sunoco
Logistics, under two crude oil purchase agreements. We have
amended these purchase contracts from time to time to add new
leases and to modify the pricing terms. Generally, amendments to
modify the pricing terms extend the term of the agreements for
six months. If new amendments to the 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.
The purchase agreements provide a fixed NYMEX-WTI differential
for all production from an individual producing lease.
Settlement under these purchase agreements occurs monthly, with
payment being made on or about the 15th of each month for
oil delivered in the previous month. The ultimate price per
barrel paid to us by Sunoco Logistics is 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.
75
We sell the remainder of our production to several other
purchasers based on regional pricing. From time to time, we
compare the pricing under our current Sunoco Logistics contract
to offers from other purchasers to determine the best price in
the relevant market. Sales to other producers are also made at
the NYMEX-WTI price, less a differential for quality and
transportation, depending primarily on location and purchaser.
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
our oil production to Sunoco Logistics and other customers 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
Sunoco Logistics or any other party.
For the years ending December 31, 2011, 2012 and 2013, we
have commodity derivative contracts covering approximately 43%,
44% and 24%, respectively, of our estimated oil production from
proved reserves as of June 30, 2011. All of our derivative
contracts for 2012 and 2013 are either swaps with fixed price
settlements or collars with floors of at least $100. 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 $100.00 to $104.28 covering
approximately 13% and 31%, respectively, of our total proved
estimated production. In 2013, we have collars with a floor of
$100.00 and swaps with fixed price settlements of $105.80
covering 12% and 12%, respectively, of our total proved
estimated 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)
|
|
|
559
|
|
|
|
460
|
|
|
|
197
|
|
Weighted Average NYMEX-WTI price per Bbl
|
|
$
|
91.22
|
|
|
|
$101.83
|
|
|
|
$105.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 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
76
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 June 30,
2011. During the same twelve month period, per unit lease
operating expenses for our Highlands Unit decreased from
approximately $40 per Boe to $11 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):
|
|
|
|
|
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 abandonment of unproved properties; and
|
|
|
|
loss on sale of assets;
|
77
|
|
|
|
|
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.
|
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.
78
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC
(combined)
|
|
|
|
Mid-Con Energy Corporation
|
|
|
|
Six Months
|
|
|
Year
|
|
|
Six Months
|
|
|
|
(consolidated)
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Year Ended June 30,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
June 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(restated)
|
|
|
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
(restated)
|
|
|
(restated)
|
|
|
|
|
|
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
13,667
|
|
|
$
|
10,246
|
|
|
|
$
|
5,729
|
|
|
$
|
16,853
|
|
|
$
|
7,482
|
|
|
$
|
15,609
|
|
Natural gas sales
|
|
|
618
|
|
|
|
2,172
|
|
|
|
|
743
|
|
|
|
1,418
|
|
|
|
803
|
|
|
|
657
|
|
Realized gain (loss) on derivatives, net
|
|
|
(804
|
)
|
|
|
(669
|
)
|
|
|
|
(350
|
)
|
|
|
(90
|
)
|
|
|
(91
|
)
|
|
|
(714
|
)
|
Unrealized gain (loss) on derivatives, net
|
|
|
(2,035
|
)
|
|
|
1,679
|
|
|
|
|
(147
|
)
|
|
|
(707
|
)
|
|
|
545
|
|
|
|
1,046
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
$
|
11,446
|
|
|
$
|
13,428
|
|
|
|
$
|
5,975
|
|
|
$
|
17,474
|
|
|
$
|
8,739
|
|
|
$
|
16,598
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
$
|
5,005
|
|
|
$
|
5,369
|
|
|
|
$
|
2,431
|
|
|
$
|
6,237
|
|
|
$
|
3,038
|
|
|
$
|
3,550
|
|
Oil and gas production taxes
|
|
|
946
|
|
|
|
631
|
|
|
|
|
269
|
|
|
|
822
|
|
|
|
384
|
|
|
|
655
|
|
Dry holes and abandonments of unproved properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,418
|
|
|
|
44
|
|
|
|
772
|
|
Depreciation, depletion and amortization(1)
|
|
|
1,465
|
|
|
|
2,103
|
|
|
|
|
2,357
|
|
|
|
5,204
|
|
|
|
2,934
|
|
|
|
2,080
|
|
General and administrative
|
|
|
1,871
|
|
|
|
1,767
|
|
|
|
|
704
|
|
|
|
982
|
|
|
|
587
|
|
|
|
476
|
|
Impairment of proved oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
|
9,208
|
|
|
|
1,886
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
3
|
|
|
|
93
|
|
|
|
|
2
|
|
|
|
98
|
|
|
|
17
|
|
|
|
237
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
145
|
|
|
|
153
|
|
|
|
|
87
|
|
|
|
228
|
|
|
|
104
|
|
|
|
167
|
|
Natural gas (MMcf)
|
|
|
86
|
|
|
|
341
|
|
|
|
|
140
|
|
|
|
191
|
|
|
|
106
|
|
|
|
79
|
|
Total (MBoe)
|
|
|
159
|
|
|
|
210
|
|
|
|
|
110
|
|
|
|
260
|
|
|
|
121
|
|
|
|
180
|
|
Average net production (Boe/d)
|
|
|
437
|
|
|
|
575
|
|
|
|
|
602
|
|
|
|
710
|
|
|
|
666
|
|
|
|
986
|
|
Average sales price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales price
|
|
$
|
94.20
|
|
|
$
|
66.87
|
|
|
|
$
|
66.11
|
|
|
$
|
74.07
|
|
|
$
|
72.05
|
|
|
$
|
93.58
|
|
Effect of realized commodity derivative instruments
|
|
$
|
(5.54
|
)
|
|
$
|
(4.37
|
)
|
|
|
$
|
(4.04
|
)
|
|
$
|
0.40
|
|
|
$
|
(0.87
|
)
|
|
$
|
(4.28
|
)
|
Realized price
|
|
$
|
88.66
|
|
|
$
|
62.50
|
|
|
|
$
|
62.06
|
|
|
$
|
73.67
|
|
|
$
|
71.17
|
|
|
$
|
89.30
|
|
Natural gas (per Mcf):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales price(2)
|
|
$
|
7.17
|
|
|
$
|
6.37
|
|
|
|
$
|
5.33
|
|
|
$
|
7.44
|
|
|
$
|
7.59
|
|
|
$
|
8.28
|
|
Average unit costs per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
31.39
|
|
|
$
|
25.56
|
|
|
|
$
|
22.11
|
|
|
$
|
24.05
|
|
|
$
|
25.01
|
|
|
$
|
19.72
|
|
Oil and gas production taxes
|
|
$
|
5.93
|
|
|
$
|
3.00
|
|
|
|
$
|
2.45
|
|
|
$
|
3.17
|
|
|
$
|
3.16
|
|
|
$
|
3.64
|
|
General and administrative expenses
|
|
$
|
11.73
|
|
|
$
|
8.41
|
|
|
|
$
|
6.40
|
|
|
$
|
3.79
|
|
|
$
|
4.83
|
|
|
$
|
2.64
|
|
Depreciation, depletion and amortization
|
|
$
|
9.21
|
|
|
$
|
10.01
|
|
|
|
$
|
21.43
|
|
|
$
|
20.02
|
|
|
$
|
24.25
|
|
|
$
|
11.55
|
|
|
|
|
(1)
|
|
Depreciation, depletion, and
amortization expenses for this table only represent the
depletion expenses for the producing properties.
|
|
(2)
|
|
Natural gas sales price per Mcf
includes the sale of natural gas liquids.
|
79
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 June 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:
|
|
|
|
|
The drilling of 35 wells in 2010 and 21 wells in 2011
on our properties in Oklahoma;
|
|
|
|
Our sale to the Mid-Con Affiliates on June 30, 2011 of
certain properties representing approximately 2% of our proved
reserves by value, as calculated using the standardized measure,
as of June 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;
|
|
|
|
Our acquisition of the War Party I and II Units for a
purchase price of $7.2 million on June 30, 2011, which
together represented approximately 7.2% of our total estimated
proved reserves on a Boe basis as of that date;
|
|
|
|
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
|
|
|
|
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.
|
Six Months Ended June 30, 2011 Compared to Six Months
Ended June 30, 2010
Sales Revenues. Revenues from oil and natural
gas sales for the six months ended June 30, 2011 were
approximately $16.3 million as compared to
$8.3 million for the six months ended June 30, 2010.
The increase in revenues was primarily due to an increase in
daily oil production and higher sales prices during the six
months ended June 30, 2011.
Our production volumes for the six months ended June 30,
2011 were 180 MBoe, or 986 Boe per day. In comparison, our
production volumes for the six months ended June 30, 2010
were 121 MBoe, or 666 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 six months ended
June 30, 2011 was $93.58, compared with $72.05 for the six
months ended June 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 six months ended June 30,
2011 of approximately $0.3 million, which was composed of a
realized loss of $0.7 million and an unrealized gain of
$1.0 million. For the six months ended June 30, 2010,
we recorded a net gain from our commodity hedging program of
approximately $0.4 million, which was composed of a
realized loss of $0.1 million and an unrealized gain of
$0.5 million.
Lease Operating Expenses. Our lease operating
expenses were $3.6 million for the six months ended
June 30, 2011, or $19.72 per Boe, compared to
$3.0 million for the six months ended June 30, 2010,
or $25.01 per Boe. The increase in total lease operating
expenses during the six months ended June 30, 2011 was
primarily due to the increase in production and the
80
increase in the number of wells producing. The decrease in lease
operating expenses per Boe was due to the increased production
for the six months ended June 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
$0.7 million for the six months ended June 30, 2011,
or $3.64 per Boe for an effective tax rate of 4.0%, compared to
$0.4 million for the six months ended June 30, 2010,
or $3.16 per Boe for an effective tax rate of 4.6%. The increase
in production taxes during the six months ended June 30,
2011 was primarily due to the increase in the realized average
oil sales price. The decrease in the effective tax rate is due
to increased production from several of our Southern Oklahoma
waterflood projects that qualify for reduced tax rates.
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 six months ended June 30,
2011 were $2.1 million, or $11.55 per Boe produced,
compared to $2.9 million, or $24.25 per Boe produced, for
the six months ended June 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
June 30, 2011.
Impairment of Oil and Natural Gas
Properties. There was no impairment charge for
both the six months ended June 30, 2011 and 2010.
General and Administrative Expenses. Our
general and administrative expenses were approximately
$0.5 million for the six months ended June 30, 2011,
or $2.64 per Boe produced compared to $0.6 million for the
six months ended June 30, 2010 or $4.83 per Boe produced.
The decrease in general and administrative expenses for the six
months ended June 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
six months ended June 30, 2011 was $0.2 million,
compared to $17,000 for the six months ended June 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 259 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.
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
81
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 $20.02 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.
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
82
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.
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
83
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 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
84
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 (used in) operating activities was
approximately $11.8 million, $10.9 million,
$4.2 million, $5.2 million, $6.7 million and
($14,000) for the twelve months ended December 31, 2010,
June 30, 2009 and June 30, 2008 and for the six months
ended June 30, 2011, June 30, 2010 and
December 31, 2009, respectively. Our revenues increased
significantly for the year ended December 31, 2010 and for
the six month period ended June 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,
$13.3 million, $8.3 million and $4.0 million for
the twelve months ended December 31, 2010, June 30,
2009, June 30, 2008 and for the six months ended
June 30, 2011, June 30, 2010 and December 31,
2009, respectively. The increased amount of cash used in
investing activities for the year ended December 31, 2010
and six months ended June 30, 2011 compared to
corresponding twelve and six 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, $8.4 million, $1.1 million and
($1.2 million) for the twelve months ended
December 31, 2010, June 30, 2009 and June 30,
2008 and for the six months ended June 30, 2011,
June 30, 2010 and December 31, 2009, respectively. For
the year ended December 31, 2010 and the six months ended
June 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 $4.4 million,
($1.3 million), and $2.4 million at June 30,
2011, December 31, 2010, and December 31, 2009,
respectively. Our cash balances at June 30, 2011,
December 31, 2010, and December 31, 2009 were
$0.4 million, $0.2 million, and $0.8 million,
respectively. The negative working capital at December 31,
2010 was directly 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
85
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 production
levels and asset base, including over the long term. The primary
purpose of maintenance capital expenditures is to prevent our
production from declining over time, which could result in a
corresponding decline in our distributions per unit. For the
twelve months ending December 31, 2012, we estimate that
our maintenance capital expenditures will be approximately
$6.0 million.
Growth capital expenditures are capital expenditures that we
expect to increase our production levels and asset base over the
long term. 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. Growth capital expenditures may also include
acquisitions of additional oil and gas properties. 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
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.
86
New
Credit Facility
Concurrently with the closing of this offering, we anticipate
that we will enter into a new credit facility, which we expect
to be a five-year, $ million
revolving credit facility with an initial borrowing base of
approximately $ million. We
expect the new credit facility to include typical operational
and financial covenants.
We anticipate that 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 natural
gas properties and our commodity derivative contracts as
determined by our lenders in their sole discretion. We expect
that our borrowing base will be subject to redetermination on a
semi-annual basis based on an engineering report with respect to
our estimated oil and natural gas reserves, which will take into
account our lenders commodity price assumptions, as
adjusted for the impact of our commodity derivative contracts.
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 anticipate that if, at the time of any
distribution, our borrowings equal or exceed the maximum
percentage allowed of the then-specified borrowing base, we will
not be able to pay distributions to our unitholders in any such
quarter without first making the required repayments of
indebtedness under our new credit facility.
Derivative
Contracts
For the years ending December 31, 2011, 2012 and 2013, we
have commodity derivative contracts covering approximately 43%,
44% and 24%, respectively, of our estimated oil production from
proved reserves as of June 30, 2011.
The following table summarizes, for the periods indicated, our
oil swaps and put/call options or collars, as of
December 31, 2011 through December 31, 2013. These
transactions are settled based upon the NYMEX-WTI price of oil.
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|
|
|
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Weighted
|
|
|
Term
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|
Type of Derivative
|
|
Average ($/Bbl)
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|
Bbls/d
|
|
2011
|
|
Swaps
|
|
$
|
91.22
|
|
|
|
559
|
|
2012
|
|
Swaps
|
|
$
|
101.83
|
|
|
|
460
|
|
2012
|
|
Put/Call (Collars)
|
|
$
|
100 $117
|
|
|
|
197
|
|
2013
|
|
Swaps
|
|
$
|
105.80
|
|
|
|
197
|
|
2013
|
|
Put/Call (Collars)
|
|
$
|
100 $111
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|
|
|
197
|
|
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
87
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.
Contractual
Obligations
A summary of our contractual obligations as of June 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
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Total
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Long-term debt
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$
|
|
|
|
$
|
|
|
|
$
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13,310
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|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
13,310
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|
Interest on long-term debt(1)
|
|
$
|
266
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|
|
$
|
532
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|
|
$
|
532
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,330
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|
Office lease
|
|
$
|
89
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|
|
$
|
89
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
178
|
|
|
|
|
|
|
|
|
|
|
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|
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|
|
|
|
|
|
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|
|
|
|
|
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Total contractual obligations
|
|
$
|
355
|
|
|
$
|
621
|
|
|
$
|
13,842
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
14,818
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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(1)
|
|
Based upon an interest rate of 4.0%
under the credit facilities at June 30, 2011.
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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.
88
For a summary of the oil swaps and swap prices, related basis
swap prices and resulting adjusted swap prices in place as of
June 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 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 June 30,
2011, please read Liquidity and Capital
ResourcesDerivative Contracts.
Interest
Rate Risk
At June 30, 2011 we had $13.3 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 $53,000 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
$ million, at an interest
rate
of .
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. The inability or failure of Sunoco Logistics 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 an investment grade
credit rating and, as a result, we believe the credit quality of
Sunoco Logistics 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 June 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.
89
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 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
90
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 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 six months
91
ended June 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.
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 June 30, 2011 and for the six
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.
92
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 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.
93
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 June 30, 2011, our total estimated proved reserves
were 7.9 MMBoe, of which approximately 98% were oil and
approximately 71% were proved developed, both on a Boe basis. As
of June 30, 2011, we operated 98% 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
June 30, 2011 was approximately 1,248 Boe per day and our
total estimated proved reserves had a
reserve-to-production
ratio of approximately 17 years. Our management team
developed approximately two-thirds 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 June 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 June 30, 2011 reserve report,
the average estimated decline rate for our proved developed
producing reserves is approximately 4% for 2011 and, on a
compounded average decline basis, approximately 11% for the
subsequent five years and approximately 10% thereafter.
Additionally, based on production estimates from this reserve
report, we believe that we have the ability to increase our
average net production from our existing proved reserves to
approximately 1,700 Boe per day during the next three years.
94
The following table summarizes information by core area
regarding our pro forma estimated oil and natural gas reserves
as of June 30, 2011 and our average net production for the
month ended June 30, 2011.
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Average
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Net
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Pro Forma
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Production
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Estimated
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for the Month Ended
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Net Proved Reserves
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June 30,
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as of June 30, 2011
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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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4,783
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100
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%
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99
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%
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58
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%
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1,892
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700
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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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2,043
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100
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%
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99
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%
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91
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%
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593
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340
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16
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154
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59
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Hugoton Basin
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720
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100
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%
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99
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%
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85
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%
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234
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141
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14
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43
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18
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Other
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361
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77
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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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231
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67
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15
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13
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4
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Total
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7,907
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99
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%
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98
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%
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71
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%
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2,950
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1,248
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17
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275
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123
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(1)
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The average
reserve-to-production
ratio is calculated by dividing estimated net proved reserves as
of June 30, 2011 by average net production for the month
ended June 30, 2011.
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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 June 30, 2011. We achieved this increase primarily
through ongoing waterflood response from existing development
activities and to a lesser extent, workovers and acquisitions.
95
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 43%, 44% and 24%,
respectively, of our estimated oil production from proved
reserves as of June 30, 2011. All of our derivative
contracts for 2012 and 2013 are either swaps with fixed price
settlements or collars with floors of at least $100. 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 $100.00 to $104.28 covering
approximately 13% and 31%, respectively, of our total proved
estimated production. In 2013, we have collars with a floor of
$100.00 and swaps with fixed price settlements of $105.80
covering 12% and 12%, respectively, of our total proved
estimated 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 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 June 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
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96
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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 June 30, 2011, we operated 98% 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
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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97
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 have been producing
continuously since 1982 or earlier. Based on production
estimates from our June 30, 2011 reserve report, the
average estimated decline rate for our existing proved developed
producing reserves is approximately 4% for 2011 and, on a
compounded average decline basis, approximately 11% for the
subsequent five years and approximately 10% thereafter.
Additionally, based on production estimates from this reserve
report, we believe that we have the ability to increase our
average net production from our existing proved reserves to
approximately 1,700 Boe per day during the next three years.
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, 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 % 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
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98
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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 June 30,
2011, we operated 98% 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
$ million under our new
credit facility after giving effect to approximately
$ 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 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
99
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 % 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.
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
100
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 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, as calculated using the standardized
measure. 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 wells (159 net) wells, 123 gross injection wells
(66 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 65% based
on our June 30, 2011 reserve report. Our estimated proved
reserves as of June 30, 2011 were 7.9 MMBoe, of which
approximately 98% were oil and approximately 71% were proved
developed, both on a Boe basis. For the month
101
ended June 30, 2011, we produced an average of 1,248 Boe
per day. Based on production estimates from our June 30,
2011 reserve report, the average estimated decline rate for our
existing proved developed producing reserves is approximately 4%
for 2011, 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 June 30, 2011, and certain
unaudited information regarding production and sales of oil and
natural gas with respect to such properties.
102
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
Pro Forma Average Net
|
|
|
Estimated Net Proved Reserves
|
|
|
|
Production
|
|
|
as of June 30,
|
|
|
|
for the Month Ended
|
|
|
2011(2)
|
|
|
|
June 30,
|
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|
|
|
|
% of
|
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|
|
|
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011(1)
|
|
|
|
|
|
Total
|
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|
|
|
|
Proved
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
% of
|
|
|
|
|
|
Proved
|
|
|
|
|
|
Developed
|
|
|
%
|
|
|
Undiscounted
|
|
|
Standardized
|
|
|
% of
|
|
|
|
(Boe/d)
|
|
|
Total
|
|
|
MBoe
|
|
|
Reserves
|
|
|
% Oil
|
|
|
Reserves
|
|
|
Depletion(3)
|
|
|
Cap. Ex.
|
|
|
Measure(4)(5)
|
|
|
Total
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
|
(in millions)
|
|
|
|
|
|
Southern Oklahoma Fields/Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Highlands(6)
|
|
|
206
|
|
|
|
17
|
%
|
|
|
2,393
|
|
|
|
30
|
%
|
|
|
99
|
%
|
|
|
62
|
%
|
|
|
36
|
%
|
|
$
|
11
|
|
|
$
|
85
|
|
|
|
37
|
%
|
Battle Springs(6)
|
|
|
348
|
|
|
|
28
|
%
|
|
|
1,122
|
|
|
|
14
|
%
|
|
|
100
|
%
|
|
|
81
|
%
|
|
|
48
|
%
|
|
|
4
|
|
|
|
45
|
|
|
|
19
|
%
|
Ardmore West(6)
|
|
|
49
|
|
|
|
4
|
%
|
|
|
649
|
|
|
|
8
|
%
|
|
|
99
|
%
|
|
|
5
|
%
|
|
|
44
|
%
|
|
|
2
|
|
|
|
17
|
|
|
|
7
|
%
|
Twin Forks(6)
|
|
|
30
|
|
|
|
2
|
%
|
|
|
455
|
|
|
|
6
|
%
|
|
|
100
|
%
|
|
|
42
|
%
|
|
|
55
|
%
|
|
|
3
|
|
|
|
13
|
|
|
|
6
|
%
|
Southeast Hewitt
|
|
|
55
|
|
|
|
4
|
%
|
|
|
126
|
|
|
|
2
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
69
|
%
|
|
|
|
|
|
|
5
|
|
|
|
2
|
%
|
Other Southern Oklahoma Fields/Units
|
|
|
12
|
|
|
|
1
|
%
|
|
|
38
|
|
|
|
< 1
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
< 1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Southern Oklahoma Fields / Units
|
|
|
700
|
|
|
|
56
|
%
|
|
|
4,783
|
|
|
|
60
|
%
|
|
|
99
|
%
|
|
|
58
|
%
|
|
|
|
|
|
$
|
20
|
|
|
$
|
166
|
|
|
|
71
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeastern Oklahoma Fields / Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cleveland
|
|
|
209
|
|
|
|
17
|
%
|
|
|
1,036
|
|
|
|
13
|
%
|
|
|
99
|
%
|
|
|
100
|
%
|
|
|
88
|
%(7)
|
|
$
|
2
|
|
|
$
|
25
|
|
|
|
11
|
%
|
Cushing
|
|
|
91
|
|
|
|
7
|
%
|
|
|
596
|
|
|
|
8
|
%
|
|
|
99
|
%
|
|
|
100
|
%
|
|
|
82
|
%(7)
|
|
|
|
|
|
|
12
|
|
|
|
5
|
%
|
Skiatook(6)
|
|
|
25
|
|
|
|
2
|
%
|
|
|
363
|
|
|
|
5
|
%
|
|
|
100
|
%
|
|
|
50
|
%
|
|
|
73
|
%
|
|
|
1
|
|
|
|
6
|
|
|
|
3
|
%
|
Other Northeastern Oklahoma Fields/Units
|
|
|
15
|
|
|
|
1
|
%
|
|
|
48
|
|
|
|
< 1
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Northeastern Oklahoma Fields / Units
|
|
|
340
|
|
|
|
27
|
%
|
|
|
2,043
|
|
|
|
26
|
%
|
|
|
99
|
%
|
|
|
91
|
%
|
|
|
|
|
|
$
|
3
|
|
|
$
|
44
|
|
|
|
19
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hugoton Fields / Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
War Party I
|
|
|
61
|
|
|
|
5
|
%
|
|
|
350
|
|
|
|
4
|
%
|
|
|
99
|
%
|
|
|
100
|
%
|
|
|
92
|
%
|
|
|
|
|
|
$
|
7
|
|
|
|
3
|
%
|
War Party II
|
|
|
59
|
|
|
|
5
|
%
|
|
|
217
|
|
|
|
3
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
74
|
%
|
|
|
|
|
|
|
3
|
|
|
|
1
|
%
|
Harker Ranch(6)
|
|
|
21
|
|
|
|
2
|
%
|
|
|
153
|
|
|
|
2
|
%
|
|
|
100
|
%
|
|
|
27
|
%
|
|
|
83
|
%
|
|
|
1
|
|
|
|
3
|
|
|
|
1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Hugoton Fields / Unit
|
|
|
141
|
|
|
|
12
|
%
|
|
|
720
|
|
|
|
9
|
%
|
|
|
99
|
%
|
|
|
85
|
|
|
|
|
|
|
$
|
1
|
|
|
$
|
13
|
|
|
|
5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Fields / Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decker(6)
|
|
|
18
|
|
|
|
1
|
%
|
|
|
216
|
|
|
|
3
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
67
|
%
|
|
|
|
|
|
$
|
8
|
|
|
|
3
|
%
|
Miscellaneous
|
|
|
49
|
|
|
|
4
|
%
|
|
|
145
|
|
|
|
2
|
%
|
|
|
< 1
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other Fields / Units
|
|
|
67
|
|
|
|
5
|
%
|
|
|
361
|
|
|
|
5
|
%
|
|
|
60
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
$
|
10
|
|
|
|
5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Fields
|
|
|
1,248
|
|
|
|
100
|
%
|
|
|
7,907
|
|
|
|
100
|
%
|
|
|
98
|
%
|
|
|
71
|
%
|
|
|
|
|
|
$
|
24
|
|
|
$
|
233
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Excludes production from certain
properties, which represent approximately 2% of our proved
reserves by value, as calculated using the standardized measure,
as of June 30, 2011, that were sold to the Mid-Con
Affiliates on June 30, 2011.
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(2)
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Includes the working interests to
be acquired from J&A Oil Company and Mid-Con Operating
immediately prior to the closing of this offering.
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(3)
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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.
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(4)
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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.
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(5)
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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 $89.96 per Bbl for oil and $4.20 per MMBtu for
natural gas for the 12 months ended June 30, 2011.
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(6)
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Denotes a waterflood project or
unit that we identified, acquired, formed and developed.
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(7)
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Cumulative production for these
properties has been estimated due to lack of complete historical
production information.
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Summary of Oil Properties and Projects
Our principal fields detailed below represent approximately 97%
of our total estimated net proved reserves as of June 30,
2011, 94% of our average daily net production for the month
ended June 30, 2011 and 98% of our standardized measure as
of June 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 June 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 2,814 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 15 gross (9 net) producing
and 16 gross injection (9 net) wells in this unit with an
average working interest of 57%. As of June 30, 2011, our
properties in this unit were producing 569 Boe per day gross,
206 Boe per day net, and contained 2,393 MBoe of estimated
net proved reserves. The current rate of 569 Boe per day gross
is approximately 41% of the future peak rate as estimated in our
June 30, 2011 reserve report, and has increased from 88 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 24% and 62%, respectively, as of
June 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 23%.
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 2,519 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 16 gross (8 net) producing and 12 gross injection
(6 net) wells in this unit with an average working interest of
51%. As of June 30, 2011, our properties in this unit were
producing 861 Boe per day gross, 348 Boe per day net, and
contained 1,122 MBoe of estimated net proved reserves. The
current rate of 861 Boe per day gross is approximately 92% of
the future peak rate as estimated in our June 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 72% and 81%, respectively, as of June 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 25%.
104
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 580 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 2 gross (2 net)
injection wells in this unit with an average working interest of
96%. As of June 30, 2011, our properties in this unit were
producing 63 Boe per day gross, 49 Boe per day net, and
contained 649 MBoe of estimated net proved reserves. The
current rate of 63 Boe per day gross is approximately 25% of the
future peak rate as estimated in our June 30, 2011 reserve
report, and has increased from 3 Boe per day gross for the month
of January 2010. Proved producing and proved developed reserves
represent 5% and 5%, respectively, as of June 30, 2011, of
the total proved reserves. Reservoir
fill-up is
0% as injection should commence during the third quarter of 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 1,092 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 June 30,
2011, our properties in this unit were producing 73 Boe per day
gross, 30 Boe per day net, and contained 455 MBoe of
estimated net proved reserves. The current rate of 73 Boe per
day gross is approximately 34% of the future peak rate as
estimated in our June 30, 2011 reserve report, and has
increased from 35 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 42% and 42%,
respectively, as of June 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 12%.
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
1,503 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. We own
8 gross (2 net) producing and 7 gross (2 net)
injection wells in this unit with an average working interest of
22%. As of June 30, 2011, our properties in this unit were
producing 296 Boe per day gross, 55 Boe per day net, and
contained 126 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 95%.
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 9,509 MBoe. Production from the Cleveland Field is
primarily from the multiple Pennsylvanian age sands at depths
from 1,000 to 2,400 feet. Approximately 1560 acres in
the Cleveland Field is being operated by our affiliate,
Mid-Con
Energy Operating. Approximately 840 of the total 1560 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 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
105
field with an average working interest of 96%. As of
June 30, 2011, our properties in this field were producing
250 Boe per day gross, 209 Boe per day net, and contained
1,036 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. The Cleveland 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 Cleveland Field through workovers, recompletions 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 8,800 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
2,800 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 (27 net) producing wells and 35 gross (13
net) injection wells in this field with an average working
interest of 38%. As of June 30, 2011, our properties in
this field were producing 286 Boe per day gross, 91 Boe per day
net, and contained 596 MBoe of estimated net proved
reserves. Waterflooding in the Cushing 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 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 1,169 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 June 30, 2011, our
properties in this field were producing 30 Boe per day gross, 25
Boe per day net, and contained 363 MBoe of estimated net
proved reserves. The current rate of 30 Boe per day gross is
approximately 55% of the future peak rate as estimated in our
June 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 50% and 50%, respectively, as of
June 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. Since their discovery
in 1998, the War Party I and II Units have collectively
produced approximately 4,350 MBoe. 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 December 2001
106
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 June 30, 2011, our
properties in these units were producing 209 Boe per day gross,
120 Boe per day net, and contained 567 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 903 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 3 gross (3 net)
producing and 3 gross (3 net) injection wells in this unit
with a working interest of 100%. As of June 30, 2011, our
properties in this unit were producing 26 Boe per day gross, 21
Boe per day net, and contained 153 MBoe of estimated net
proved reserves. The current rate of 26 Boe per day gross is
approximately 44% of the future peak rate as estimated in our
June 30, 2011 reserve report, and is relatively unchanged
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 27% and 27%,
respectively, as of June 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 56%.
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 563 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 June 30, 2011, our properties in
this unit were producing 23 Boe per day gross, 18 Boe per day
net, and contained 216 MBoe of estimated net proved
reserves. The current rate of 23 Boe per day gross is
approximately 30% of the future peak rate as estimated in our
June 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 23% and 100%, respectively, as of
June 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 52%.
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 June 30, 2011, our other properties contained
145 MBoe of estimated net proved reserves and generated
average net production of 49 Boe per day for the month ended
June 30, 2011.
107
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
108
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
June 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
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Pro Forma as of
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December 31,
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June 30,
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2010(2)
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2011(3)
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Reserve Data(1):
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Estimated proved reserves (MBoe)
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7,116
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7,907
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Estimated proved developed reserves (MBoe)
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3,710
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5,605
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Estimated proved undeveloped reserves (MBoe)
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3,406
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2,302
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Standardized Measure (in millions)(4)
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$
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182.1
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$
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233.1
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(1)
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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 $89.96 per Bbl for oil and $4.20 per MMBtu for natural gas
at June 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 $7.56 per Mcf, respectively, on a
pro forma basis. For the six months ended June 30, 2011,
the relevant average realized prices for oil and natural gas
were $93.55 per Bbl and $8.84 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 six months ended June 30,
2011.
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(2)
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Excludes certain properties which
represented approximately 2% of our proved reserves by value, as
calculated using the standardized measure, as of June 30,
2011 that were sold to the Mid-Con Affiliates on June 30,
2011.
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(3)
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Includes the working interests to
be acquired from J&A Oil Company and Mid-Con Energy
Operating immediately prior to the closing of this offering.
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(4)
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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
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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
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Gas
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Total
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(MBbl)
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(MMcf)
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(MBoe)
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Proved undeveloped reserves-beginning of year
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3,686
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3,686
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Transferred to proved developed through drilling
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(333
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(333
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)
|
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 June 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
$12.5 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.
110
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
|
|
Six Months
|
|
|
Ended
|
|
Ended
|
|
Ended
|
|
Ended
|
|
Ended
|
|
|
June 30,
|
|
June 30,
|
|
December 31,
|
|
December 31,
|
|
June 30,
|
|
|
2008
|
|
2009
|
|
2009
|
|
2010
|
|
2010
|
|
2011
|
|
Production and operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
145
|
|
|
|
153
|
|
|
|
87
|
|
|
|
228
|
|
|
|
104
|
|
|
|
167
|
|
Natural gas (MMcf)
|
|
|
86
|
|
|
|
341
|
|
|
|
140
|
|
|
|
191
|
|
|
|
106
|
|
|
|
79
|
|
Total (MBoe)
|
|
|
159
|
|
|
|
210
|
|
|
|
110
|
|
|
|
260
|
|
|
|
121
|
|
|
|
180
|
|
Average net production (Boe/d)
|
|
|
437
|
|
|
|
575
|
|
|
|
602
|
|
|
|
710
|
|
|
|
666
|
|
|
|
986
|
|
Average sales price:(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
94.20
|
|
|
$
|
66.87
|
|
|
$
|
66.11
|
|
|
$
|
74.07
|
|
|
$
|
72.05
|
|
|
$
|
93.58
|
|
Natural gas (per Mcf)
|
|
$
|
7.17
|
|
|
$
|
6.37
|
|
|
$
|
5.33
|
|
|
$
|
7.44
|
|
|
$
|
7.59
|
|
|
$
|
8.28
|
|
Average price per Boe
|
|
$
|
89.78
|
|
|
$
|
59.06
|
|
|
$
|
59.07
|
|
|
$
|
70.69
|
|
|
$
|
68.58
|
|
|
$
|
90.46
|
|
Average unit costs per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production expenses
|
|
$
|
31.39
|
|
|
$
|
25.56
|
|
|
$
|
22.11
|
|
|
$
|
24.05
|
|
|
$
|
25.01
|
|
|
$
|
19.72
|
|
Production taxes
|
|
$
|
5.93
|
|
|
$
|
3.00
|
|
|
$
|
2.45
|
|
|
$
|
3.17
|
|
|
$
|
3.16
|
|
|
$
|
3.64
|
|
General and administrative and other
|
|
$
|
11.73
|
|
|
$
|
8.41
|
|
|
$
|
6.40
|
|
|
$
|
3.79
|
|
|
$
|
4.83
|
|
|
$
|
2.64
|
|
Depreciation, depletion and amortization
|
|
$
|
9.21
|
|
|
$
|
10.01
|
|
|
$
|
21.43
|
|
|
$
|
20.02
|
|
|
$
|
24.25
|
|
|
$
|
11.55
|
|
|
|
|
(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 45 gross (26 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 October 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 are currently engaged in a workover program to return a
number
111
of inactive wells in these units to production, to optimize
producing well rates and to increase injection. We expect that
this program will be substantially completed by 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 3 gross (2 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, we are in the process of
drilling approximately 55 gross (31 net) wells, with
45 gross (26 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, which are
located in our Southern Oklahoma core area. 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. As of June 30, 2011, we were in the process
of completing the installation of additional waterflood
facilities in the Ardmore West Unit to activate infill injection
wells completed in 2011.
Productive Wells
The following table sets forth information at June 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
|
|
|
|
157
|
|
|
|
1
|
|
|
|
1
|
|
|
|
123
|
|
|
|
66
|
|
Non-operated
|
|
|
1
|
|
|
|
|
|
|
|
4
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
270
|
|
|
|
157
|
|
|
|
5
|
|
|
|
2
|
|
|
|
123
|
|
|
|
66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
112
Developed Acreage
The following table sets forth information as of June 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 June 30, 2011
substantially all of our leasehold acreage was held by
production.
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage
|
|
|
|
Gross
|
|
|
Net
|
|
|
Southern Oklahoma
|
|
|
9,865
|
|
|
|
5,578
|
|
Northeastern Oklahoma
|
|
|
5,919
|
|
|
|
3,576
|
|
Hugoton Basin
|
|
|
4,658
|
|
|
|
3,079
|
|
Other
|
|
|
1,294
|
|
|
|
1,294
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
21,736
|
|
|
|
13,527
|
|
|
|
|
|
|
|
|
|
|
Delivery Commitments
We will have no delivery commitments with respect to our
production upon the closing of this offering.
Operations
General
We operated approximately 98% of our properties, as calculated
on a Boe basis as of June 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 operating 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
113
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 81.8%, on a 100%
working interest basis, based on our June 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 six
months ended June 30, 2011, purchases by Sunoco Logistics
accounted for approximately 76% and 89%, respectively, of our
total sales revenues. Our production is marketed by our
affiliate, Mid-Con Energy Operating, under crude oil purchase
contracts with Sunoco Logistics. By selling a substantial
majority of our production to Sunoco Logistics under these
contracts, we believe that we 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 or any of our other customers could
temporarily delay production and sale of our oil and natural
gas. If we were to lose Sunoco Logistics or any of our
customers, we believe that under current market conditions, we
could identify substitute customers to purchase the impacted
production volumes. However, if Sunoco Logistics 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 Sunoco Logistics,
please read Risk FactorsRisks Related to our
BusinessWe are primarily dependent upon one customer for
our production sales and we may experience a temporary decline
in revenues and production if we lose that customer.
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 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.
114
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 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 32% of
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our total estimated proved reserves as of June 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 $6.0 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 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.
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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 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
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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 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
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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 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
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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. 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 February 28,
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
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
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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 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
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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
The oil and natural gas industry is extensively regulated by
numerous federal, state and local authorities. Legislation
affecting the oil and natural gas industry is under constant
review for amendment or expansion, frequently increasing the
regulatory burden. Additionally, numerous departments and
agencies, both federal and state, are authorized by statute to
issue rules and regulations that are binding on the oil and
natural gas industry and its individual members, some of which
carry substantial penalties for failure to comply. Although the
regulatory burden on the oil and natural gas industry increases
our cost of doing business and, consequently, affects our
profitability, these burdens generally do not affect us any
differently or to any greater or lesser extent than they affect
other companies in the oil and natural gas industry with similar
types, quantities and locations of production.
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.
State Regulation
Our operations are subject to various types of regulation at
federal, state and local levels. These types of regulation
include requiring permits for the drilling of wells, drilling
bonds and reports concerning operations. Most states and some
counties and municipalities in which we operate also regulate
one or more of the following:
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the location of wells;
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the method of drilling and casing wells;
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the surface use and restoration of properties upon which wells
are drilled;
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the permitting and operating of injection wells;
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the plugging and abandoning of wells; and
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notice to surface owners and other third parties.
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State laws regulate the size and shape of drilling and spacing
units or proration units governing the pooling of oil
properties. Some states, like Oklahoma (where most of our
properties are currently located), allow 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
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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 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.
Employees
The officers of our general partner will manage our operations
and activities. However, neither we, our subsidiary, nor our
general partner have employees. Immediately prior to 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 in Dallas, Texas
at . 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 on June 30, 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.
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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, subject to certain transitional
relief during the one-year period following the consummation of
this offering. 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 operating 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.
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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
|
|
|
52
|
|
|
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
|
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
125
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
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
126
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 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
127
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.
Director
Independence
Messrs. Berry and Adamson meet the independence standards
established by the NASDAQ listing rules. In accordance with the
NASDAQ listing rules, one additional independent director must
be appointed within twelve months of listing on the NASDAQ
Global Market.
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 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
128
with our general partner or affiliates. The conflicts committee
will determine if the resolution of the conflict of interest is
fair and reasonable to us. 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, 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 be fair and reasonable to us, approved by all of our
partners and not a breach by our general partner of any duties
it may owe us or our unitholders. Please read Conflicts of
Interest and Fiduciary DutiesConflicts of Interest.
Initially, Messrs. Berry 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 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.
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
129
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 plan 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 plan. 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 plan 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 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 plan 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 plan 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 plan. We expect that annual bonuses
130
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, dental, 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 Plan
In connection with this offering, the board of directors of our
general partner intends to adopt a long-term incentive plan 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 plan 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.
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 plan. 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 Plan
Our general partner intends to adopt a long-term incentive plan
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 plan set forth below
is a summary of the anticipated material features of the plan.
This summary, however, does not purport to be a complete
description of all of the anticipated provisions of the plan.
Additionally, our general partner is still in the process of
implementing the plan and, accordingly, this summary is subject
131
to change prior to the effectiveness of the registration
statement of which this prospectus is a part.
We expect that the long-term incentive plan 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 plan 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 plan will initially limit
the number of units that may be delivered pursuant to vested
awards
to
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 plan will
be administered by the board of directors of our general partner
or a designated committee thereof, which we refer to as the plan
administrator. The plan administrator may also delegate its
duties as appropriate.
Amendment or Termination of Long-Term Incentive
Plan
The plan administrator may terminate or amend the long-term
incentive plan at any time with respect to any units for which a
grant has not yet been made. The plan administrator also has the
right to alter or amend the long-term incentive plan or any part
of the plan 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 plan
will expire on the earliest to occur of (i) the date on
which all common units available under the plan for grants have
been paid to participants, (ii) termination of the plan by
the plan administrator or (iii) the
date
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 plan
administrator may make grants of restricted units containing
such terms as it shall determine, including the period over
which restricted units will vest. The plan administrator, in its
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 plan 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 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 plan administrator, cash
equivalent to the value of a common unit. The plan administrator
may make grants of phantom units under the plan containing such
terms as the plan administrator shall determine, including the
period over which phantom units granted will vest. The plan
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 plan 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
132
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 plan 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 plan administrator may make grants containing such
terms as the plan 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 plan administrator.
Unit Appreciation Rights
The long-term incentive plan 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 plan
administrator may make grants of unit appreciation rights
containing such terms as the plan 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 plan
administrator.
Distribution Equivalent Rights
The plan administrator may, in its discretion, grant
distribution equivalent rights, or DERs, in tandem with phantom
unit awards or other awards under the long-term incentive plan.
DERs entitle the participant to receive cash equal to the amount
of any cash distributions made by us during the period that the
right is outstanding. Payment of a DER issued in connection with
another award may be subject to the same vesting terms as the
award to which it relates or different vesting terms, in the
discretion of the plan administrator.
Other Unit-Based Awards
The long-term incentive plan 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 plan 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; Termination of Service
The plan administrator may provide that awards under the
long-term incentive plan will vest and/or become exercisable, as
applicable, upon a change of control (as defined in
the long-term incentive plan) of us or our general partner. The
consequences of the termination of a grantees employment,
consulting arrangement or membership on the board of directors
will be determined by the plan administrator in the terms of the
relevant award agreement.
Source of Common Units
Common units to be delivered pursuant to awards under the
long-term incentive plan 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
133
incentive plan, 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.
134
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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Yorktown Energy Partners VII, L.P.(1)(3)
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Yorktown Energy Partners VIII, L.P.(1)(4)
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Charles R. Olmstead(5)
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Jeffrey R. Olmstead(5)
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Robbin W. Jones(5)
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David A. Culbertson(5)
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S. Craig George(5)
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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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All named executive officers, directors and director nominees as
a group ( persons)(5)
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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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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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136
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
common units representing an
approximate % limited partner
interest in us. In addition, our general partner will own a 2.0%
general partner interest in us, evidenced
by
general partner units. These percentages do not reflect any
common units that may be issued under the long-term incentive
plan 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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common units;
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general partner units; and
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approximately
$ million in cash.
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To the extent the underwriters exercise their option to purchase
up to an
additional 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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Operational Stage |
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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 % 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
$ million on its general
partner units and the Contributing Parties would receive an
annual distribution of approximately
$ million on their common
units. |
137
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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 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
Contemporaneously 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
operating services, 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,
138
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 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 Mid-Con Energy
Operating 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
$ million.
Merger and Contribution Agreement
In connection with the closing of this offering, we will enter
into a merger and contribution 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 merger and
contribution 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.
Omnibus Agreement
Upon the closing of this offering, we will enter into an omnibus
agreement with our general partner pursuant to which our general
partner will indemnify us against (i) title defects,
subject to a $ per claim de
minimis exception, for amounts in excess of a
$ million threshold, and
(ii) income taxes attributable to pre-closing operations as
of the closing date of this offering. Such indemnification
obligation will (i) survive
for
years after the closing of this offering with respect to title,
and (ii) terminate upon the expiration of the applicable
statute of limitations with respect to income taxes. We will
indemnify our general partner and its affiliates against certain
potential environmental claims, losses and expenses associated
with the operation of our business that arise after the
consummation of this offering. Any or all of the provisions of
the omnibus agreement will terminate upon a change of control of
us or our general partner.
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 June 30, 2011, we had a receivable from J&A Oil
Company, LLC of $62,000 arising from shared derivative
transactions that we jointly entered into with financial
institutions.
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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 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 affiliates of our general partner will own an
approximate % 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, who they control, 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.
140
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 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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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. If our general partner
seeks approval from the conflicts committee, the conflicts
committee will determine if the resolution of a conflict of
interest with our general partner or its affiliates is fair and
reasonable to us. Any matters approved by the conflicts
committee in good faith will be conclusively deemed to be fair
and reasonable to us, approved by all of our partners and not a
breach by our general partner of any duties it may owe us or our
unitholders. 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 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. 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 reasonably believe
that he or she is acting in our best interest.
141
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 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.
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 become
affiliated. Due to these existing and potential future
affiliations and economic interests in
142
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 acting in good
faith 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 advantageous or
beneficial 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 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; and
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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 or the conflicts committee of 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.
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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.
143
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 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 additional options, rights,
warrants and unit appreciation rights relating to our securities;
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the mortgage, pledge, encumbrance, hypothecation or exchange of
any or all of our assets;
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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 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 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.
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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 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
common units representing a %
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.
146
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. 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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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 |
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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 errors of judgment or for any acts or
omissions unless there has been a final and non-appealable
judgment by a court of competent jurisdiction determining that
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 such conduct
was unlawful. |
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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 |
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us, the person bringing or prosecuting such proceeding will have
the burden of overcoming such presumption. These standards
reduce the obligations to which our general partner would
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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
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.
149
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
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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gives the consents, waivers and approvals 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, including a municipality; or
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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.
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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 become a
substituted limited partner in our partnership for the
transferred common units. A transferee will become a substituted
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.
151
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 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. However, our general partner may
not cause us to engage in any business activity that it
determines would 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.
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.
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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 ,
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 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 |
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general partner interest to a third party prior
to , 2021. Please read
Transfer of General Partner Units. |
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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 a 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 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, 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 is irrevocably
consenting to these limitations and provisions regarding claims,
suits, actions or proceedings and submitting to the exclusive
jurisdiction of the Court of Chancery of the State of Delaware
in connection with any such claims, suits, actions or
proceedings.
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 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.
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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 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 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 or the issuance
of partnership interests upon conversion of any outstanding
partnership interests that may be
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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 issue
additional units 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
or 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 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). Upon the consummation of
this offering, affiliates of our general partner (including the
Founders) and Yorktown will own an aggregate of
approximately % of our outstanding
common units representing an aggregate of
approximately % of our outstanding
limited partnership units.
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 year 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, the Investment Advisers Act of 1940, or plan
asset regulations adopted under the Employee Retirement
Income Security Act of 1974, or ERISA, whether or not
substantially similar to plan asset regulations currently
applied or proposed;
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an amendment that our general partner determines to be necessary
or appropriate for the authorization or issuance of additional
partnership securities or rights to acquire partnership
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 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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any amendment necessary to require our limited partners to
provide a statement, certification or other evidence to us
regarding whether such limited partner is subject to United
States federal income taxation on the income generated by us and
to provide for the ability of our general partner to redeem the
units of any limited partner who fails to provide such
statement, certification or other evidence;
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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; 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 our units are 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 is required to be approved by the affirmative vote
of limited partners whose aggregate outstanding units constitute
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 fiduciary duty or obligation
whatsoever to us or our limited partners, including any duty to
act in good faith or 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 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 that approval.
Our general partner may also sell all or substantially all of
our assets under a foreclosure or other realization upon those
encumbrances without that 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
transaction 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 units will be an identical unit of our partnership
following the transaction, and the partnership interests to be
issued do not exceed 20% of our outstanding partnership
interests immediately prior to the transaction.
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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 any of our
subsidiaries into, or convey all of our assets to, a newly
formed entity, 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 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 applicable Delaware law;
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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 or
withdrawal or removal following approval and admission of a
successor general partner.
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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 action would not result in the loss of limited liability
under Delaware law 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.
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 ,
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
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partner and its affiliates (including the Founders), and
furnishing an opinion of counsel regarding limited liability and
tax matters. On or
after ,
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, our
partnership agreement permits our general partner in some
instances to sell or otherwise transfer all of its general
partner interest in us without the approval of the unitholders.
Please read Transfer of General Partner Units.
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 select 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 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 % of our outstanding
common units, representing
approximately % of our outstanding
limited partnership 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 its
affiliate and the successor general partner. If no agreement is
reached, an independent investment banking firm or other
independent expert selected by the departing general partner and
its affiliate and the successor general partner will determine
the fair market value. If the departing general partner and its
affiliate and the successor general partner cannot agree upon an
expert, then an expert chosen by agreement of the experts
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 partners general partner interest will
automatically convert into common units equal to the fair market
value of those interests as determined
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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 Units
Except for the transfer by our general partner of all, but not
less than all, of its general partner units 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 units to another person prior
to ,
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
and Yorktown). As a condition of this transfer, the transferee
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 and its affiliates (including the Founders)
acquires beneficial ownership of 20% or more of any class of
units, that person or group loses voting rights on all of its
units. This loss of voting rights does not apply to any person
or group that acquires the units 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
the units 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.
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 in whole or in
part to any of its affiliates or to us, to acquire all, but not
less than all, of the limited partner interests of the class
held by
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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 the class
purchased within the 90 days preceding the date on which
our general partner first mails notice of its election to
purchase those 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 units then outstanding, record holders
of common units 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. 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 consents in writing describing the action so taken
are signed by holders of 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 units then outstanding,
that person or group will lose voting rights on all of its units
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, determining the
presence of a quorum or for other similar purposes. Common units
held in nominee or street name account will be 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.
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Status as
Limited Partner
By 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. 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 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:
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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, manager, managing
member, partner, fiduciary or trustee of any entity set forth in
the preceding three bullet points;
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any person who is or was serving as a director, officer,
manager, managing member, partner, fiduciary or trustee of
another person at the request of 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.
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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 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. These expenses include salary, bonus,
incentive compensation, 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 of our
business at our principal offices. The books will be maintained
for both tax and financial reporting purposes on an accrual
basis. 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 90 days after the close of each fiscal year,
an annual report containing audited financial statements 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 summary
financial information within 45 days after the close of
each quarter. We will be deemed to have made any such report
available if we file such report with the SEC on EDGAR or make
the report available on a publicly available website which we
maintain.
We will furnish each record holder of a unit with information
reasonably required for tax reporting purposes within
90 days after the close of each calendar year. This
information is expected to be furnished in summary form so that
some complex calculations normally required of partners can be
avoided. Our ability to furnish this summary information to our
unitholders will depend on the cooperation of our unitholders in
supplying us with specific information. Every unitholder will
receive information to assist him in determining his federal and
state tax liability and filing his federal and state income tax
returns, regardless of whether he supplies us with information.
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
partner;
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a copy of our tax returns;
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information as to the amount of cash, and a description and
statement of the agreed value of any other property or services,
contributed or to be contributed by each partner and the date on
which each partner became a partner;
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copies of our partnership agreement, our certificate of limited
partnership, related amendments and any powers of attorney under
which they have been executed;
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information regarding the status of our business and financial
condition; and
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any other information regarding our affairs as 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.
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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 any withdrawal or removal of our general partner. 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
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 % 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 ,
will be allocated, on a cumulative basis, an amount of federal
taxable income for that period that will
be % or less 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 9% 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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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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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.
189
UNDERWRITING
RBC Capital Markets, LLC 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
|
Underwriter
|
|
Common Units
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|
RBC Capital Markets, LLC
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|
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Total
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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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Total
|
|
$
|
|
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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 $ . We will pay
RBC Capital Markets, LLC a structuring fee equal
to % 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 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 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
190
preceding table, and we will be obligated, pursuant to the
option, to sell these common units to the underwriters.
We, our general partner and its affiliates, including the
directors and executive officers of our general partner have
agreed that we will not, directly or indirectly, sell, offer or
otherwise dispose of any common units or enter into any
derivative transaction with similar effect as a sale of common
units 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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|
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the sale of common units to the underwriters;
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|
|
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restricted common units issued by us under the long-term
incentive plan or upon the exercise of options issued under the
long-term incentive plan; or
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|
|
the issuance of common units or securities convertible or
exchangeable into common units as payment of any part of the
purchase price for businesses that we acquire; provided, that
any recipient of such common units must agree to be bound by the
restrictions described in this paragraph for the remainder of
the 180-day
restricted period.
|
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;
|
in which case the restrictions described in the preceding
paragraph will continue to apply until the expiration of the
16-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; or (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. 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 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.
191
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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.
|
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 applied to list our common units on the NASDAQ Global
Market under the symbol MCEP.
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.
192
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.
|
193
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.
194
EXPERTS
The audited balance sheet of Mid-Con Energy Partners, LP as of
June 30, 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 June 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.
195
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.
196
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.
|
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.
197
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.
198
INDEX TO
FINANCIAL STATEMENTS
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Page
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MID-CON ENERGY PARTNERS, LP
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F-2
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F-3
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F-4
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F-5
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F-6
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Historical Balance Sheet:
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F-9
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F-10
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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
June 30, 2011 and for the Six Months Ended June 30,
2010 and 2011:
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F-12
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F-13
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F-14
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F-15
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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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F-27
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F-28
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F-29
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F-30
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F-31
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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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F-52
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F-53
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F-54
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F-55
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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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(restated)
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|
ASSETS
|
Current Assets:
|
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|
Cash and cash equivalents
|
|
$
|
440
|
|
|
|
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|
$
|
16,690
|
|
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|
(a
|
)
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|
$
|
440
|
|
|
|
|
|
|
|
|
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120,000
|
|
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|
(b
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)
|
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|
|
|
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1,873
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|
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|
(c
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)
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|
|
|
|
|
|
|
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(138,563
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)
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(d
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)
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Accounts receivable:
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|
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|
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|
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Oil and natural gas sales
|
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3,619
|
|
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|
|
|
|
|
|
|
|
|
|
|
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3,619
|
|
Affiliate
|
|
|
1,529
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|
|
|
|
|
|
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|
|
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|
1,529
|
|
Certificate of depositgovernment bond
|
|
|
150
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|
|
|
|
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|
|
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150
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|
Prepaids and other
|
|
|
66
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|
|
|
|
|
|
|
|
|
|
|
|
|
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|
66
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|
|
|
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|
|
|
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|
|
|
|
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|
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|
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|
Total current assets
|
|
|
5,804
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|
|
|
|
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|
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|
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5,804
|
|
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|
|
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|
Property and Equipment:
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|
Oil and gas properties, successful efforts method:
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|
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|
Proved properties
|
|
|
71,936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
71,936
|
|
Unproved properties
|
|
|
325
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
325
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(6,476
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,476
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
65,785
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
65,785
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
272
|
|
|
|
|
|
|
|
(240
|
)
|
|
|
(e
|
)
|
|
|
32
|
|
Derivative Financial Instruments
|
|
|
529
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
529
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
72,390
|
|
|
|
|
|
|
$
|
(240
|
)
|
|
|
|
|
|
$
|
72,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
708
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
708
|
|
Accrued liabilities
|
|
|
316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
316
|
|
Revenue payable
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
Derivative financial instruments
|
|
|
387
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
387
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
1,421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt
|
|
|
13,310
|
|
|
|
|
|
|
|
16,690
|
|
|
|
(a
|
)
|
|
|
30,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligations
|
|
|
1,561
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,561
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners Capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contributed capital
|
|
|
57,971
|
|
|
|
|
|
|
|
120,000
|
|
|
|
(b
|
)
|
|
|
39,168
|
|
|
|
|
|
|
|
|
|
|
|
|
(138,563
|
)
|
|
|
(d
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(240
|
)
|
|
|
(e
|
)
|
|
|
|
|
Notes receivable from officers, directors and employees
|
|
|
(1,873
|
)
|
|
|
|
|
|
|
1,873
|
|
|
|
(c
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
56,098
|
|
|
|
|
|
|
|
(16,930
|
)
|
|
|
|
|
|
|
39,168
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
72,390
|
|
|
|
|
|
|
$
|
(240
|
)
|
|
|
|
|
|
$
|
72,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
$
|
15,609
|
|
|
$
|
(721
|
)(f)
|
|
$
|
14,888
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
14,888
|
|
Natural gas sales
|
|
|
657
|
|
|
|
|
|
|
|
657
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
657
|
|
Realized gain (loss) on derivatives, net
|
|
|
(714
|
)
|
|
|
|
|
|
|
(714
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(714
|
)
|
Unrealized gain (loss) on derivatives, net
|
|
|
1,046
|
|
|
|
(62
|
)(f)
|
|
|
984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
16,598
|
|
|
|
(783
|
)
|
|
|
15,815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
3,550
|
|
|
|
(583
|
)(f)
|
|
|
2,967
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,967
|
|
Oil and gas production taxes
|
|
|
655
|
|
|
|
(46
|
)(f)
|
|
|
609
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
609
|
|
Dry holes and abandonments of unproved properties
|
|
|
772
|
|
|
|
|
|
|
|
772
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
772
|
|
Geological and geophysical
|
|
|
58
|
|
|
|
(58
|
)(f)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
2,419
|
|
|
|
(338
|
)(g)
|
|
|
2,081
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,081
|
|
Accretion of discount on asset retirement obligations
|
|
|
32
|
|
|
|
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32
|
|
General and administrative
|
|
|
476
|
|
|
|
|
|
|
|
476
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
476
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
7,962
|
|
|
|
(1,025
|
)
|
|
|
6,937
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,937
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
8,636
|
|
|
|
242
|
|
|
|
8,878
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,878
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income and other
|
|
|
62
|
|
|
|
|
|
|
|
62
|
|
|
|
|
|
|
|
(58
|
)
|
|
|
(h
|
)
|
|
|
4
|
|
Interest expense
|
|
|
(237
|
)
|
|
|
|
|
|
|
(237
|
)
|
|
|
|
|
|
|
(363
|
)
|
|
|
(i
|
)
|
|
|
(600
|
)
|
Gain on sale of assets
|
|
|
1,209
|
|
|
|
(1,209
|
)(f)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other revenue and expense, net
|
|
|
576
|
|
|
|
(576
|
)(f)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expenses)
|
|
|
1,610
|
|
|
|
(1,785
|
)
|
|
|
(175
|
)
|
|
|
|
|
|
|
(421
|
)
|
|
|
|
|
|
|
(596
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
10,246
|
|
|
$
|
(1,543
|
)
|
|
$
|
8,703
|
|
|
|
|
|
|
$
|
(421
|
)
|
|
|
|
|
|
$
|
8,282
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Computation of net income per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
8,116
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of limited partner units outstanding
(basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
15,516
|
|
Natural gas sales
|
|
|
1,418
|
|
|
|
(26
|
)(f)
|
|
|
1,392
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,392
|
|
Realized gain (loss) on derivatives, net
|
|
|
(90
|
)
|
|
|
|
|
|
|
(90
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(90
|
)
|
Unrealized gain (loss) on derivatives, net
|
|
|
(707
|
)
|
|
|
|
|
|
|
(707
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(707
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
17,474
|
|
|
|
(1,363
|
)
|
|
|
16,111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
6,237
|
|
|
|
(1,449
|
)(f)
|
|
|
4,788
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,788
|
|
Oil and gas production taxes
|
|
|
822
|
|
|
|
(81
|
)(f)
|
|
|
741
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
741
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,014
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,362
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(243
|
)
|
|
|
4,992
|
|
|
|
4,749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income and other
|
|
|
218
|
|
|
|
|
|
|
|
218
|
|
|
|
|
|
|
|
(92
|
)
|
|
|
(h
|
)
|
|
|
126
|
|
Interest expense
|
|
|
(98
|
)
|
|
|
|
|
|
|
(98
|
)
|
|
|
|
|
|
|
(1,102
|
)
|
|
|
(i
|
)
|
|
|
(1,200
|
)
|
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
|
|
|
|
|
|
|
|
(1,194
|
)
|
|
|
|
|
|
|
(1,074
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
1,078
|
|
|
$
|
3,791
|
|
|
$
|
4,869
|
|
|
|
|
|
|
$
|
(1,194
|
)
|
|
|
|
|
|
$
|
3,675
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Computation of net income per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,602
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit (basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of limited partner units outstanding
(basic and diluted)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 June 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
June 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 six months
ended June 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 approximately 2% of
its proved reserves by value, as calculated using the
standardized measure, as of such date, 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 common units and
$ million in cash;
|
|
|
|
|
|
the issuance to Mid-Con Energy GP, LLC, the Partnerships
general partner,
of 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
common units (the Offering) and the application of
the net proceeds as described in Use of
Proceeds; and
|
|
|
|
the Partnerships borrowing of approximately
$ million under its new
credit facility and the application of the proceeds as described
in Use of Proceeds.
|
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 June 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 six months ended June 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 six months ended June 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 $30.0 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 $120.0 million from the issuance and sale
of
common units in the offering at an assumed initial public
offering of $ 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
$12.0 million, to repay $13.3 million in outstanding
indebtedness under the predecessors credit facilities and
to make a $123.1 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 $30.0 million
of borrowings by the Partnership under a new credit facility
assuming an interest rate of 4.0%. A one-eighth percentage point
change in the interest rate would change pro forma interest
expense by less than $20,000 for the six months ended
June 30, 2011.
|
|
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
number of common units
was .
All units were assumed to have been outstanding since
January 1, 2010.
F-7
NOTES TO
UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS
(continued)
|
|
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,
|
|
|
June 30,
|
|
|
|
2010
|
|
|
2011
|
|
|
|
(unaudited, in thousands)
|
|
|
|
(as restated, see Note 9)
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
222
|
|
|
$
|
440
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
|
2,134
|
|
|
|
3,619
|
|
Joint operations and other
|
|
|
1,548
|
|
|
|
1,529
|
|
Certificate of depositgovernment bond
|
|
|
150
|
|
|
|
150
|
|
Inventory
|
|
|
771
|
|
|
|
|
|
Prepaids and other
|
|
|
147
|
|
|
|
66
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
4,972
|
|
|
|
5,804
|
|
|
|
|
|
|
|
|
|
|
Property and Equipment:
|
|
|
|
|
|
|
|
|
Oil and gas properties, successful efforts method:
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
57,364
|
|
|
|
71,936
|
|
Unproved properties
|
|
|
446
|
|
|
|
325
|
|
Other property and equipment
|
|
|
2,324
|
|
|
|
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(8,478
|
)
|
|
|
(6,476
|
)
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
51,656
|
|
|
|
65,785
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
239
|
|
|
|
272
|
|
Derivative Financial Instruments
|
|
|
|
|
|
|
529
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
56,867
|
|
|
$
|
72,390
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS EQUITY
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
2,785
|
|
|
$
|
708
|
|
Accrued liabilities
|
|
|
399
|
|
|
|
316
|
|
Revenue payable
|
|
|
182
|
|
|
|
10
|
|
Advance billings and other
|
|
|
1,864
|
|
|
|
|
|
Current portion of long-term debt
|
|
|
5,354
|
|
|
|
|
|
Derivative financial instruments
|
|
|
904
|
|
|
|
387
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
11,488
|
|
|
|
1,421
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt
|
|
|
159
|
|
|
|
13,310
|
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligations
|
|
|
2,148
|
|
|
|
1,561
|
|
|
|
|
|
|
|
|
|
|
Members Equity:
|
|
|
|
|
|
|
|
|
Contributed capital
|
|
|
52,923
|
|
|
|
55,743
|
|
Notes receivable from officers, directors and employees
|
|
|
(1,833
|
)
|
|
|
(1,873
|
)
|
(Accumulated deficit) retained earnings
|
|
|
(8,018
|
)
|
|
|
2,228
|
|
|
|
|
|
|
|
|
|
|
Total members equity
|
|
|
43,072
|
|
|
|
56,098
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and members equity
|
|
$
|
56,867
|
|
|
$
|
72,390
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
2010
|
|
|
2011
|
|
|
|
(unaudited, in thousands)
|
|
|
|
(as restated,
|
|
|
|
|
|
|
see Note 9)
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
7,482
|
|
|
$
|
15,609
|
|
Natural gas sales
|
|
|
803
|
|
|
|
657
|
|
Realized loss on derivatives, net
|
|
|
(91
|
)
|
|
|
(714
|
)
|
Unrealized gain on derivatives, net
|
|
|
545
|
|
|
|
1,046
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
8,739
|
|
|
|
16,598
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
3,038
|
|
|
|
3,550
|
|
Oil and gas production taxes
|
|
|
384
|
|
|
|
655
|
|
Dry holes and abandonments of unproved properties
|
|
|
44
|
|
|
|
772
|
|
Geological and geophysical
|
|
|
287
|
|
|
|
58
|
|
Depreciation, depletion and amortization
|
|
|
3,445
|
|
|
|
2,419
|
|
Accretion of discount on asset retirement obligations
|
|
|
64
|
|
|
|
32
|
|
General and administrative
|
|
|
587
|
|
|
|
476
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
7,849
|
|
|
|
7,962
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
890
|
|
|
|
8,636
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest income and other
|
|
|
151
|
|
|
|
62
|
|
Interest expense
|
|
|
(17
|
)
|
|
|
(237
|
)
|
Gain on sale of assets
|
|
|
353
|
|
|
|
1,209
|
|
Other revenue and expense, net
|
|
|
299
|
|
|
|
576
|
|
|
|
|
|
|
|
|
|
|
Total other income (expenses)
|
|
|
786
|
|
|
|
1,610
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,676
|
|
|
$
|
10,246
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
2,824
|
|
|
|
(43
|
)
|
|
|
|
|
|
|
2,781
|
|
Repurchase of member units
|
|
|
(4
|
)
|
|
|
3
|
|
|
|
|
|
|
|
(1
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
10,246
|
|
|
|
10,246
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at June 30, 2011
|
|
$
|
55,743
|
|
|
$
|
(1,873
|
)
|
|
$
|
2,228
|
|
|
$
|
56,098
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
|
2010
|
|
|
2011
|
|
|
|
(unaudited, in thousands)
|
|
|
|
(as restated,
|
|
|
|
|
|
|
see Note 9)
|
|
|
|
|
|
Cash Flows From Operating Activities:
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,676
|
|
|
$
|
10,246
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
3,445
|
|
|
|
2,419
|
|
Accretion of discount on asset retirement obligations
|
|
|
64
|
|
|
|
32
|
|
Dry holes and abandonments of unproved properties
|
|
|
44
|
|
|
|
772
|
|
Unrealized loss (gain) on derivative instruments, net
|
|
|
(545
|
)
|
|
|
(1,046
|
)
|
Gain on sale of assets
|
|
|
(353
|
)
|
|
|
(1,209
|
)
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(553
|
)
|
|
|
(2,163
|
)
|
Prepaids and other
|
|
|
579
|
|
|
|
54
|
|
Other assets
|
|
|
(92
|
)
|
|
|
(75
|
)
|
Inventory
|
|
|
(148
|
)
|
|
|
(27
|
)
|
Accounts payable
|
|
|
75
|
|
|
|
(4,187
|
)
|
Accrued liabilities
|
|
|
(94
|
)
|
|
|
454
|
|
Revenue payable
|
|
|
(38
|
)
|
|
|
42
|
|
Advance billings and other
|
|
|
2,625
|
|
|
|
(120
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
6,685
|
|
|
|
5,192
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities:
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties
|
|
|
(4,335
|
)
|
|
|
(11,825
|
)
|
Additions to other property and equipment
|
|
|
(250
|
)
|
|
|
(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
|
|
|
(4,306
|
)
|
|
|
(8,161
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(8,284
|
)
|
|
|
(13,351
|
)
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities:
|
|
|
|
|
|
|
|
|
Proceeds from credit facilities
|
|
|
2,300
|
|
|
|
15,950
|
|
Payments on credit facilities
|
|
|
(1,200
|
)
|
|
|
(7,900
|
)
|
Borrowings on note payable
|
|
|
5
|
|
|
|
412
|
|
Payments on note payable
|
|
|
(47
|
)
|
|
|
(84
|
)
|
Repurchase member units
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
1,058
|
|
|
|
8,377
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
(541
|
)
|
|
|
218
|
|
Beginning Cash and Cash Equivalents
|
|
|
763
|
|
|
|
222
|
|
|
|
|
|
|
|
|
|
|
Ending Cash and Cash Equivalents
|
|
$
|
222
|
|
|
$
|
440
|
|
|
|
|
|
|
|
|
|
|
Supplemental Cash Flow Information:
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
12
|
|
|
$
|
189
|
|
|
|
|
|
|
|
|
|
|
Non-Cash Investing and Financing Activities:
|
|
|
|
|
|
|
|
|
Accrued capital expendituresoil and gas properties
|
|
$
|
1,257
|
|
|
$
|
310
|
|
|
|
|
|
|
|
|
|
|
Accounts and notes receivable from officers, directors and
employees
|
|
$
|
|
|
|
$
|
58
|
|
|
|
|
|
|
|
|
|
|
Deferred gain on sale of property and equipment to affiliate
|
|
$
|
|
|
|
$
|
2,766
|
|
|
|
|
|
|
|
|
|
|
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 June 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 for all
periods presented.
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 June 30, 2011,
and its results of operations and cash flow for the six months
ended June 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
June 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 June 30, 2011 and there were no
provisions for bad debts or write-offs of accounts receivable
for the six months ended June 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
June 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 June 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
June 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 June 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 six months ended June 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 $44,000 and $0.8 million as
abandonment expense for the six months ended June 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 six months ended June 30, 2010 and 2011 totaled
approximately $0.5 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
June 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 $1.5 million and $2.1 million for the
six months ended June 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 June 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
June 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
June 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 June 30, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
|
(in thousands)
|
|
|
June 30, 2011
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets and Liabilities Measured as Fair Value on a Recurring
Basis
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instrumentsasset
|
|
$
|
|
|
|
$
|
529
|
|
|
$
|
|
|
Derivative financial instrumentsliability
|
|
$
|
|
|
|
$
|
387
|
|
|
$
|
|
|
Assets and Liabilities Measured at Fair Value on a Nonrecurring
Basis
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
$
|
|
|
|
$
|
|
|
|
$
|
405
|
|
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 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
F-21
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
June 30, 2011
(Unaudited) (continued)
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 June 30, 2011 (in thousands):
|
|
|
|
|
Asset retirement obligations at December 31, 2010
|
|
$
|
2,148
|
|
Liabilities incurred for new wells
|
|
|
311
|
|
Disposition of wells
|
|
|
(1,024
|
)
|
Revision in estimates
|
|
|
94
|
|
Accretion expense
|
|
|
32
|
|
|
|
|
|
|
Asset retirement obligations at June 30, 2011
|
|
$
|
1,561
|
|
|
|
|
|
|
|
|
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 June 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 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.
F-22
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
June 30, 2011
(Unaudited) (continued)
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 June 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)
|
|
Jul-Dec 2011
|
|
$
|
83.25
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
18,000
|
|
|
WTI
|
|
$
|
(248
|
)
|
Jul-Dec 2011
|
|
$
|
86.75
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
18,000
|
|
|
WTI
|
|
|
(181
|
)
|
Jul-Dec 2011
|
|
$
|
85.30
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
12,000
|
|
|
WTI
|
|
|
(139
|
)
|
Jul-Dec 2011
|
|
$
|
89.55
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
18,000
|
|
|
WTI
|
|
|
(129
|
)
|
Jul-Dec 2011
|
|
$
|
100.25
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
36,000
|
|
|
WTI
|
|
|
163
|
|
Jan-Dec 2012
|
|
$
|
104.28
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
72,000
|
|
|
WTI
|
|
|
297
|
|
Jan-Dec 2012
|
|
$
|
100.00
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
96,000
|
|
|
WTI
|
|
|
6
|
|
Jan-Dec 2012
|
|
|
|
|
|
$
|
100.00
|
|
|
$
|
117.00
|
|
|
Collar
|
|
|
72,000
|
|
|
WTI
|
|
|
(23
|
)
|
Jan-Dec 2013
|
|
$
|
105.80
|
|
|
|
|
|
|
|
|
|
|
Price Swap
|
|
|
72,000
|
|
|
WTI
|
|
|
396
|
|
Jan-Dec 2013
|
|
|
|
|
|
$
|
100.00
|
|
|
$
|
111.00
|
|
|
Collar
|
|
|
72,000
|
|
|
WTI
|
|
|
|
|
At June 30, 2011, the predecessor recorded the estimated
fair value of the derivative contracts as $0.5 million as a
long-term asset and $0.4 million as a short term liability.
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 $43,000. 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 13,760 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
F-23
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
June 30, 2011
(Unaudited) (continued)
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 six month ended June 30, 2011:
|
|
|
|
|
Beginning non-vested Class C Units outstanding
|
|
|
35,254
|
|
Awards granted
|
|
|
13,760
|
|
Awards cancelled
|
|
|
|
|
Awards vested
|
|
|
|
|
|
|
|
|
|
Ending non-vested Class C Units outstanding
|
|
|
49,014
|
|
|
|
|
|
|
Notes
Receivable from Officers, Directors and Employees
At June 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
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 June 30, 2011 consisted
of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
June 30,
|
|
|
|
2010
|
|
|
2011
|
|
|
|
(in thousands)
|
|
Revolving credit facilities
|
|
$
|
5,260
|
|
|
$
|
13,310
|
|
Term loans
|
|
|
253
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,513
|
|
|
|
13,310
|
|
Less: Current portion
|
|
|
5,354
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
159
|
|
|
$
|
13,310
|
|
|
|
|
|
|
|
|
|
|
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
F-24
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
June 30, 2011
(Unaudited) (continued)
monthly and charged at the financial institutions prime
rate (4% at June 20, 2011). The predecessors oil
properties located in southern Oklahoma are pledged as security
under the agreements. The predecessor had approximately
$5.3 million and $13.3 million borrowed against their
credit facilities at December 31, 2010 and June 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 June 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.
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 and June 30, 2011 and the
predecessors combined statements of operations and cash
flow for the six months ended June 30, 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-25
Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC
Notes to Combined Financial Statements
June 30, 2011
(Unaudited) (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2011
|
|
|
|
As Previously
|
|
|
|
|
|
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
As Restated
|
|
|
|
(in thousands)
|
|
|
Combined Balance Sheet:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
72,445
|
|
|
$
|
(509
|
)
|
|
$
|
71,936
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(6,793
|
)
|
|
|
317
|
|
|
|
(6,476
|
)
|
Total property and equipment, net
|
|
|
65,977
|
|
|
|
(192
|
)
|
|
|
65,785
|
|
Total assets
|
|
|
72,582
|
|
|
|
(192
|
)
|
|
|
72,390
|
|
Contributed capital
|
|
|
55,753
|
|
|
|
(10
|
)
|
|
|
55,743
|
|
Retained earnings
|
|
|
2,410
|
|
|
|
(182
|
)
|
|
|
2,228
|
|
Total members equity
|
|
|
56,290
|
|
|
|
(192
|
)
|
|
|
56,098
|
|
Total liabilities and members equity
|
|
|
72,582
|
|
|
|
(192
|
)
|
|
|
72,390
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2010
|
|
|
|
As Previously
|
|
|
|
|
|
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
As Restated
|
|
|
|
(in thousands)
|
|
|
Combined Statement of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
$
|
3,629
|
|
|
$
|
(184
|
)
|
|
$
|
3,445
|
|
Total operating costs and expenses
|
|
|
8,033
|
|
|
|
(184
|
)
|
|
|
7,849
|
|
Income from operations
|
|
|
706
|
|
|
|
184
|
|
|
|
890
|
|
Net income
|
|
|
1,492
|
|
|
|
184
|
|
|
|
1,676
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2010
|
|
|
|
As Previously
|
|
|
|
|
|
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
As Restated
|
|
|
|
(in thousands)
|
|
|
Combined Statement of Cash Flow:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,492
|
|
|
$
|
184
|
|
|
$
|
1,676
|
|
Depreciation, depletion and amortization
|
|
|
3,629
|
|
|
|
(184
|
)
|
|
|
3,445
|
|
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
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
August 8,
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 June 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 August 8, 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 June 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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7,733
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1,053
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7,907
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233,147
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Proved Developed Producing
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3,928
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1,051
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4,103
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117,124
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Proved Developed Non-Producing
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1,295
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2
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1,295
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51,832
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Proved Developed Behind Pipe
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207
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0
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207
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7,076
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Proved Undeveloped
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2,302
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0
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2,302
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57,115
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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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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 June 30,
2011 were $89.96/bbl and
$4.20/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 July 1,
2010 through June 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 $85.65 per barrel for oil
and $7.62 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 41 proved undeveloped locations, which
includes two (2) locations in the Harker Ranch Field in
Colorado and 39 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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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 waterflooding or preparing 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.
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 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.
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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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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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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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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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(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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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
Common Units Representing
Limited Partner Interests
PRICE
$
PER COMMON UNIT
RBC
Capital Markets
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
|
|
|
*
|
|
Accounting fees and expenses
|
|
|
*
|
|
Legal fees and expenses
|
|
|
*
|
|
Transfer agent and registrar fees
|
|
|
*
|
|
Miscellaneous
|
|
|
*
|
|
Total
|
|
$
|
*
|
|
|
|
|
|
|
*
|
To be provided by amendment.
|
|
|
|
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
II-1
indemnified upon receipt by the partnership of any undertaking
by or on behalf of the 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 Merger and Contribution Agreement
|
|
10
|
.3**
|
|
|
|
Form of Mid-Con Energy GP, LLC Long-Term Incentive Plan
|
|
10
|
.4**
|
|
|
|
Form of Omnibus Agreement
|
|
10
|
.5**
|
|
|
|
Form of Services Agreement
|
|
10
|
.6
|
|
|
|
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.
|
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 June 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.
|
|
|
|
**
|
|
To be filed by amendment.
|
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 October 5, 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
|
|
October 5, 2011
|
|
|
|
|
|
/s/ CHARLES
R. OLMSTEAD
Charles
R. Olmstead
|
|
Chief Executive Officer and Director
(Principal Executive Officer)
|
|
October 5, 2011
|
|
|
|
|
|
*
Jeffrey
R. Olmstead
|
|
Chief Financial Officer and Director
(Principal Financial Officer)
|
|
October 5, 2011
|
|
|
|
|
|
*
Dave
A. Culbertson
|
|
Chief Accounting Officer (Principal
Accounting Officer)
|
|
October 5, 2011
|
|
|
|
|
|
*
Peter
A. Leidel
|
|
Director
|
|
October 5, 2011
|
|
|
|
|
|
*
Cameron
O. Smith
|
|
Director
|
|
October 5, 2011
|
|
|
|
|
|
*
Robert
W. Berry
|
|
Director
|
|
October 5, 2011
|
|
|
|
|
|
*
Peter
Adamson III
|
|
Director
|
|
October 5, 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 Merger and Contribution Agreement
|
|
10
|
.3**
|
|
|
|
Form of Mid-Con Energy GP, LLC Long-Term Incentive Plan
|
|
10
|
.4**
|
|
|
|
Form of Omnibus Agreement
|
|
10
|
.5**
|
|
|
|
Form of Services Agreement
|
|
10
|
.6
|
|
|
|
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.
|
|
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 June 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.
|
|
|
|
**
|
|
To be filed by amendment.
|