As filed with
the Securities and Exchange Commission on April 13,
2011
Registration
No. 333-171474
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Amendment No. 3
to
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
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VOC Energy Trust
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VOC Brazos Energy Partners, L.P.
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(Exact Name of co-registrant as specified in its charter)
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(Exact Name of co-registrant as specified in its charter)
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Delaware
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Texas
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(State or other jurisdiction of
incorporation or organization)
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(State or other jurisdiction of
incorporation or
organization)
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1311
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1311
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(Primary Standard Industrial
Classification Code Number)
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(Primary Standard Industrial
Classification Code
Number)
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80-6183103
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20-0079353
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(I.R.S. Employer Identification
No.)
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(I.R.S. Employer Identification
No.)
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919 Congress Avenue
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1700 Waterfront Parkway
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Suite 500
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Building 500
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Austin, Texas 78701
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Wichita, Kansas 67206
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(512) 236-6599
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(316) 682-1537
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(Address, including zip code,
and telephone number, including
area code, of co-registrants Principal Executive
Offices)
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(Address, including zip code,
and telephone number, including
area code, of co-registrants Principal Executive
Offices)
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The Bank of New York Mellon Trust
Company, N.A., Trustee
919 Congress Avenue
Suite 500
Austin, Texas 78701
(512) 236-6599
Attention: Michael J. Ulrich
(Name, address, including zip code, and telephone
number,
including area code, of agent for service)
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Barry Hill
1700 Waterfront Parkway
Building 500
Wichita, Kansas 67206
(316) 682-1537
(Name, address, including zip code, and telephone
number,
including area code, of agent for service)
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Copies to:
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David P. Oelman
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Joshua Davidson
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W. Matthew Strock
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Laura Tyson
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Vinson & Elkins L.L.P.
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Baker Botts L.L.P.
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1001 Fannin Street, Suite 2500
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910 Louisiana, Suite 3200
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Houston, Texas
77002-6760
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Houston, Texas 77002
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(713) 758-2222
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(713) 229-1234
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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(c) 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
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 co-registrants hereby amend this Registration Statement
on such date or dates as may be necessary to delay its effective
date until the co-registrants 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.
These securities may not be sold 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 state where the offer or sale is not
permitted.
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Subject to
Completion dated April 13, 2011
PRELIMINARY PROSPECTUS
VOC Energy Trust
10,785,000 Trust Units
This is an initial public offering of units of beneficial
interest in VOC Energy Trust, or the trust. VOC
Sponsor (as defined in the Prospectus Summary) has
formed the trust and, immediately prior to the closing of this
offering, will convey, or cause to be conveyed, a term net
profits interest in oil and natural gas properties (the
Net Profits Interest) to the trust in exchange for
16,540,000 trust units. VOC Sponsor is offering
10,785,000 trust units to be sold in this offering and will
receive all of the proceeds derived therefrom. The underwriters
have been granted an option to purchase from VOC Sponsor up to
1,617,750 additional trust units at the initial public
offering price. VOC Sponsor is a privately-held limited
partnership engaged in the production and development of oil and
natural gas from properties located in Kansas and Texas.
There is currently no public market for the trust units. VOC
Sponsor expects that the public offering price will be between
$19.00 and $21.00 per trust unit. The trust units have been
approved for listing on the New York Stock Exchange under the
symbol VOC, subject to notice of official
issuance.
The trust units. Trust units are units of
beneficial interest in the trust and represent undivided
interests in the trust. They do not represent any interest in
VOC Sponsor.
The trust. The trust will own the Net Profits
Interest, which represents the right to receive during the term
of the trust 80% of the net proceeds from the sale of production
from oil and natural gas properties in Kansas and Texas, which
are referred to as the Underlying Properties, held
by VOC Sponsor as of the date of the conveyance of the Net
Profits Interest to the trust.
The trust unitholders. As a trust
unitholder, you will receive quarterly distributions of cash
from the proceeds that the trust receives from VOC Sponsor
pursuant to the Net Profits Interest. The trusts ability
to pay such quarterly cash distributions will depend on its
receipt of net proceeds attributable to the Net Profits
Interest, which will depend upon, among other things, volumes
produced, wellhead prices, price differentials, production and
development costs and potential reductions or suspensions of
production.
Investing in the trust units involves a high degree of risk.
Before buying any trust units, you should read the discussion of
material risks of investing in the trust units in Risk
factors beginning on page 23 of this prospectus.
These risks include the following:
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Prices of oil and natural gas fluctuate and lower prices could
reduce proceeds to the trust and cash distributions to
unitholders.
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An increase in the differential between the price realized by
VOC Sponsor for oil or natural gas produced from the Underlying
Properties and the NYMEX or other benchmark price of oil or
natural gas could reduce the proceeds to the trust and therefore
the cash distributions by the trust and the value of trust units.
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Estimates of future cash distributions to unitholders are based
on assumptions that are inherently subjective.
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Actual reserves and future production may be less than current
estimates, which could reduce cash distributions by the trust
and the value of the trust units.
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The processes of drilling and completing wells are high risk
activities.
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Neither the trust nor the trusts unitholders will have the
ability to influence VOC Sponsor or control the operations or
development of the Underlying Properties.
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The trust is managed by a trustee who cannot be replaced except
by a majority vote of the unitholders at a special meeting,
which may make it difficult for unitholders to remove or replace
the trustee.
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The tax treatment of an investment in trust units could be
affected by recent and potential legislative changes, possibly
on a retroactive basis.
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The trust has not requested a ruling from the IRS regarding the
tax treatment of ownership of the trust units. If the IRS were
to determine (and be sustained in that determination) that the
trust is not a grantor trust for federal income tax
purposes, or that the Net Profits Interest is not properly
treated as a production payment (and thus would fail to qualify
as a debt instrument) for federal income tax purposes, the trust
unitholders may receive different and potentially less
advantageous tax treatment from that described in this
prospectus.
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Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved of these
securities or passed upon the adequacy or accuracy of this
prospectus. Any representation to the contrary is a criminal
offense.
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Per
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Trust
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Unit
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Total
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Initial public offering price
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$
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$
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Underwriting discounts and commissions (1)
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$
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$
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Proceeds, before expenses, to VOC Sponsor
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$
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$
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(1)
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Excludes a structuring fee of 0.50%
of the gross proceeds of the offering payable to Raymond
James & Associates, Inc. by VOC Sponsor for the
evaluation, analysis and structuring of the trust.
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The underwriters are offering the trust units as set forth
under Underwriting. Delivery of the trust units will
be made on or
about ,
2011.
Joint Book-Running
Managers
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RAYMOND
JAMES |
MORGAN STANLEY |
The date of this prospectus
is ,
2011
Geographic
Location of the Operating Areas
of the Underlying Properties in the States of Kansas and
Texas
TABLE OF
CONTENTS
Important
Notice About Information in This Prospectus
You should rely only on the information contained in this
prospectus or in any free writing prospectus we may authorize to
be delivered to you.
Until ,
2011 (25 days after the date of this prospectus), federal
securities laws may require all dealers that effect transactions
in the trust units, whether or not participating in this
offering, 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.
VOC Sponsor and the trust have not, and the underwriters have
not, authorized anyone to provide you with additional or
different information. If anyone provides you with additional,
different or inconsistent information, you should not rely on
it. This prospectus is not an offer to sell or a solicitation of
an offer to buy the trust units in any jurisdiction where such
offer and sale would be unlawful. You should not assume that the
information contained in this prospectus is accurate as of any
date other than the date on the front of this document. The
trusts business, financial condition, results of
operations and prospects may have changed since such date.
i
PROSPECTUS
SUMMARY
This summary highlights information contained elsewhere in
this prospectus. To understand this offering fully, you should
read the entire prospectus carefully, including the risk factors
and the financial statements and notes to those statements.
Unless otherwise indicated, all information in this prospectus
assumes (a) an initial public offering price of $20.00 per
trust unit and (b) no exercise of the underwriters
option to purchase additional trust units.
Unless the context otherwise requires, as used in this
prospectus, (i) VOC Brazos refers to VOC Brazos
Energy Partners, L.P. without giving pro forma effect to the KEP
Acquisition (as defined below), (ii) KEP refers
to VOC Kansas Energy Partners, LLC, (iii) the Common
Control Properties include certain of the Underlying
Properties (as defined below) held by KEP that are deemed to be
under common control with VOC Brazos, (iv) the
Acquired Underlying Properties include the
Underlying Properties held by KEP that are not under common
control with VOC Brazos, (v) Predecessor refers
to VOC Brazos and the Common Control Properties on a combined
basis, as described in Selected historical and unaudited
pro forma financial, operating and reserve data of VOC
Sponsor, (vi) when discussing the assets, operations
or financial condition and results of operations of VOC Sponsor,
unless otherwise indicated, VOC Sponsor refers to
VOC Brazos and the Common Control Properties after giving effect
to the acquisition of the Acquired Underlying Properties, and
when discussing oil and natural gas reserve information of VOC
Sponsor, refers to the combined amounts of estimated proved oil
and natural gas reserves for VOC Brazos and KEP as reflected in
the reserve reports (as defined below), (vii) when
discussing the financial condition and results of operations
relating to the Underlying Properties, Underlying
Properties refers to the underlying oil and natural gas
properties attributable to Predecessor after giving pro forma
effect to the acquisition of the Acquired Underlying Properties
and after deducting all royalties and other burdens on
production thereon as of the date of the conveyance of the Net
Profits Interest to the trust, and (viii) the KEP
Acquisition refers to the acquisition by VOC Brazos of all
of the membership interests in KEP in exchange for limited
partner interests in VOC Brazos, resulting in KEP becoming a
wholly-owned subsidiary of VOC Brazos. For more information on
the KEP Acquisition and the acquisition of the Acquired
Underlying Properties by Predecessor, please see
Formation transactions and
Information about VOC Brazos Energy Partners, L.P. (VOC
Sponsor) General, respectively.
Cawley, Gillespie & Associates, Inc., an
independent engineering firm, provided the estimates of proved
oil and natural gas reserves for the underlying properties of
each of VOC Brazos and KEP and the Net Profits Interest as of
December 31, 2010, included in this prospectus. These
estimates are contained in summaries prepared by Cawley,
Gillespie & Associates, Inc. of its reserve reports as
of December 31, 2010, for the Underlying Properties and the
Net Profits Interest. These summaries are located at the back of
this prospectus in Annexes A, B, and C and are collectively
referred to in this prospectus as the reserve
reports. You will find definitions for terms relating to
the oil and natural gas business in the Glossary
beginning on page 122.
VOC
ENERGY TRUST
VOC Energy Trust is a Delaware statutory trust formed in
November 2010 by VOC Sponsor to own a term net profits interest
representing the right to receive 80% of the net proceeds
(calculated as described below) from production from
substantially all of the interests in oil and natural gas
properties in the states of Kansas and Texas held by VOC Sponsor
as of the date of the conveyance of the net profits interest to
the trust. We refer to the conveyed interest as the Net
Profits Interest. The Net Profits Interest will terminate
on the later to occur of (1) December 31, 2030, or
(2) the time from and after January 1, 2011 when
10.6 MMBoe (which is the equivalent of 8.5 MMBoe in
respect of the Net Profits Interest) have been produced from the
Underlying Properties and sold.
1
As of December 31, 2010, the Underlying Properties produced
predominantly oil from approximately 881 gross (545.7 net)
wells located in 191 fields. As of December 31, 2010, the
Underlying Properties had a weighted average age (calculated on
a PV-10
basis) of approximately 38 years, and assuming an average
price of $79.43 per Bbl (the average per Bbl price for 2010),
the weighted average expected remaining reserve life (calculated
on a PV-10
basis) of the reserves attributable to the Underlying Properties
was approximately 39 years as of December 31, 2010.
Substantially all of the Underlying Properties are located in
mature oil fields that are characterized by long production
histories and several additional development opportunities,
which may help to diminish natural declines in production from
the Underlying Properties. As of December 31, 2010, the
total proved reserves attributable to the Underlying Properties
were 13.7 MMBoe, of which approximately 84% were classified
as proved developed producing reserves, and approximately 92%
were oil and approximately 8% were natural gas. Based on the
reserve reports, the Net Profits Interest would entitle the
trust to receive net proceeds from the sale of production of
8.5 MMBoe of proved reserves during the term of the trust,
calculated as 80% of the proved reserves attributable to the
Underlying Properties expected to be produced during the term of
the trust. During the year ended December 31, 2010, average
net production from the Underlying Properties was approximately
2,547 Boe per day (or 2,038 Boe per day attributable to the
trust) comprised of approximately 88% oil and approximately 12%
natural gas.
As of December 31, 2010, approximately 98% of the total
proved reserves relating to the Underlying Properties, based on
pre-tax present value of estimated future net revenue using a
discount rate of ten percent per annum
(PV-10),
were operated, or operated on a contract operator basis, by Vess
Oil Corporation (which we refer to as Vess Oil), L.
D. Drilling Inc. or Davis Petroleum, Inc. (which we refer to
collectively with Vess Oil as the VOC Operators).
See Planned development and workover
program for a summary of VOC Sponsors development
plans.
For the years 2011, 2012 and 2013, VOC Sponsor has entered into
swap contracts, which we refer to as the hedge
contracts, at weighted average prices ranging from $94.90
to $100.87 per barrel of oil that hedge approximately 66% of
expected oil production for such years from the proved developed
producing reserves attributable to the Underlying Properties in
the summary reserve reports. The hedge contracts should help
mitigate the impact of any crude oil price volatility on
distributions made on the trust units during the term of the
hedge contracts. Upon expiration in 2013, unitholder exposure to
fluctuations in crude oil prices will increase significantly.
The trust will make quarterly cash distributions of
substantially all of its quarterly cash receipts, after
deduction of fees and expenses for the administration of the
trust (which are estimated to be approximately $900,000 in
2011), to holders of its trust units during the term of the
trust. The first quarterly distribution is expected to be made
on or about August 15, 2011, to trust unitholders owning
trust units on or about August 1, 2011. The trusts
first quarterly distribution will consist of an amount in cash
paid by VOC Sponsor equal to the amount that would have been
payable to the trust had the Net Profits Interest been in effect
during the period from January 1, 2011 through
June 30, 2011, less any general and administrative expenses
and reserves of the trust. As a result of the extended period of
time that will be included in the first quarterly distribution,
subsequent quarterly distributions are likely to be less than
the initial distribution. Because payments to the trust will be
generated by depleting assets and the trust has a finite life
with the production from the Underlying Properties diminishing
over time, a portion of each distribution will represent, in
effect, a return of your original investment.
The trust will receive quarterly cash receipts from the net
proceeds attributable to the Net Profits Interest, with such net
proceeds generally being equal to 80% of the gross proceeds
received from sales of oil and natural gas attributable to the
Underlying Properties for each calendar quarter, less production
and development costs and amounts that may be reserved for
2
future development, maintenance or operating expenditures (which
reserve amounts may not exceed $1.0 million in the
aggregate at any given time), and after giving effect to the
impact of the hedge contracts. See Computation of net
proceeds. Net proceeds payable to the trust will generally
depend upon, among other things, the impact of hedge contracts,
volumes produced, wellhead prices, price differentials and
production and development costs. If the trust does not receive
net proceeds pursuant to the Net Profits Interest, or if such
net proceeds are reduced, the trust will not be able to
distribute cash to the trust unitholders, or such cash
distributions will be reduced, respectively. For the year ended
December 31, 2010, lease operating expenses were
$14.76 per Boe and production and property taxes were $4.45
per Boe, for an aggregate production cost for the Underlying
Properties of $19.21 per Boe. As substantially all of the
Underlying Properties are located in mature fields, VOC Sponsor
does not expect its total future production costs for the
Underlying Properties to change significantly as compared to
recent historical costs other than changes in costs due to any
increases in the cost of general oilfield services in its
operating areas.
The amount of cash available for distribution by the trust will
be reduced by the general and administrative costs of the trust.
The business and affairs of the trust will be managed by The
Bank of New York Mellon Trust Company, N.A. as trustee, and
VOC Sponsor and its affiliates will have no ability to manage or
influence the operations of the trust.
FORMATION
TRANSACTIONS
At or prior to the closing of this offering, the following
transactions, which are referred to herein as the
formation transactions, will occur:
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VOC Brazos will acquire all of the membership interests in KEP
in exchange for newly issued limited partner interests in VOC
Brazos pursuant to a Contribution and Exchange Agreement dated
August 30, 2010, resulting in KEP becoming a wholly-owned
subsidiary of VOC Brazos. KEP was formed in November 2009 to
engage in the production and development of oil and natural gas
primarily within the state of Kansas. KEPs properties
consist of oil and gas properties that have been acquired or
developed by KEPs members since 1979. KEPs members
contributed these properties to KEP in December 2010. The
closing of the KEP Acquisition is conditioned solely upon the
closing of this offering.
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VOC Sponsor will convey to the trust the Net Profits Interest in
exchange for 16,540,000 trust units in the aggregate,
representing all of the outstanding trust units of the trust.
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VOC Sponsor will sell the 10,785,000 trust units offered
hereby, representing a 65.2% interest in the trust. VOC Sponsor
will also make available during the
30-day
option period up to 1,617,750 trust units for the
underwriters to purchase at the initial offering price to cover
over-allotments. VOC Sponsor intends to use the proceeds of the
offering as disclosed under Use of Proceeds.
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Forty-five days following the closing of this offering, VOC
Sponsor will sell the remaining trust units which it holds to
VOC Partners, LLC, an affiliate of VOC Sponsor, at the initial
offering price.
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VOC Sponsor and the trust will enter into an administrative
services agreement which will define the services VOC Sponsor
will provide to the trust on an ongoing basis as well as its
compensation therefor. Please see The trust.
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3
STRUCTURE
OF THE TRUST
The following chart shows the relationship of VOC Sponsor, VOC
Partners, LLC, the trust and the public trust unitholders after
the closing of this offering.
THE
UNDERLYING PROPERTIES
The Underlying Properties consist of VOC Sponsors net
interests in substantially all of its oil and natural gas
properties after deduction of all royalties and other burdens on
production thereon as of the date of conveyance of the Net
Profits Interest to the trust. As of December 31, 2010,
these oil and natural gas properties consisted of approximately
881 gross (545.7 net) producing oil and natural gas wells
in 191 fields in VOC Sponsors two operating areas, Kansas
and Texas. During the year ended December 31, 2010, average
net production from the Underlying Properties was approximately
2,547 Boe per day (or 2,038 Boe per day attributable to the
trust) comprised of approximately 88% oil and approximately 12%
natural gas. VOC Sponsors interests in the properties
comprising the Underlying Properties require VOC Sponsor to bear
its proportionate share, along with the other working interest
owners, of the costs of development and operation of such
properties. As of December 31, 2010, VOC Sponsor held
average working interests of 74.4% and 68.0% in the Underlying
Properties located in the states of Kansas and Texas,
respectively. As of December 31, 2010, the VOC Operators
were the operators or contract operators of approximately 98% of
the total proved reserves attributable to the Underlying
Properties, based on
PV-10 value
and VOC Sponsor held an average net revenue interest of 61.8%
and 56.1% for the Underlying Properties located in Kansas and
Texas respectively. As of December 31, 2010, proved
reserves attributable to the Underlying Properties, as estimated
in the reserve reports, were approximately 13.7 MMBoe with
a PV-10
value of $268.3 million.
Based on the reserve reports, the Net Profits Interest would
entitle the trust to receive net proceeds from the sale of
production of approximately 8.5 MMBoe of proved reserves
over the term of the trust. The trust is entitled to receive 80%
of the net proceeds from the sale of production of oil and
natural gas attributable to the Underlying Properties that are
produced during the term of the trust, whereas total reserves as
reflected in the reserve reports and attributable to the
Underlying Properties include all reserves expected to be
economically produced during the economic life of the properties.
4
VOC Sponsor has agreed to use commercially reasonable efforts to
cause the operators of the Underlying Properties to operate
these properties as would a reasonably prudent operator acting
with respect to its own properties (without regard to the
existence of the Net Profits Interest). In addition, after
giving effect to the conveyance of the Net Profits Interest to
the trust, VOC Sponsors interest in the Underlying
Properties will entitle it to 20% of the net proceeds from the
sale of production of oil and natural gas attributable to the
Underlying Properties during the term of the trust, and 100%
thereafter. VOC Sponsor believes that its retained interests in
the Underlying Properties combined with VOC Partners, LLCs
ownership of trust units representing a 34.8% beneficial
interest in the trust, which collectively entitle VOC Sponsor
and VOC Partners, LLC to receive an aggregate of approximately
48% of the net proceeds from the Underlying Properties, will
provide sufficient incentive to operate and develop the oil and
natural gas properties comprising the Underlying Properties in
an efficient and cost-effective manner. Please see Risk
factors Conflicts of interest could arise between
VOC Sponsor and its affiliates, on the one hand, and the trust
unitholders, on the other hand.
OPERATING
AREAS
The Underlying Properties are located in Kansas and Texas in
areas characterized by long production histories and several
additional development opportunities, which may help to diminish
natural declines in production from the Underlying Properties.
See Planned development and workover
program for a summary of VOC Sponsors development
plans in each of the operating areas of the Underlying
Properties. Based on the reserve reports, approximately 92% of
the future production from the Underlying Properties is expected
to be oil, and approximately 8% is expected to be natural gas.
The following table summarizes, by state, the number of gross
producing wells, the estimated proved reserves attributable to
the Underlying Properties, the corresponding
PV-10 value
as of December 31, 2010, the average working interest, the
average net revenue interest and the average daily net
production attributable to the Underlying Properties for the
year ended December 31, 2010, in each case derived from the
reserve reports. The reserve reports were prepared by Cawley,
Gillespie & Associates, Inc. in accordance with
criteria established by the Securities and Exchange Commission
(the SEC). The summary reserve reports are included
in Annexes A, B, and C to this prospectus.
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Year Ended
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Number
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December 31,
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of
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Proved Reserves (1)
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Average
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2010
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Gross
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Net
|
|
|
Average
|
|
|
|
Producing
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
% Oil
|
|
|
% PDP
|
|
|
PV-10
|
|
|
Working
|
|
|
Revenue
|
|
|
Net Production
|
|
Operating Area
|
|
Wells
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBoe) (2)
|
|
|
Reserves
|
|
|
Reserves
|
|
|
Value (3)
|
|
|
Interest
|
|
|
Interest
|
|
|
(Boe per day)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
Kansas
|
|
|
742
|
|
|
|
6,535
|
|
|
|
3,550
|
|
|
|
7,127
|
|
|
|
91.7
|
%
|
|
|
94.8
|
%
|
|
$
|
134.8
|
|
|
|
74.4
|
%
|
|
|
61.8
|
%
|
|
|
1,536
|
|
Texas
|
|
|
139
|
|
|
|
6,007
|
|
|
|
3,399
|
|
|
|
6,573
|
|
|
|
91.4
|
%
|
|
|
72.6
|
%
|
|
$
|
133.5
|
|
|
|
68.0
|
%
|
|
|
56.1
|
%
|
|
|
1,011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
881
|
|
|
|
12,542
|
|
|
|
6,949
|
|
|
|
13,700
|
|
|
|
91.5
|
%
|
|
|
84.1
|
%
|
|
$
|
268.3
|
|
|
|
71.2
|
%
|
|
|
58.9
|
%
|
|
|
2,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
In accordance with the rules and
regulations promulgated by the SEC, the proved reserves
presented above were determined using the twelve month
unweighted arithmetic average of the
first-day-of-the-month
price for the period from January 1, 2010 through
December 1, 2010, without giving effect to any hedge
transactions, and were held constant for the life of the
properties. This yielded a price for oil of $79.43 per Bbl and a
price for natural gas of $4.37 per MMBtu.
|
|
(2)
|
|
Oil equivalents in the table are
the sum of the Bbls of oil and the Boe of the stated Mcfs of
natural gas, calculated on the basis that six Mcfs of natural
gas is the energy equivalent of one Bbl of oil.
|
|
(3)
|
|
PV-10
is the present value of estimated future net revenue to be
generated from the production of proved reserves, discounted
using an annual discount rate of 10%, calculated without
deducting future income taxes. Standardized
|
5
|
|
|
|
|
measure of discounted net cash
flows is calculated the same as
PV-10 except
that it deducts future income taxes. Because VOC Sponsor bears
no federal income tax expense and taxable income is passed
through to the unitholders of the trust, no provision for
federal or state income taxes is included in the reserve reports
and therefore the standardized measure of discounted future net
cash flows attributable to the Underlying Properties is equal to
the pre-tax
PV-10 value.
PV-10 may not be considered a generally accepted accounting
principle (GAAP) financial measure as defined by the
SEC and is derived from the standardized measure of discounted
future net cash flows, which is the most directly comparable
GAAP financial measure. The pre-tax
PV-10 value
and the standardized measure of discounted future net cash flows
do not purport to present the fair value of the oil and natural
gas reserves attributable to Underlying Properties.
|
PLANNED
DEVELOPMENT AND WORKOVER PROGRAM
The primary goals of VOC Sponsors development and workover
program have been to develop proved undeveloped reserves, manage
workovers and minimize the natural decline in production. No
assurance can be given, however, that any development well will
produce in commercially paying quantities or that the
characteristics of any development well will match the
characteristics of VOC Sponsors existing wells or VOC
Sponsors historical drilling success rate. With respect to
the Underlying Properties, VOC Sponsor expects, but is not
obligated (subject to its reasonable discretion), to implement
the following development strategies specific to each of its
primary operating areas.
|
|
|
|
|
Kansas. VOC Sponsors historical development and
workover program for the Kansas Underlying Properties has
included recompleting certain existing wells, drilling infill
development wells, conducting
3-D seismic
surveys, completing workovers and applying new production
technologies. VOC Sponsor intends to continue this program with
respect to the Kansas Underlying Properties, and expects to
incur total development expenditures for these properties
through December 31, 2015 of approximately
$3.2 million. Of this total, VOC Sponsor contemplates
spending approximately $2.5 million to drill and complete
13 vertical wells. The remaining approximate
$0.7 million is expected to be used for recompletions and
workovers of 12 wells.
|
|
|
|
Texas. VOC Sponsors historical development and
workover program for the Texas Underlying Properties has
included recompleting certain existing wells, drilling infill
development wells, completing workovers and applying new
production technologies. In 2009, after an extensive review of
horizontal development drilling in the area, VOC Sponsor
commenced drilling horizontal wells in the Kurten Woodbine Unit
in order to accelerate the development of proved undeveloped
reserves. VOC Sponsor has successfully completed each of its
first four horizontal wells to the Woodbine C sand in this area
with average lateral lengths of approximately 3,000 feet.
VOC Sponsor intends to continue developing the Woodbine C sand
underlying the Kurten Woodbine Unit, utilizing horizontal wells
completed with multiple fracture stimulations together with
recompletions of existing vertical wellbores into additional pay
intervals. VOC Sponsor expects total development expenditures
for the Texas Underlying Properties through December 31,
2015 to be approximately $24.0 million. Of this total, VOC
Sponsor contemplates spending approximately $22.5 million
to drill and complete 11 horizontal wells in the Woodbine C
sand. The remaining approximate $1.5 million is expected to
be used for recompletions and workovers of 12 Woodbine vertical
wells to additional Woodbine sands and seven existing wells in
the Sand Flat Unit.
|
VOC
SPONSOR
VOC Brazos is a privately-held limited partnership engaged in
the production and development of oil and natural gas from
properties located in Texas. VOC Brazos was formed in May 2003.
Pursuant to the KEP Acquisition, VOC Brazos will acquire KEP,
which was formed in
6
November 2009 to develop and produce oil and natural gas from
properties primarily located in Kansas along with a limited
number of Texas properties. There are no conditions to the
closing of the KEP Acquisition other than the closing of this
offering. Members of KEP acquired interests in the properties
owned by KEP through various acquisitions and drilling
activities that have occurred since 1979. See
Formation transactions for a more
detailed discussion of the KEP Acquisition.
As of December 31, 2010, VOC Sponsor held interests in
approximately 881 gross (545.7 net) producing wells,
and proved reserves of the Underlying Properties were
approximately 13.7 MMBoe. As of December 31, 2010,
based on
PV-10 value,
the VOC Operators were the operators or contract operators of
approximately 98% of the total proved reserves attributable to
the Underlying Properties, with Vess Oil operating approximately
91% of the total proved reserves and L.D. Drilling Inc. and
Davis Petroleum, Inc. operating approximately 7% of the total
proved reserves. Vess Oil has operated oil and natural gas
properties in Kansas for more than 30 years and, according
to statistics furnished by the Kansas Geological Survey, was the
second largest operator of oil properties in Kansas measured by
production during 2010. Vess Oil currently operates over 1,600
oil, natural gas and service wells located primarily in Kansas,
with growing operations in Texas. As of December 31, 2010,
Vess Oil employed 19 full-time employees, three contract
professionals and 14 contract personnel in its Wichita office
and in five field and satellite offices.
For the year ended December 31, 2010, VOC Sponsor had pro
forma revenues and net earnings of $62.8 million and
$30.6 million, respectively. As of December 31, 2010,
VOC Sponsor had pro forma total assets of $202.2 million
and total liabilities of $42.6 million, including
indebtedness outstanding of $24.0 million. After giving
further pro forma effect to the conveyance of the Net Profits
Interest to the trust, the offering of the trust units
contemplated by this prospectus and the application of the net
proceeds as described in Use of proceeds, as of
December 31, 2010, VOC Sponsor would have had total assets
of $96.4 million and total liabilities of
$123.1 million, with no indebtedness outstanding. For an
explanation of the pro forma adjustments, please read
Financial statements of Predecessor Unaudited
pro forma statement of earnings.
The address of VOC Sponsor is 1700 Waterfront Parkway, Building
500, Wichita, Kansas 67206, and its telephone number is
(316) 682-1537.
KEY
INVESTMENT CONSIDERATIONS
The following are some key investment considerations related to
the Underlying Properties, the Net Profits Interest and the
trust units:
|
|
|
|
|
Long-lived oil-producing properties. Oil-producing
properties in VOC Sponsors areas of operation have
historically had stable production profiles and generally
long-lived production. VOC Sponsor acquired interests in the
Texas Underlying Properties through various acquisitions that
have occurred since the inception of VOC Brazos in 2003 and in
the Kansas Underlying Properties through the contribution to KEP
by its members in December 2010 of properties obtained through
various acquisitions and drilling activities since 1979. Proved
reserves attributable to the Underlying Properties have remained
relatively stable, with proved reserves of approximately 10.8
MMBoe as of December 31, 2008 (based on a
year-end oil
price of $44.60 per Bbl), 13.0 MMBoe as of
December 31, 2009 (based on average oil prices of $61.18
per Bbl) and 13.7 MMBoe as of December 31, 2010 (based
on average oil prices of $79.43 per Bbl). Based on the reserve
reports and assuming for purposes of this calculation that no
additional development drilling or other development
expenditures are made on the Underlying Properties after 2014,
production
|
7
|
|
|
|
|
from the Underlying Properties is expected to decline at an
average annual rate of approximately 6.2% over the next
20 years. VOC Sponsor may continue to drill beyond 2014,
and such drilling may reduce the anticipated decline rate if
successful.
|
|
|
|
|
|
Substantial proved developed producing reserves. Proved
developed producing reserves are the lowest risk category of
reserves because production has already commenced, and VOC
Sponsor does not expect the proved developed producing reserves
attributable to the Underlying Properties to require significant
future development costs. Proved developed producing reserves
attributable to the Underlying Properties represented
approximately 84% of the proved reserves attributable to the
Underlying Properties as of December 31, 2010.
|
|
|
|
Near term development activities. VOC Sponsor has
identified multiple locations on the Underlying Properties on
which it intends to drill new infill wells and recomplete
existing wells into new horizons over the next several years.
See Planned development and workover
program for a summary of VOC Sponsors development
plans. These locations are currently classified as proved
undeveloped reserves on the reserve reports. If these wells are
successfully completed or recompleted, as the case may be, the
additional production from these wells would partially offset
the natural decline in production from the Underlying
Properties. Any additional incremental revenue received by VOC
Sponsor from this additional production could have the effect of
increasing future distributions to the trust unitholders. No
assurance can be given, however, that any development well will
produce in commercially paying quantities or that the
characteristics of any development well will match the
characteristics of VOC Sponsors existing wells or VOC
Sponsors historical drilling success rate.
|
|
|
|
Operational control. The right to operate an oil and
natural gas lease is important because the operator can control
the timing and amount of discretionary expenditures for
operational and development activities. As of December 31,
2010, the VOC Operators operated, or operated on a contract
basis, approximately 98% of the proved reserves attributable to
the Underlying Properties based on
PV-10 value.
|
|
|
|
|
|
Experienced Royalty Trust Sponsor. Certain members
of VOC Sponsors management team were involved in the
formation and initial public offering of MV Oil Trust (NYSE:
MVO) (MVO) a publicly-traded trust that is similar
to VOC Energy Trust. In connection with the formation of MVO,
the sponsor conveyed an 80% term net profits interest in oil and
natural gas properties in the Mid-Continent region in Kansas and
Colorado to MVO in exchange for trust units, a portion of which
were sold by the sponsor in MVOs initial public offering
in January 2007. The terms of the net profits interest being
conveyed in connection with the formation of VOC Energy Trust
are similar to those of the net profits interest which was
conveyed to MVO. To offset the natural decline in production of
the proved developed wells, the sponsor planned and executed a
development and workover program. The results of this program
have partially mitigated the decline, with average net
production being approximately 2,859 Boe per day (or
approximately 2,287 Boe per day attributable to MVOs 80%
net profit interest) at the time of the initial public offering
and 2,621 Boe per day (or approximately 2,097 Boe per day
attributable to MVOs 80% net profit interest) for the year
ended December 31, 2010. As a result of differences in
pricing, well locations, costs, development schedule,
development expenditures and regulatory environment, among other
things, the historical results of operations and performance of
MVO should not be relied on as an indicator of how the trust
will perform. The final prospectus relating to the initial
public offering of MVO set forth a projection for the twelve
months ended December 31, 2007 that totaled $3.02 per MVO
trust unit. Actual distributions for each of the second, third
and fourth quarters of 2007
|
8
and the twelve months ended December 31, 2007 (totaling
$2.48 per MVO trust unit) were below the projected amounts
outlined in such final prospectus. For a description of the
prior performance of MVO, including a discussion of the reasons
underlying why actual distributions for the twelve months ended
December 31, 2007 were below certain estimated
distributions as outlined in its prospectus relating to its
initial public offering, please see MV Oil Trust on
page 47.
|
|
|
|
|
Strong oil fundamentals. Substantially all of the
production from the Underlying Properties consists of crude oil.
According to the US Energy Information Administration
(EIA) projections, world oil prices are expected to
rise gradually. These projections assume that global economic
growth results in higher global oil demand, growth in supply
from countries who are not members of the Organization of the
Petroleum Exporting Countries (OPEC) slows in 2011,
and members of OPEC continue to support world oil prices while
commercial oil inventories in the Organization for Economic
Cooperation and Development (OECD) countries begin
to decline.
|
|
|
|
|
|
Downside oil price protection. For the years 2011, 2012
and 2013, VOC Sponsor has entered into swap contracts, which we
refer to as the hedge contracts, at weighted average
prices ranging from $94.90 to $100.87 per barrel of oil that
hedge approximately 66% of expected oil production for such
years from the proved developed producing reserves attributable
to the Underlying Properties in the summary reserve reports. The
hedge contracts should help mitigate the impact of any crude oil
price volatility on distributions made on the trust units during
the term of the hedge contracts. Upon expiration in 2013,
unitholder exposure to fluctuations in crude oil prices will
increase significantly. Under the terms of the conveyance, VOC
Sponsor will be prohibited from entering into hedging
arrangements for the benefit of the trust and, under the terms
of the trust agreement, the trustee is not empowered to enter
into hedge contracts with trust proceeds. For more information
on VOC Sponsors hedge positions, please see The
Underlying Properties Hedge contracts.
|
|
|
|
|
|
Aligned interests of sponsor. Following the closing of
this offering, VOC Sponsor, together with VOC Partners, LLC,
will be entitled to receive an aggregate of approximately 48% of
the net proceeds attributable to the sale of oil and natural gas
produced from the Underlying Properties. This 48% interest will
consist of (1) the 20% of the net proceeds from the sale of
production of oil and natural gas and attributable to the
Underlying Properties that is retained by VOC Sponsor after
transferring to the trust the Net Profits Interest and
(2) the ownership by VOC Partners, LLC of approximately 35%
of the trust units following the closing of this offering.
|
RISK
FACTORS
An investment in the trust units involves risks, including those
listed below. Please read carefully the risks described under
Risk Factors on page 23 of this prospectus.
|
|
|
|
|
Prices of oil and natural gas fluctuate, and lower prices could
reduce proceeds to the trust and cash distributions to
unitholders.
|
|
|
|
An increase in the differential between the price realized by
VOC Sponsor for oil or natural gas produced from the Underlying
Properties and the NYMEX or other benchmark price of oil or
natural gas could reduce the proceeds to the trust and therefore
the cash distributions by the trust and the value of trust units.
|
9
|
|
|
|
|
Estimates of future cash distributions to unitholders are based
on assumptions that are inherently subjective.
|
|
|
|
Actual reserves and future production may be less than current
estimates, which could reduce cash distributions by the trust
and the value of the trust units.
|
|
|
|
The processes of drilling and completing wells are high risk
activities.
|
|
|
|
Risks associated with the production, gathering, transportation
and sale of oil and natural gas could adversely affect cash
distributions by the trust.
|
|
|
|
VOC Sponsor does not have any long term contracts related to the
sale of production of oil and natural gas from the Underlying
Properties and may be unable to find purchasers.
|
|
|
|
Neither the trust nor the trusts unitholders will have the
ability to influence VOC Sponsor or control the operations or
development of the Underlying Properties.
|
|
|
|
Shortages or increases in costs of equipment, services and
qualified personnel could result in a reduction in the amount of
cash available for distribution to the trust unitholders.
|
|
|
|
The trust units may lose value as a result of title deficiencies
with respect to the Underlying Properties.
|
|
|
|
VOC Sponsor may transfer all or a portion of the Underlying
Properties at any time without trust unitholder consent, subject
to specified limitations.
|
|
|
|
The reserves attributable to the Underlying Properties are
depleting assets and production from those properties will
diminish over time.
|
|
|
|
The amount of cash available for distribution by the trust will
be reduced by the amount of any costs and expenses related to
the Underlying Properties and other costs and expenses incurred
by the trust.
|
|
|
|
The trustee may, under certain circumstances, sell the Net
Profits Interest and dissolve the trust prior to the expected
termination of the trust. As a result, trust unitholders may not
recover their investment.
|
|
|
|
VOC Partners, LLC may sell trust units in the public or private
markets, and such sales could have an adverse impact on the
trading price of the trust units.
|
|
|
|
There has been no public market for the trust units and no
independent appraisal of the value of the Net Profits Interest
has been performed.
|
|
|
|
The trading price for the trust units may not reflect the value
of the Net Profits Interest held by the trust.
|
|
|
|
Conflicts of interest could arise between VOC Sponsor and its
affiliates, on the one hand, and the trust unitholders, on the
other hand.
|
|
|
|
The trust is managed by a trustee who cannot be replaced except
by a majority vote of the unitholders at a special meeting,
which may make it difficult for unitholders to remove or replace
the trustee.
|
10
|
|
|
|
|
Trust unitholders have limited ability to enforce provisions of
the Net Profits Interest, and VOC Sponsors liability to
the trust is limited.
|
|
|
|
Courts outside of Delaware may not recognize the limited
liability of the trust unitholders provided under Delaware law.
|
|
|
|
The operations of the Underlying Properties are subject to
environmental laws and regulations that may result in
significant costs and liabilities, which could reduce the amount
of cash available for distribution to trust unitholders.
|
|
|
|
The operations of the Underlying Properties are subject to
complex federal, state, local and other laws and regulations
that could adversely affect the cost, manner or feasibility of
conducting its operations or expose VOC Sponsor to significant
liabilities, which could reduce the amount of cash available for
distribution to trust unitholders.
|
|
|
|
Climate change laws and regulations restricting emissions of
greenhouse gases could result in increased operating
costs and reduced demand for the oil and natural gas that VOC
Sponsor produces while the physical effects of climate change
could disrupt VOC Sponsors production and cause VOC
Sponsor to incur significant costs in preparing for or
responding to those effects.
|
|
|
|
Federal and state legislative and regulatory initiatives
relating to hydraulic fracturing could result in increased costs
and additional operating restrictions or delays as well as
adversely affect VOC Sponsors services.
|
|
|
|
The bankruptcy of VOC Sponsor or any of the VOC Operators could
impede the operation of the wells and the development of the
proved undeveloped reserves.
|
|
|
|
The trust may be treated as an unsecured creditor with respect
to the Net Profits Interest attributable to properties in Kansas
in the event of the bankruptcy of VOC Sponsor if a court were to
hold that the conveyance and recording of the Net Profits
Interest was not a conveyance of a fully vested real property
interest or an interest in hydrocarbons in place or to be
produced.
|
|
|
|
Due to lack of geographic diversification of the Underlying
Properties, adverse developments in Kansas or Texas could
adversely impact the results of operations and cash flows of the
Underlying Properties and reduce the amount of cash available
for distributions to trust unitholders.
|
|
|
|
The receipt of payments by VOC Sponsor based on the hedge
contracts depends upon the financial position of the hedge
contract counterparties. A default by any of the hedge contract
counterparties could reduce the amount of cash available for
distribution to the trust unitholders.
|
|
|
|
VOC Sponsors performance of its obligations to the trust
and the financial results of the trust may differ from the
drilling and financial results of MVO.
|
|
|
|
The tax treatment of an investment in trust units could be
affected by recent and potential legislative changes, possibly
on a retroactive basis.
|
|
|
|
The trust has not requested a ruling from the IRS regarding the
tax treatment of ownership of the trust units. If the IRS were
to determine (and be sustained in that determination) that the
trust is not a grantor trust for federal income tax
purposes, or
|
11
|
|
|
|
|
that the Net Profits Interest is not properly treated as a
production payment (and thus would fail to qualify as a debt
instrument) for federal income tax purposes, the trust
unitholders may receive different and potentially less
advantageous tax treatment from that described in this
prospectus.
|
SUMMARY
PROVED RESERVES
Summary proved reserves of Underlying Properties and Net
Profits Interest. As of December 31, 2010, estimated
proved reserves attributable to the Underlying Properties were
approximately 92% oil and approximately 8% natural gas, based on
the reserve reports. The following table sets forth, as of
December 31, 2010, certain estimated proved oil and natural
gas reserves, estimated future net revenues and the discounted
present value thereof attributable to the Underlying Properties
and the Net Profits Interest, in each case as derived from the
reserve reports.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves of the Underlying Properties
|
|
Undiscounted
|
|
|
|
|
Oil
|
|
Natural Gas
|
|
Oil Equivalent
|
|
Future Net
|
|
PV-10
|
|
|
(MBbls )
|
|
(MMcf)
|
|
(MBoe)
|
|
Revenues
|
|
Value (3)
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Underlying Properties (total) (1)
|
|
|
12,542
|
|
|
|
6,949
|
|
|
|
13,700
|
|
|
$
|
569,829
|
|
|
$
|
268,283
|
|
Underlying Properties (attributable to the Net Profits Interest)
(2)
|
|
|
7,712
|
|
|
|
4,819
|
|
|
|
8,515
|
|
|
$
|
379,296
|
|
|
$
|
208,552
|
|
|
|
|
(1)
|
|
Reflects 100% of the proved
reserves attributable to the Underlying Properties.
|
|
(2)
|
|
Reflects 80% of proved reserves
attributable to the Underlying Properties expected to be
produced during the term of the trust.
|
|
(3)
|
|
PV-10
is the present value of estimated future net revenue to be
generated from the production of proved reserves, discounted
using an annual discount rate of 10%, calculated without
deducting future income taxes. Standardized measure of
discounted net cash flows is calculated the same as
PV-10 except
that it deducts future income taxes. Because VOC Sponsor bears
no federal income tax expense and taxable income is passed
through to the unitholders of the trust, no provision for
federal or state income taxes is included in the reserve reports
and therefore the standardized measure of discounted future net
cash flows attributable to the Underlying Properties is equal to
the pre-tax
PV-10 value.
PV-10 may not be considered a generally accepted accounting
principle (GAAP) financial measure as defined by the
SEC and is derived from the standardized measure of discounted
future net cash flows, which is the most directly comparable
GAAP financial measure. The pre-tax
PV-10 value
and the standardized measure of discounted future net cash flows
do not purport to present the fair value of the oil and natural
gas reserves attributable to Underlying Properties.
|
12
Annual production attributable to Net Profits Interest.
The following graph shows estimated monthly production of total
proved reserves attributable to the Net Profits Interest based
upon the pricing and other assumptions set forth in the reserve
reports. This graph presents the total proved reserves as
reflected in the reserve reports broken down by three reserve
categories (proved developed producing, proved developed
non-producing and proved undeveloped reserves) which demonstrate
the impact of developmental drilling and well re-completion and
workover activities that VOC Sponsor expects to undertake with
respect to the Underlying Properties within the next five years.
For a description of VOC Sponsors planned development,
workover and recompletion programs over the next five years, see
The Underlying Properties Planned development
and workover program.
Estimated
Annual Production of Proved Reserves
Attributable to the Net Profits Interest
13
SUMMARY
UNAUDITED PRO FORMA COMBINED FINANCIAL DATA AND OPERATING DATA
FOR THE UNDERLYING PROPERTIES OF VOC SPONSOR AND THE
TRUST
Pro Forma
Combined Financial Data of the Underlying Properties
The summary unaudited pro forma combined financial data
presented below should be read in conjunction with The
Underlying Properties Selected historical and
unaudited pro forma financial and operating data of the
Underlying Properties and the accompanying financial
statements and related notes included elsewhere in this
prospectus. The following table sets forth revenues, direct
operating expenses and the excess of revenues over direct
operating expenses relating to the Predecessor Underlying
Properties after giving pro forma effect to the acquisition of
the Acquired Underlying Properties. The summary unaudited pro
forma financial data for the year ended December 31, 2010
have been derived from the unaudited pro forma statements of
historical revenues and direct operating expenses of the
Underlying Properties included in this prospectus beginning on
page F-18.
The pro forma adjustments have been prepared as if the
acquisition of the Acquired Underlying Properties by Predecessor
had taken place as of January 1, 2010.
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31, 2010
|
|
|
|
(In thousands)
|
|
|
|
(Unaudited)
|
|
|
Revenues:
|
|
|
|
|
Oil sales
|
|
$
|
60,187
|
|
Natural gas sales
|
|
|
3,239
|
|
Hedge and other derivative activity
|
|
|
(707
|
)
|
|
|
|
|
|
Total
|
|
|
62,719
|
|
|
|
|
|
|
Direct operating expenses:
|
|
|
|
|
Lease operating expenses
|
|
|
13,727
|
|
Production and property taxes
|
|
|
4,137
|
|
|
|
|
|
|
Total
|
|
|
17,864
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
$
|
44,855
|
|
|
|
|
|
|
14
Pro Forma
Distributable Income of the Trust
The table below outlines the calculation of distributable income
from Net Profits Interest derived from the excess of revenues
over direct operating expenses of the Underlying Properties for
the year ended December 31, 2010 and should be read in
conjunction with the unaudited pro forma financial information
of the Trust included in this prospectus beginning on
page F-24. The pro forma amounts below do not purport to
present cash available for distribution by the trust to trust
unitholders had the formation transactions contemplated actually
occurred on January 1, 2010. In addition, cash available
for distribution by the trust will be calculated based upon
actual cash receipts of the trust during the applicable quarter,
while the unaudited pro forma available cash calculation has
been prepared using a modified cash basis of accounting as
described in more detail in Note B to the unaudited pro
forma financial statements appearing on page
F-27. As a
result, you should view the amount of unaudited pro forma
available cash only as a general indication of the amount of
cash available for distribution by the trust for the year ended
December 31, 2010 had the formation transactions described
above actually occurred on January 1, 2010.
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31, 2010
|
|
|
|
|
|
|
(In thousands,
|
|
|
|
|
|
|
except per unit data)
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
$
|
44,855
|
|
|
|
|
|
Less development expenses
|
|
|
10,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses and
development expenses
|
|
|
34,363
|
|
|
|
|
|
Times Net Profits Interest over the term of the trust
|
|
|
80
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Net Profits Interest
|
|
|
27,490
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma adjustments:
|
|
|
|
|
|
|
|
|
Less estimated trust general and administrative expenses
|
|
|
900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable income (1)
|
|
$
|
26,590
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable income per trust unit (2)
|
|
$
|
1.61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Per the terms of the Net Profits
Interest, development costs are to be deducted when calculating
the distributable income to the trust.
|
|
|
|
(2)
|
|
Due to the timing of the payment of
production proceeds to the trust, the production and costs
attributable to the available distributions for the twelve
months ended December 31, 2010 would have been for the
eleven months ended November 30, 2010, if the pro forma
available cash for distribution were calculated based on a
modified cash basis. As a result, the pro forma distributable
income per trust unit for the twelve months ended
December 31, 2010 would have been $1.43.
|
15
Operating
Data of the Underlying Properties
The following table provides oil and natural gas sales volumes,
average sales prices and capital expenditures relating to the
Underlying Properties for the years ended December 31,
2008, 2009 and 2010. Average sales prices do not include the
effect of hedge activity.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Underlying
Properties (1)
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
704
|
|
|
|
732
|
|
|
|
817
|
|
Natural gas (MMcf)
|
|
|
750
|
|
|
|
693
|
|
|
|
679
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales (MBoe)
|
|
|
829
|
|
|
|
847
|
|
|
|
930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
93.67
|
|
|
$
|
55.16
|
|
|
$
|
73.71
|
|
Natural gas (per Mcf)
|
|
$
|
7.46
|
|
|
$
|
3.31
|
|
|
$
|
4.77
|
|
Capital expenditures (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition
|
|
$
|
7,899
|
|
|
$
|
4,134
|
|
|
$
|
3,262
|
|
Well development
|
|
|
2,499
|
|
|
|
2,407
|
|
|
|
7,230
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
10,398
|
|
|
$
|
6,541
|
|
|
$
|
10,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The operating data below includes
the effect of the Acquired Underlying Properties for all periods
presented.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Predecessor Underlying
Properties
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
389
|
|
|
|
407
|
|
|
|
495
|
|
Natural gas (MMcf)
|
|
|
426
|
|
|
|
415
|
|
|
|
447
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
460
|
|
|
|
477
|
|
|
|
569
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
94.11
|
|
|
$
|
55.86
|
|
|
$
|
74.59
|
|
Natural gas (per Mcf)
|
|
$
|
7.86
|
|
|
$
|
3.64
|
|
|
$
|
5.36
|
|
Capital expenditures (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition
|
|
$
|
6,715
|
|
|
$
|
2,369
|
|
|
$
|
2,606
|
|
Well development
|
|
|
1,063
|
|
|
|
1,955
|
|
|
|
6,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
7,778
|
|
|
$
|
4,324
|
|
|
$
|
9,372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Acquired Underlying
Properties
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
315
|
|
|
|
324
|
|
|
|
322
|
|
Natural gas (MMcf)
|
|
|
324
|
|
|
|
278
|
|
|
|
232
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales (MBoe)
|
|
|
369
|
|
|
|
371
|
|
|
|
360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
93.12
|
|
|
$
|
54.27
|
|
|
$
|
72.35
|
|
Natural gas (per Mcf)
|
|
$
|
6.94
|
|
|
$
|
2.81
|
|
|
$
|
3.63
|
|
Capital expenditures (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition
|
|
$
|
1,184
|
|
|
$
|
1,765
|
|
|
$
|
655
|
|
Well development
|
|
|
1,436
|
|
|
|
452
|
|
|
|
464
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,620
|
|
|
$
|
2,217
|
|
|
$
|
1,119
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Historical
and Pro Forma Financial Data of VOC Sponsor
The summary historical audited financial data of Predecessor as
of and for the year ended December 31, 2010 have been
derived from the audited financial statements of Predecessor
beginning on page
VOC F-2.
The summary unaudited pro forma financial data as of and for the
year ended December 31, 2010 set forth in the following
table have been derived from the unaudited pro forma financial
statements of Predecessor included in this prospectus beginning
on page VOC
F-24. The
pro forma adjustments have been prepared as if the acquisition
of the Acquired Underlying Properties and, with respect to pro
forma as adjusted information, the conveyance of the Net Profits
Interest, the offer and sale of the trust units and application
of the net proceeds therefrom, had taken place (i) on
December 31, 2010, in the case of the pro forma balance
sheet information as of December 31, 2010, and (ii) as
of January 1, 2010, in the case of the pro forma statement
of earnings information for the year ended December 31,
2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor Pro Forma
|
|
Predecessor Pro Forma As
|
|
|
|
|
for the Acquisition
|
|
Adjusted for the Offering
|
|
|
|
|
of the Acquired
|
|
(Including the conveyance
|
|
|
Predecessor
|
|
Underlying Properties
|
|
of the Net Profits Interest)
|
|
|
Year Ended
|
|
Year Ended
|
|
Year Ended
|
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
|
2010
|
|
2010
|
|
2010
|
|
|
(In thousands)
|
|
|
|
|
(Unaudited)
|
|
(Unaudited)
|
|
Revenue
|
|
$
|
38,635
|
|
|
$
|
62,750
|
|
|
$
|
21,998
|
|
Net earnings
|
|
$
|
20,911
|
|
|
$
|
30,624
|
|
|
$
|
14,020
|
|
Total assets (at year end)
|
|
$
|
109,038
|
|
|
$
|
202,171
|
|
|
$
|
96,358
|
|
Long-term liabilities, excluding current maturities (at year end)
|
|
$
|
26,241
|
|
|
$
|
27,805
|
|
|
$
|
99,392
|
|
Partners capital/common control owners equity
(deficit)
|
|
$
|
70,936
|
|
|
$
|
159,559
|
|
|
$
|
(26,746
|
)
|
SUMMARY
PROJECTED CASH DISTRIBUTIONS
The following table presents a calculation of projected cash
distributions to holders of trust units who own trust units as
of the record date for the distribution for the second quarter
of 2011 and continue to own those trust units through the record
date for the cash distribution payable
17
with respect to oil and natural gas production for the last
quarter of 2011. The cash distribution projections for the year
ending December 31, 2011 were prepared by VOC Sponsor based
on the hypothetical assumptions that are described below and in
Projected cash distributions Significant
assumptions used to prepare the projected cash
distributions. Production attributable to the Underlying
Properties for the twelve months ending December 31, 2011
is estimated to be 878.4 MBoe. However, due to the timing
of the payment of production proceeds to the trust, the
production and costs attributable to the distributions for the
twelve months ending December 31, 2011 will be for the
eleven months ending November 30, 2011, which is estimated
to be 800.9 MBoe. As a result, projected cash distributions
for the year ending December 31, 2011 will only include
proceeds attributable to production and costs for the eleven
months ending November 30, 2011. Payments to trust
unitholders will generally be made 45 days following each
calendar quarter. Generally, the trust will make payments to the
trust that will include cash from production from the first two
months of the quarter just ended as well as the last month of
the immediately preceding quarter. For the year ending
December 31, 2011, the trust will not make its first
payment to the unitholders pursuant to the Net Profits Interest
until on or about August 15, 2011, which payment will cover
the net proceeds attributable to the Net Profits Interest for
the first five months of 2011, less any general and
administrative expenses and cash reserves of the trust.
VOC Sponsor does not as a matter of course make public
projections as to future sales, earnings or other results.
However, the management of VOC Sponsor has prepared the
projected financial information set forth below to present the
projected cash distributions to the holders of the trust units
based on the estimates and hypothetical assumptions described
below. The accompanying projected financial information was not
prepared with a view toward complying with the published
guidelines of the SEC or guidelines established by the American
Institute of Certified Public Accountants with respect to
projected financial information.
Neither VOC Sponsors independent auditors nor any other
independent accountants have compiled, examined or performed any
procedures with respect to the projected financial information
contained herein, nor have they expressed any opinion or any
other form of assurance on such information or its
achievability, and assume no responsibility for, and disclaim
any association with, the projected financial information.
The projections and the estimates and hypothetical assumptions
on which they are based are subject to significant
uncertainties, many of which are beyond the control of VOC
Sponsor or the trust. Actual cash distributions to trust
unitholders, therefore, could vary significantly based upon
events or conditions occurring that are different from the
events or conditions assumed to occur for purposes of these
projections. Cash distributions to trust unitholders will be
particularly sensitive to fluctuations in oil and natural gas
prices. See Risk factors Prices of oil and
natural gas fluctuate due to a number of factors that are beyond
the control of the trust and VOC Sponsor, and lower prices could
reduce proceeds to the trust and cash distributions to
unitholders.
18
|
|
|
|
|
|
|
Projection for Twelve Months
|
|
Projected Cash Distributions
|
|
Ending December 31, 2011 (1)
|
|
|
|
(Dollars in thousands, except
|
|
|
|
per Bbl, Mcf, MMBtu and
|
|
|
|
per unit
|
|
|
|
amounts)
|
|
|
Underlying Properties sales volumes:
|
|
|
|
|
Oil (MBbls)
|
|
|
716.5
|
|
Natural gas (MMcf)
|
|
|
506.3
|
|
|
|
|
|
|
Total sales (MBoe)
|
|
|
800.9
|
|
|
|
|
|
|
NYMEX futures price (2):
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
102.07
|
|
Natural gas (per MMBtu)
|
|
$
|
4.07
|
|
Assumed realized sales price (3):
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
96.42
|
|
Natural gas (per Mcf)
|
|
$
|
4.84
|
|
Calculation of net proceeds:
|
|
|
|
|
Gross proceeds:
|
|
|
|
|
Oil sales
|
|
$
|
69,092
|
|
Natural gas sales
|
|
|
2,452
|
|
|
|
|
|
|
Total
|
|
$
|
71,544
|
|
|
|
|
|
|
Costs:
|
|
|
|
|
Production and development costs:
|
|
|
|
|
Lease operating expenses
|
|
$
|
11,239
|
|
Production and property taxes
|
|
|
4,409
|
|
Development expenses
|
|
|
8,171
|
|
|
|
|
|
|
Total
|
|
$
|
23,819
|
|
|
|
|
|
|
Settlement of hedge contracts (payment received) (4)
|
|
$
|
1,562
|
|
|
|
|
|
|
Net proceeds
|
|
$
|
46,163
|
|
|
|
|
|
|
Percentage allocable to Net Profits Interest
|
|
|
80
|
%
|
Net proceeds to trust from Net Profits Interest
|
|
$
|
36,930
|
|
|
|
|
|
|
Trust general and administrative expenses (5)
|
|
|
900
|
|
|
|
|
|
|
Cash reserve
|
|
|
1,000
|
|
Cash available for distribution by the trust
|
|
$
|
35,030
|
|
|
|
|
|
|
Cash distribution per trust unit
|
|
$
|
2.12
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Only includes proceeds attributable
from production from January 1, 2011 through
November 30, 2011 as the trust will not receive a cash
payment for December 2010 in January 2011, and the payment for
December 2011 production will be received in 2012.
|
|
|
|
(2)
|
|
The assumed oil and natural gas
prices utilized for purposes of preparing the projections are
based on spot prices for January, February and March 2011 and
NYMEX futures pricing for April through November 2011 as
reported on March 10, 2011. For a description of the effect
of lower NYMEX prices on projected cash distributions, please
read Projected cash distributions Projected cash
distributions for the year ending December 31, 2011
Sensitivity of projected cash distributions to oil and natural
gas production and prices.
|
|
|
|
(3)
|
|
Sales price net of forecasted
gravity, quality, transportation, and marketing costs. For more
information about the estimates and hypothetical assumptions
made in preparing the table above, see Projected cash
distributions
|
19
|
|
|
|
|
Projected cash distributions
Projected cash distributions for the twelve months ending
December 31, 2011 Significant assumptions used to
prepare the projected cash distributions.
|
|
(4)
|
|
Costs will be reduced by hedge
payments received by VOC Sponsor under the hedge contracts. If
the hedge payments received by VOC Sponsor under the hedge
contracts exceed costs during a quarterly period, the ability to
use such excess amounts to offset costs will be deferred, with
interest accruing on such amounts at the prevailing money market
rate, until the next quarterly period when the current and
deferred hedge payments are less than such costs.
|
|
(5)
|
|
Total general and administrative
expenses of the trust on an annualized basis for 2011 are
expected to be $900,000, which includes an annual administrative
fee to VOC Sponsor in the amount of $75,000 in 2011, which fee
will increase by 4% annually beginning in January 2012, the
annual fee to the trustees, accounting fees, engineering fees,
printing costs and other expenses properly chargeable to the
trust.
|
20
THE
OFFERING
|
|
|
Trust units offered by VOC Sponsor |
|
10,785,000 trust units, or 12,402,750 trust units if
the underwriters exercise their option to purchase additional
trust units in full |
|
Trust units owned by VOC Partners, LLC after the offering |
|
5,755,000 trust units, or 4,137,250 trust units if the
underwriters exercise their option to purchase additional trust
units in full |
|
Trust units outstanding after the offering |
|
16,540,000 trust units |
|
|
|
Use of proceeds |
|
VOC Sponsor is offering all of the trust units to be sold in
this offering including, the trust units to be sold upon any
exercise of the underwriters over-allotment option. The
estimated net proceeds of this offering to be received by VOC
Sponsor will be approximately $198.3 million, after
deducting underwriting discounts and commissions, structuring
fees and expenses, and $228.4 million if the underwriters
exercise their option to purchase additional trust units in
full. VOC Sponsor intends to use the net proceeds from this
offering, including any proceeds from the exercise of the
underwriters option to purchase additional trust units and
the sale of the trust units to VOC Partners, LLC to repay
approximately $24.0 million of outstanding borrowings under
its credit facility, to repurchase certain outstanding equity
interests in VOC Sponsor for approximately $63.4 million
and to make cash distributions to its remaining limited
partners. See Use of proceeds. |
|
|
|
Proposed NYSE symbol |
|
VOC |
|
Quarterly cash distributions |
|
It is expected that quarterly cash distributions during the term
of the trust, other than the first quarterly cash distribution,
will be made by the trustee on or about the 45th day following
the end of each quarter to the trust unitholders of record on
the 30th day following the end of each quarter (or the next
succeeding business day). The first distribution from the trust
to the trust unitholders will be made on or about
August 15, 2011 to trust unitholders owning trust units on
or about August 1, 2011. The trusts first quarterly
distribution will consist of an amount in cash paid by VOC
Sponsor equal to the amount that would have been payable to the
trust had the Net Profits Interest been in effect during the
period from January 1, 2011 through June 30, 2011,
less any general and administrative expenses and reserves of the
trust. |
|
|
|
Actual cash distributions to the trust unitholders will
fluctuate quarterly based upon the quantity of oil and |
21
|
|
|
|
|
natural gas produced from the Underlying Properties, the prices
received for oil and natural gas production and other factors.
Because payments to the trust will be generated by depleting
assets and the trust has a finite life with the production from
the Underlying Properties diminishing over time, a portion of
each distribution will represent, in effect, a return of your
original investment. Oil and natural gas production from proved
reserves attributable to the Underlying Properties is expected
to decline over the term of the trust. See Risk
factors. |
|
Termination of the trust |
|
The Net Profits Interest will terminate on the later to occur of
(1) December 31, 2030, or (2) the time from and
after January 1, 2011 when 10.6 MMBoe have been
produced from the Underlying Properties and sold (which amount
is the equivalent of 8.5 MMBoe in respect of the
trusts right to receive 80% of the net proceeds from the
Underlying Properties pursuant to the Net Profits Interest), and
the trust will promptly wind up its affairs and terminate
thereafter. |
|
Summary of income tax consequences |
|
Trust unitholders will be taxed directly on the income from
assets of the trust. The Net Profits Interest should be treated
as a debt instrument for federal income tax purposes, and a
trust unitholder in that event will be required to include in
such trust unitholders income its share of the interest
income on such debt instrument as it accrues in accordance with
the rules applicable to contingent payment debt instruments
contained in the Internal Revenue Code of 1986, as amended, and
the corresponding regulations. If the Net Profits Interest is
not treated as a debt instrument, then a trust unitholder should
be allowed to recoup its basis in the Net Profits Interest on a
schedule that is in proportion to production attributable to the
Net Profits Interest and that may be more favorable to a trust
unitholder than the schedule on which basis will be recovered if
the Net Profits Interest is treated as a debt instrument for
federal income tax purposes. See Federal income tax
consequences. |
22
RISK
FACTORS
Prices of oil and natural gas fluctuate, and lower prices
could reduce proceeds to the trust and cash distributions to
unitholders.
The trusts reserves and quarterly cash distributions are
highly dependent upon the prices realized from the sale of oil
and natural gas. Prices of oil and natural gas can fluctuate
widely on a
quarter-to-quarter
basis in response to a variety of factors that are beyond the
control of the trust and VOC Sponsor. These factors include,
among others:
|
|
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|
|
regional, domestic and foreign supply and perceptions of supply
of oil and natural gas;
|
|
|
|
the level of demand and perceptions of demand for oil and
natural gas;
|
|
|
|
political conditions or hostilities in oil and natural gas
producing regions, such as the recent geopolitical turmoil in
North Africa and the Middle East;
|
|
|
|
anticipated future prices of oil and natural gas and other
commodities;
|
|
|
|
weather conditions and seasonal trends;
|
|
|
|
technological advances affecting energy consumption and energy
supply;
|
|
|
|
U.S. and worldwide economic conditions;
|
|
|
|
the price and availability of alternative fuels;
|
|
|
|
the proximity, capacity, cost and availability of gathering and
transportation facilities;
|
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|
|
the volatility and uncertainty of regional pricing differentials;
|
|
|
|
governmental regulations and taxation;
|
|
|
|
energy conservation and environmental measures; and
|
|
|
|
acts of force majeure.
|
Crude oil prices declined from record high levels in early July
2008 of over $140 per Bbl to below $45 per Bbl in February 2009
before rebounding to over $110 per Bbl in April 2011.
Natural gas prices declined from over $13 per MMBtu in mid-2008
to approximately $2.40 per MMBtu in August 2009 to
approximately $4 per MMBtu in April 2011.
Lower prices of oil and natural gas will reduce proceeds to
which the trust is entitled and may ultimately reduce the amount
of oil and natural gas that is economic to produce from the
Underlying Properties. As a result, the operator of any of the
Underlying Properties could determine during periods of low
commodity prices to shut in or curtail production from wells on
the Underlying Properties. In addition, the operator of the
Underlying Properties could determine during periods of low
commodity prices to plug and abandon marginal wells that
otherwise may have been allowed to continue to produce for a
longer period under conditions of higher prices. Specifically,
VOC Sponsor may abandon any well or property if it reasonably
believes that the well or property can no longer produce oil or
natural gas in commercially paying quantities. This could result
in termination of the Net Profits Interest relating to the
abandoned well or property. In making such decisions, VOC
Sponsor and any transferee will be required under the applicable
23
conveyance to operate, or to use commercially reasonable efforts
to cause the operators of the Underlying Properties to operate,
these properties as would a reasonably prudent operator, acting
with respect to its own properties (without regard to the
existence of the Net Profits Interest). Because substantially
all the Underlying Properties are located in mature fields,
decreases in commodity prices could have a more significant
effect on the economic viability of these properties as compared
to more recently discovered properties. The commodity price
sensitivity of these mature wells is due to a variety of factors
that vary from
well-to-well,
including the additional costs associated with water handling
and disposal, chemicals, surface equipment maintenance, downhole
casing repairs and reservoir pressure maintenance activities
that are necessary to maintain production. As a result, the
volatility of commodity prices may cause the amount of future
cash distributions to trust unitholders to fluctuate, and a
substantial decline in the price of oil or natural gas will
reduce the amount of cash available for distribution to the
trust unitholders. The volatility of commodity prices also
reduces the accuracy of estimates of future cash distributions
to trust unitholders.
For the years 2011, 2012 and 2013, VOC Sponsor has entered into
swap contracts, which we refer to as the hedge
contracts, at weighted average prices ranging from $94.90
to $100.87 per barrel of oil that hedge approximately 66% of
expected oil production for such years from the proved developed
producing reserves attributable to the Underlying Properties in
the summary reserve reports. The effect of these hedging
transactions may limit the trusts ability to realize cash
flow from crude oil price increases on the portion of the
production attributable to the Net Profits Interest that is
hedged during such period. The Net Profits Interest will bear
its share of the hedge payments regardless of whether the
corresponding quantities of oil are produced or sold.
Furthermore, VOC Sponsor has not entered into any hedge
contracts relating to oil and natural gas volumes expected to be
produced after December 31, 2013, and the terms of the
conveyance of the Net Profits Interests will prohibit VOC
Sponsor from entering into new hedging arrangements following
the completion of this offering. As a result, the amounts of the
cash distributions may be subject to a greater fluctuation after
December 31, 2013 because of changes in crude oil prices.
In the event that any of the counterparties to the hedge
contracts default on their obligations to make payments to VOC
Sponsor under the hedge contracts, the cash distributions to the
trust unitholders would likely be materially reduced. For a
discussion of the hedge contracts, see The Underlying
Properties Hedge contracts.
An increase in the differential between the price realized
by VOC Sponsor for oil or natural gas produced from the
Underlying Properties and the NYMEX or other benchmark price of
oil or natural gas could reduce the proceeds to the trust and
therefore the cash distributions by the trust and the value of
trust units.
The prices received for VOC Sponsors oil and natural gas
production usually fall below the relevant benchmark prices,
such as NYMEX, that are used for calculating hedge positions.
The difference between the price received and the benchmark
price is called a basis differential. The differential may vary
significantly due to market conditions, the quality and location
of production and other factors. VOC Sponsor cannot accurately
predict natural gas or crude oil differentials. Increases in the
differential between the realized price of oil and natural gas
and the benchmark price for oil and natural gas could reduce the
proceeds to the trust and therefore the cash distributions by
the trust and the value of the trust units.
Estimates of future cash distributions to unitholders are
based on assumptions that are inherently subjective.
The projected cash distributions to trust unitholders in 2011
contained elsewhere in this prospectus are based on VOC
Sponsors calculations, and VOC Sponsor has not received an
opinion or report on such calculations from any independent
accountants. Such calculations are
24
based on assumptions about drilling, production, crude oil and
natural gas prices, hedging activities, development
expenditures, expenses, and other matters that are inherently
uncertain and are subject to significant business, economic,
financial, legal, regulatory and competitive risks and
uncertainties that could cause actual results to differ
materially from those estimated. In particular, these estimates
have assumed that crude oil and natural gas production is sold
in 2011 at average prices of $102.07 per Bbl in the case of
crude oil and $4.07 per MMBtu in the case of natural gas.
However, actual sales prices may be significantly lower. Recent
geopolitical turmoil in North Africa and the Middle East may
have contributed to recent increases in crude oil sales prices.
Additionally, these estimates assume the Underlying Properties
will achieve production volumes set forth in the reserve
reports; however, actual production volumes may be significantly
lower. If prices or production are lower than expected, the
amount of cash available for distribution to trust unitholders
would be reduced.
Production income is includable in the computation of net
profits only after the cash is received from purchasers by
VOC Sponsor, which typically occurs approximately
30 days after accrual. Because the trust is only entitled
to a net profits interest on production after January 1,
2011, it will not receive a cash payment for December 2010
production in January 2011 so in effect trust unitholders will
receive cash distributions attributable to only 11 months
in 2011.
Actual reserves and future production may be less than
current estimates, which could reduce cash distributions by the
trust and the value of the trust units.
The value of the trust units and the amount of future cash
distributions to the trust unitholders will depend upon, among
other things, the accuracy of the reserves and future production
estimated to be attributable to the trusts interest in the
Underlying Properties. See The Underlying
Properties Reserve reports for a discussion of
the method of allocating proved reserves to the Underlying
Properties and the Net Profits Interest. It is not possible to
measure underground accumulations of oil and natural gas in an
exact way, and estimating reserves is inherently uncertain.
Ultimately, actual production and revenues for the Underlying
Properties could vary negatively and in material amounts from
estimates. Furthermore, development expenditures and production
costs relating to the Underlying Properties could be higher than
current estimates. Petroleum engineers are required to make
subjective estimates of underground accumulations of oil and
natural gas based on factors and assumptions that include:
|
|
|
|
|
historical production from the area compared with production
rates from other producing areas;
|
|
|
|
oil and natural gas prices, production levels, Btu content,
production expenses, transportation costs, severance and excise
taxes and development expenditures; and
|
|
|
|
the effect of expected governmental regulation.
|
Changes in these assumptions and amounts of actual production
and development costs could materially decrease reserve
estimates.
The processes of drilling and completing wells are high
risk activities.
The processes of drilling and completing wells are subject to
numerous risks beyond the trusts and VOC Sponsors
control, including risks that could delay VOC Sponsors
current drilling schedule and the risk that drilling will not
result in commercially viable oil production. VOC Sponsor is not
obligated to undertake any development activities, so any
drilling and completion activities will be subject to the
reasonable discretion of VOC Sponsor. Further, VOC
Sponsors future business, financial condition, results of
operations, liquidity or ability to finance
25
its share of planned development expenditures could be
materially and adversely affected by any factor that may
curtail, delay or cancel drilling, including the following:
|
|
|
|
|
delays imposed by or resulting from compliance with regulatory
requirements, including permitting;
|
|
|
|
unusual or unexpected geological formations;
|
|
|
|
shortages of or delays in obtaining equipment and qualified
personnel;
|
|
|
|
equipment malfunctions, failures or accidents;
|
|
|
|
unexpected operational events and drilling conditions;
|
|
|
|
reductions in oil or natural gas prices;
|
|
|
|
market limitations for oil or natural gas;
|
|
|
|
pipe or cement failures;
|
|
|
|
casing collapses;
|
|
|
|
lost or damaged drilling and service tools;
|
|
|
|
loss of drilling fluid circulation;
|
|
|
|
uncontrollable flows of oil and natural gas;
|
|
|
|
fires and natural disasters;
|
|
|
|
environmental hazards, such as oil and natural gas leaks,
pipeline ruptures and discharges of toxic gases;
|
|
|
|
adverse weather conditions; and
|
|
|
|
oil or natural gas property title problems.
|
In the event that drilling of development wells is delayed or
cancelled, or development wells have lower than anticipated
production, due to one or more of the factors above or for any
other reason, estimated future distributions to unitholders may
be reduced.
Risks associated with the production, gathering,
transportation and sale of oil and natural gas could adversely
affect cash distributions by the trust.
The amount of cash to be received by the trust from VOC Sponsor
with respect to the Net Profits Interest, the value of the trust
units and the amount of cash distributions to the trust
unitholders will depend upon, among other things, oil and
natural gas production and prices and the costs incurred by VOC
Sponsor to develop and produce oil and natural gas reserves
attributable to the Underlying Properties. Drilling, production
or transportation accidents as well as adverse weather
conditions that temporarily or permanently halt the production
and sale of oil or natural gas at any of the Underlying
Properties will reduce trust distributions by reducing the
amount of net proceeds received by the trust and available for
distribution. For example, accidents may occur that result in
personal injuries, property damage, damage to productive
26
formations or equipment and environmental damages. To the extent
VOC Sponsor is not able to recover from insurance any costs
incurred by VOC Sponsor in connection with any such accidents,
the net proceeds available for distribution to the trust may be
reduced or delayed. In addition, curtailments or damage to
pipelines used by VOC Sponsor to transport oil and natural gas
production to markets for sale could reduce the amount of net
proceeds received by the trust and available for distribution.
Any such curtailment or damage to the gathering systems used by
VOC Sponsor could also require VOC Sponsor to find alternative
means to transport the oil and natural gas production from the
Underlying Properties, which could require VOC Sponsor to incur
additional costs that will have the effect of reducing net
proceeds received by the trust and available for distribution.
VOC Sponsor does not have any long term contracts related
to the sale of production of oil and natural gas from the
Underlying Properties and may be unable to find
purchasers.
VOC Sponsor does not have any firm commitment contracts for the
sale of any production nor has it received security or other
guaranty of payment for the production it sells. Therefore,
there can be no assurance that VOC Sponsor will be able to find
buyers for its production, that buyers will pay the purchase
price therefor or that the price at which the production is sold
will be current market price for such hydrocarbons at the time
of delivery. During the year ended December 31, 2010, VOC
Sponsor sold approximately 32% of the oil produced from the
Underlying Properties to MV Purchasing LLC, an affiliate of VOC
Sponsor. Any nonpayment by a purchaser of production, including
MV Purchasing LLC, or inability by VOC Sponsor to sell any
production, could reduce cash available for distribution to
trust unitholders.
Neither the trust nor the trusts unitholders will
have the ability to influence VOC Sponsor or control the
operations or development of the Underlying Properties.
Trust unitholders have no voting rights with respect to VOC
Sponsor and therefore will have no managerial, contractual or
other ability to influence VOC Sponsors activities or the
operations of the Underlying Properties. Oil and natural gas
properties are typically managed pursuant to an operating
agreement among the working interest owners of oil and natural
gas properties. The VOC Operators operate, or operate on a
contract basis, substantially all of the properties comprising
the Underlying Properties. The typical operating agreement
contains procedures whereby the owners of the working interests
in the property designate one of the interest owners to be the
operator of the property. Under these arrangements, the operator
is typically responsible for making all decisions relating to
drilling activities, sale of production, compliance with
regulatory requirements and other matters that affect the
property.
Shortages or increases in costs of equipment, services and
qualified personnel could result in a reduction in the amount of
cash available for distribution to the trust unitholders.
The demand for qualified and experienced personnel to conduct
field operations, geologists, geophysicists, engineers and other
professionals in the oil and natural gas industry can fluctuate
significantly, often in correlation with oil and natural gas
prices, causing periodic shortages. Historically, there have
been shortages of drilling rigs and other equipment as demand
for rigs and equipment has increased along with the number of
wells being drilled. These factors also cause significant
increases in costs for equipment, services and personnel. Higher
oil and natural gas prices generally stimulate demand and result
in increased prices for drilling rigs, crews and associated
supplies, equipment and services. Shortages of field personnel
and equipment or price increases could significantly decrease
the amount of cash received by the trust and available for
distribution to the trust unitholders or restrict the ability of
VOC Sponsor to drill the development wells and conduct the
operations which it currently has planned for the Underlying
Properties.
27
The trust units may lose value as a result of title
deficiencies with respect to the Underlying Properties.
VOC Sponsor acquired the Underlying Properties over the past
30 years. The existence of a material title deficiency with
respect to the Underlying Properties could reduce the value of a
property or render it worthless, thus adversely affecting the
Net Profits Interest and distributions to trust unitholders. VOC
Sponsor does not obtain title insurance covering mineral
leaseholds, and VOC Sponsors failure to cure any title
defects may cause VOC Sponsor to lose its rights to production
from the Underlying Properties. In the event of any such
material title problem, proceeds available for distribution to
trust unitholders and the value of the trust units may be
reduced.
VOC Sponsor may transfer all or a portion of the
Underlying Properties at any time without trust unitholder
consent, subject to specified limitations.
VOC Sponsor may at any time transfer all or part of the
Underlying Properties, subject to and burdened by the Net
Profits Interest, and may abandon individual wells or properties
that it reasonably believes would no longer produce oil or
natural gas in commercially paying quantities. For the years
ended December 31, 2008, 2009 and 2010, VOC Sponsor plugged
and abandoned six, 15 and 27 wells, respectively, located
on leases on the Underlying Properties. Trust unitholders will
not be entitled to vote on any transfer of the Underlying
Properties, and the trust will not receive any proceeds from any
such transfer, except in certain limited circumstances when the
Net Profits Interest is released in connection with such
transfer, in which case the trust will receive an amount equal
to the fair market value (net of sales costs) of the Net Profits
Interest released. See The Underlying
Properties Sale and abandonment of Underlying
Properties. Following any sale or transfer of any of the
Underlying Properties, if the Net Profits Interest is not
released in connection with such sale or transfer, the Net
Profits Interest will continue to burden the transferred
property and net proceeds attributable to such property will be
calculated as part of the computation of net proceeds described
in this prospectus. VOC Sponsor may delegate to the transferee
responsibility for all of VOC Sponsors obligations
relating to the Net Profits Interest on the portion of the
Underlying Properties transferred.
In addition, VOC Sponsor may, without the consent of the trust
unitholders, require the trust to release the Net Profits
Interest associated with any lease that accounts for less than
or equal to 0.25% of the total production from the Underlying
Properties in the prior 12 months and provided that the Net
Profits Interest covered by such releases cannot exceed, during
any 12-month
period, an aggregate fair market value to the trust of $500,000.
These releases will be made only in connection with a sale by
VOC Sponsor of the relevant Underlying Properties and are
conditioned upon the trusts receiving an amount equal to
the fair market value to the trust of such Net Profits Interest.
Any net sales proceeds paid to the trust will be distributable
to trust unitholders for the quarter in which they are received.
VOC Sponsor has not identified for sale any of the Underlying
Properties.
The reserves attributable to the Underlying Properties are
depleting assets and production from those properties will
diminish over time.
The proceeds payable to the trust attributable to the Net
Profits Interests are derived from the sale of production of oil
and natural gas from the Underlying Properties. The reserves
attributable to the Underlying Properties are depleting assets,
which means that the reserves and the quantity of oil and
natural gas produced from the Underlying Properties will decline
over time. Furthermore, over approximately 87% of the estimated
oil recovery attributable to the Underlying Properties has
already been extracted from the producing wells located on the
Underlying Properties. Based on the estimated production volumes
in the reserve reports, the oil and natural gas production from
proved reserves attributable to the Underlying Properties is
projected to
28
decline at an average rate of approximately 6.2% per year over
the next 20 years, assuming the level of development
drilling and development expenditures on the Underlying
Properties disclosed elsewhere in this prospectus through 2014
and none thereafter. Actual decline rates may vary from this
projected decline rate. In the event expected future development
is delayed, reduced or cancelled, the average rate of decline
will likely exceed 6.2% per year.
The trust agreement will provide that the trusts
activities will be limited to owning the Net Profits Interest
and any activity reasonably related to such ownership, including
activities required or permitted by the terms of the conveyance
related to the Net Profits Interest. As a result, the trust will
not be permitted to acquire other oil and natural gas properties
or net profits interests to replace the depleting assets and
production attributable to the Net Profits Interest.
Because the net proceeds payable to the trust are derived from
the sale of depleting assets, the portion of the distributions
to unitholders attributable to depletion may be considered to
have the effect of a return of capital as opposed to a return on
investment. Eventually, the Underlying Properties burdened by
the Net Profits Interest may cease to produce in commercially
paying quantities and the trust may, therefore, cease to receive
any distributions of net proceeds therefrom.
The amount of cash available for distribution by the trust
will be reduced by the amount of any costs and expenses related
to the Underlying Properties and other costs and expenses
incurred by the trust.
The Net Profits Interest will bear its share of all costs and
expenses related to the Underlying Properties, such as lease
operating expenses, production and property taxes, development
expenses and hedge expenses, which will reduce the amount of
cash received by the trust and thereafter distributable to trust
unitholders. Accordingly, higher costs and expenses related to
the Underlying Properties will directly decrease the amount of
cash received by the trust in respect of its Net Profits
Interest. Please read The Underlying
Properties Selected historical and unaudited pro
forma financial data and operating data of the Underlying
Properties. Historical costs may not be indicative of
future costs. In addition, cash available for distribution by
the trust will be further reduced by the trusts general
and administrative expenses, which are expected to be $900,000
in 2011. For details about these general and administrative
expenses, please see Description of the trust
agreement Fees and expenses.
If production and development costs on the Underlying Properties
together with the other costs exceed gross proceeds of
production from the Underlying Properties, the trust will not
receive net proceeds from those properties until future gross
proceeds from production exceed the total of the excess costs,
plus accrued interest. If the trust does not receive net
proceeds pursuant to the Net Profits Interest, or if such net
proceeds are reduced, the trust will not be able to distribute
cash to the trust unitholders, or such cash distributions will
be reduced, respectively. Development activities may not
generate sufficient additional revenue to repay the costs.
The trustee may, under certain circumstances, sell the Net
Profits Interest and dissolve the trust prior to the expected
termination of the trust. As a result, trust unitholders may not
recover their investment.
The trustee must sell the Net Profits Interest if the holders of
a majority of the trust units approve the sale or vote to
dissolve the trust. The trustee must also sell the Net Profits
Interest if the annual gross proceeds from the Underlying
Properties attributable to the Net Profits Interest are less
than $1.0 million for each of any two consecutive years.
The sale of the Net Profits
29
Interest will result in the dissolution of the trust. The net
proceeds of any such sale will be distributed to the trust
unitholders.
VOC Partners, LLC may sell trust units in the public or
private markets, and such sales could have an adverse impact on
the trading price of the trust units.
After the closing of the offering, VOC Partners, LLC will hold
an aggregate of 5,755,000 trust units, assuming no exercise
of the underwriters over-allotment option. VOC Partners,
LLC has agreed not to sell any trust units for a period of
180 days after the date of this prospectus without the
consent of Raymond James & Associates, Inc. See
Underwriting. After such period, VOC Partners, LLC
may sell trust units in the public or private markets, and any
such sales could have an adverse impact on the price of the
trust units or on any trading market that may develop. The trust
has granted registration rights to VOC Partners, LLC, which, if
exercised, would facilitate sales of common units thereby.
There has been no public market for the trust units and no
independent appraisal of the value of the Net Profits Interest
has been performed.
Among the factors to be considered in determining the number of
trust units to be offered hereby and the initial public offering
price will be current and historical oil and natural gas prices,
current and prospective conditions in the supply and demand for
oil and natural gas, reserve and production quantities estimated
for the Net Profits Interest, the trusts cash
distributions prospects and prevailing market conditions. None
of VOC Sponsor, the trust or the underwriters will obtain any
independent appraisal or other opinion of the value of the Net
Profits Interest, other than the reserve report prepared by
Cawley, Gillespie & Associates, Inc.
The trading price for the trust units may not reflect the
value of the Net Profits Interest held by the trust.
The trading price for publicly traded securities similar to the
trust units tends to be tied to recent and expected levels of
cash distributions. The amounts available for distribution by
the trust will vary in response to numerous factors outside the
control of the trust, including prevailing prices for sales of
oil and natural gas production from the Underlying Properties
and the timing and amount of production and development costs.
Consequently, the trading price for the trust units may not
necessarily be indicative of the value that the trust would
realize if it sold the Net Profits Interest to a third-party
buyer. In addition, such market price may not necessarily
reflect the fact that since the assets of the trust are
depleting assets, a portion of each cash distribution paid on
the trust units should be considered by investors as a return of
capital, with the remainder being considered as a return on
investment. As a result, distributions made to a unitholder over
the life of these depleting assets may not equal or exceed the
purchase price paid by the unitholder.
Conflicts of interest could arise between VOC Sponsor and
its affiliates, on the one hand, and the trust and the trust
unitholders, on the other hand.
As working interest owners in, and operators of substantially
all the wells on, the Underlying Properties, VOC Sponsor and its
affiliates could have interests that conflict with the interests
of the trust and the trust unitholders. For example:
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VOC Sponsors interests may conflict with those of the
trust and the trust unitholders in situations involving the
development, maintenance, operation or abandonment of the
Underlying Properties. VOC Sponsor may also make decisions with
respect to development expenditures that adversely affect the
Underlying Properties. These
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decisions include reducing development expenditures on these
properties, which could cause oil and natural gas production to
decline at a faster rate and thereby result in lower cash
distributions by the trust in the future.
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VOC Sponsor may sell some or all of the Underlying Properties
without taking into consideration the interests of the trust
unitholders. Such sales may not be in the best interests of the
trust unitholders. These purchasers may lack VOC Sponsors
experience or its credit worthiness. VOC Sponsor also has the
right, under certain limited circumstances, to cause the trust
to release all or a portion of the Net Profits Interest in
connection with a sale of a portion of the Underlying Properties
to which such Net Profits Interest relates. See The
Underlying Properties Sale and abandonment of
Underlying Properties.
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MV Purchasing LLC, an affiliate of VOC Sponsor, is expected to
market
and/or
purchase a substantial portion of the oil produced from the
Underlying Properties, and it is expected to profit from this
arrangement. Provisions in the Net Profits Interest conveyance,
however, require that charges and other terms under contracts
with affiliates of VOC Sponsor be comparable to prices and other
terms prevailing in the area for similar services or sales.
During the year ended December 31, 2010, VOC Sponsor sold
approximately 32% of the oil produced from the Underlying
Properties to MV Purchasing, LLC.
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VOC Partners, LLC has registration rights and can sell its units
without considering the effects such sale may have on trust unit
prices or on the trust itself. Additionally, VOC Partners, LLC
can vote its trust units in its sole discretion without
considering the interests of the other trust unitholders.
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The trust is managed by a trustee who cannot be replaced
except by a majority vote of the unitholders at a special
meeting, which may make it difficult for unitholders to remove
or replace the trustee.
The affairs of the trust will be managed by the trustee. Your
voting rights as a trust unitholder are more limited than those
of stockholders of most public corporations. For example, there
is no requirement for annual meetings of trust unitholders or
for an annual or other periodic re-election of the trustee. The
trust agreement provides that the trustee may only be removed
and replaced by the holders of a majority of the outstanding
trust units, including trust units held by VOC Partners, LLC, at
a special meeting of trust unitholders called by either the
trustee or the holders of not less than 10% of the outstanding
trust units. As a result, it will be difficult for public
unitholders to remove or replace the trustee without the
cooperation of VOC Partners, LLC so long as it holds a
significant percentage of total trust units.
Trust unitholders have limited ability to enforce
provisions of the Net Profits Interest, and VOC Sponsors
liability to the trust is limited.
The trust agreement permits the trustee to sue VOC Sponsor or
any other future owner of the Underlying Properties to enforce
the terms of the conveyance creating the Net Profits Interest.
If the trustee does not take appropriate action to enforce
provisions of the conveyance, trust unitholders recourse
would be limited to bringing a lawsuit against the trustee to
compel the trustee to take specified actions. The trust
agreement expressly limits a trust unitholders ability to
directly sue VOC Sponsor or any other third party other than the
trustee. As a result, trust unitholders will not be able to sue
VOC Sponsor or any future owner of the Underlying Properties to
enforce these rights. Furthermore, the Net Profits Interest
conveyance provides that, except as set forth in the conveyance,
VOC Sponsor will not be liable to the trust for the manner
31
in which it performs its duties in operating the Underlying
Properties as long as it acts without gross negligence or
willful misconduct.
Courts outside of Delaware may not recognize the limited
liability of the trust unitholders provided under Delaware
law.
Under the Delaware Statutory Trust Act, trust unitholders
will be entitled to the same limitation of personal liability
extended to stockholders of corporations under the General
Corporation Law of the state of Delaware. No assurance can be
given, however, that the courts in jurisdictions outside of
Delaware will give effect to such limitation.
The operations of the Underlying Properties are subject to
environmental laws and regulations that may result in
significant costs and liabilities, which could reduce the amount
of cash available for distribution to trust unitholders.
The oil and natural gas exploration and production operations of
VOC Sponsor are subject to stringent and comprehensive federal,
state and local laws and regulations governing the discharge of
materials into the environment or otherwise relating to
environmental protection. These laws and regulations may impose
numerous obligations that apply to VOC Sponsors
operations, including the requirement to obtain a permit before
conducting drilling, waste disposal or other regulated
activities; the restriction of types, quantities and
concentrations of materials that can be released into the
environment; the incurrence of significant development
expenditures to install pollution or safety-related controls at
the operated facilities; the limitation or prohibition of
drilling activities on certain lands lying within wilderness,
wetlands and other protected areas; and the imposition of
substantial liabilities for pollution resulting from operations.
Numerous governmental authorities, such as the
U.S. Environmental Protection Agency (EPA) and
analogous state environmental and oil and gas agencies, have the
power to enforce compliance with these laws and regulations and
the permits issued under them, oftentimes requiring difficult
and costly actions. Failure to comply with these laws and
regulations may result in the assessment of administrative,
civil or criminal penalties; the imposition of investigatory or
remedial obligations; and the issuance of injunctions limiting
or preventing some or all of VOC Sponsors operations.
Furthermore, the inability to comply with environmental laws and
regulations in a cost-effective manner, such as removal and
disposal of produced water and other generated oil and gas
wastes, could impair VOC Sponsors ability to produce oil
and natural gas commercially from the Underlying Properties,
which would reduce proceeds attributable to the Net Profits
Interest.
There is inherent risk of incurring significant environmental
costs and liabilities in the performance of VOC Sponsors
operations as a result of its handling of petroleum hydrocarbons
and wastes, air emissions and wastewater discharges related to
its operations, and historical industry operations and waste
disposal practices. Under certain environmental laws and
regulations, VOC Sponsor could be subject to joint and several
strict liability for the removal or remediation of previously
released materials or property contamination regardless of
whether VOC Sponsor was responsible for the release or
contamination or whether the operations were in compliance with
all applicable laws at the time those actions were taken.
Private parties, including the owners of properties upon which
VOC Sponsors wells are drilled and facilities where VOC
Sponsors petroleum hydrocarbons or wastes are taken for
reclamation or disposal, may also have the right to pursue legal
actions to enforce compliance as well as to seek damages for
non-compliance with environmental laws and regulations or for
personal injury or property damage. In addition, the risk of
accidental spills or releases could expose VOC Sponsor to
significant liabilities that could have a material adverse
effect on its financial condition or results of operations.
Changes in environmental laws and regulations occur frequently,
and any changes that result in more stringent or costly
operational control requirements or waste handling, storage,
32
transport, disposal or cleanup requirements could require VOC
Sponsor to make significant expenditures to attain and maintain
compliance and may otherwise have a material adverse effect on
its results of operations, competitive position or financial
condition. VOC Sponsor may be unable to recover some or any of
these costs from insurance, in which case the amount of cash
received by the trust may be decreased. The Net Profits Interest
held by the trust will bear 80% of all costs and expenses
incurred by VOC Sponsor in regard to environmental costs and
liabilities associated with the Underlying Properties, including
costs and liabilities resulting from conditions that existed
prior to VOC Sponsors acquisition of the Underlying
Properties unless such costs and expenses result from VOC
Sponsors gross negligence or willful misconduct. In
addition, as a result of the increased cost of compliance, VOC
Sponsor may decide to discontinue drilling.
The operations of the Underlying Properties are subject to
complex federal, state, local and other laws and regulations
that could adversely affect the cost, manner or feasibility of
conducting its operations or expose VOC Sponsor to significant
liabilities, which could reduce the amount of cash available for
distribution to trust unitholders.
The production and development operations on the Underlying
Properties are subject to complex and stringent laws and
regulations. In order to conduct its operations in compliance
with these laws and regulations, VOC Sponsor must obtain and
maintain numerous permits, drilling bonds, approvals and
certificates from various federal, state and local governmental
authorities and engage in extensive reporting. VOC Sponsor may
incur substantial costs in order to maintain compliance with
these existing laws and regulations, and the Net Profits
Interest will bear its share of these costs. In addition, VOC
Sponsors costs of compliance may increase if existing laws
and regulations are revised or reinterpreted, or if new laws and
regulations become applicable to VOC Sponsors operations.
Such costs could have a material adverse effect on VOC
Sponsors business, financial condition and results of
operations and reduce the amount of cash received by the trust
in respect of the Net Profits Interest, VOC Sponsor must also
comply with laws and regulations prohibiting fraud and market
manipulations in energy markets. To the extent VOC Sponsor is a
shipper on interstate pipelines, it must comply with the tariffs
of such pipelines and with federal policies related to the use
of interstate capacity, and such compliance costs will be borne
indirectly in part by the trust.
Laws and regulations governing exploration and production may
also affect production levels. VOC Sponsor is required to comply
with federal and state laws and regulations governing
conservation matters, including: provisions related to the
unitization or pooling of oil and natural gas properties; the
establishment of maximum rates of production from wells; the
spacing of wells; the plugging and abandonment of wells; and the
removal of related production equipment. These and other laws
and regulations can limit the amount of oil and natural gas VOC
Sponsor can produce from its wells, limit the number of wells it
can drill, or limit the locations at which it can conduct
drilling operations, which in turn could negatively impact trust
distributions, estimated and actual future net revenues to the
trust and estimates of reserves attributable to the trusts
interests.
New laws or regulations, or changes to existing laws or
regulations, may unfavorably impact VOC Sponsor, could result in
increased operating costs or have a material adverse effect on
VOC Sponsors financial condition and results of operations
and reduce the amount of cash received by the trust. For
example, Congress is currently considering legislation that, if
adopted in its proposed form, would subject companies involved
in oil and natural gas exploration and production activities to,
among other items, additional regulation of and restrictions on
hydraulic fracturing of wells, the elimination of certain
U.S. federal tax incentives and deductions available to oil
and natural gas exploration and production activities, and the
prohibition or additional regulation of private energy commodity
derivative and hedging activities. These and other
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potential regulations could increase the operating costs of the
Underlying Properties, reduce VOC Sponsors liquidity,
delay VOC Sponsors operations or otherwise alter the way
VOC Sponsor conducts its business, any of which could have a
material adverse effect on the Net Profits Interest and the
trusts cash flows.
Climate change laws and regulations restricting emissions
of greenhouse gases could result in increased
operating costs and reduced demand for the oil and natural gas
that VOC Sponsor produces while the physical effects of climate
change could disrupt VOC Sponsors production and cause VOC
Sponsor to incur significant costs in preparing for or
responding to those effects.
The oil and gas industry is a direct source of certain
greenhouse gases (GHG) emissions, namely carbon
dioxide and methane, and future restrictions on such emissions
could impact our future operations. On December 15, 2009,
the EPA published its findings that emissions of carbon dioxide,
methane and other 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. Based on
these findings, the agency has begun adopting and implementing
regulations that restrict emissions of GHGs under existing
provisions of the federal Clean Air Act. During 2010, the EPA
adopted two sets of rules regulating GHG emissions under the
Clean Air Act, one of which requires a reduction in emissions of
GHGs from motor vehicles and the other of which regulates
emissions of GHGs from certain large stationary sources under
the Prevention of Significant Deterioration (PSD)
and Title V permitting programs, effective January 2,
2011. The stationary source rule tailors these
permitting programs to apply to certain stationary sources in a
multi-step process, with the largest sources first subject to
permitting. Facilities required to obtain PSD permits for their
GHG emissions also will be required to reduce those emissions
according to best available control technology
standards for GHGs that will be established by the states or, in
some instances, by the EPA on a
case-by-case
basis. The EPAs rules relating to emissions of GHGs from
large stationary sources of emissions are currently subject to a
number of legal challenges, but the federal courts have thus far
declined to issue any injunctions to prevent EPA from
implementing, or requiring state environmental agencies to
implement, the rules. These EPA rulemakings could affect VOC
Sponsors operations and its ability to obtain air permits
for new or modified facilities. In addition, on
November 30, 2010, the EPA published final regulations
expanding the existing greenhouse gas monitoring and reporting
rule to include onshore and offshore oil and natural gas
production and onshore oil and natural gas processing,
transmission storage and distribution facilities. Reporting of
GHG emissions from such facilities will be required on an annual
basis, with reporting beginning in 2012 for emissions occurring
in 2011.
In addition, the U.S. Congress has from time to time considered
legislation to reduce emissions of GHGs, and almost 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. These reductions would be expected to cause the
cost of allowances to escalate significantly over time. The
adoption of any legislation or regulations that requires
reporting of GHGs or otherwise limits emissions of GHGs from VOC
Sponsors equipment and operations could require VOC
Sponsor to incur costs to monitor and report on GHG emissions or
reduce emissions of GHGs associated with its operations, and
such requirements also could adversely affect demand for the oil
and natural gas produced, all of which could reduce proceeds
attributable to the Net Profits Interest and, as a result, the
trusts cash available for distribution.
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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, they could have an
adverse effect on VOC Sponsors assets and operations and,
consequently, may reduce the proceeds attributable to the Net
Profits Interest and, as a result, the trusts cash
available for distribution.
Federal and state legislative and regulatory initiatives
relating to hydraulic fracturing could result in increased costs
and additional operating restrictions or delays as well as
adversely affect VOC Sponsors services.
Hydraulic fracturing is an important and common practice that is
used to stimulate production of hydrocarbons, particularly
natural gas, from tight formations. The process involves the
injection of water, sand and chemicals under pressure into
formations to fracture the surrounding rock and stimulate
production. The process is typically regulated by state oil and
gas commissions. However, the EPA recently asserted federal
regulatory authority over hydraulic fracturing involving diesel
additives under the Safe Drinking Water Acts Underground
Injection Control Program. While the EPA has yet to take any
action to enforce or implement this newly asserted regulatory
authority, industry groups have filed suit challenging the
EPAs recent decision. At the same time, the EPA has
commenced a study of the potential environmental impacts of
hydraulic fracturing activities, with initial results of the
study anticipated to be available by late 2012, and final
results in 2014. In addition, legislation that was introduced in
the 111th session of Congress has been reintroduced in the 112th
Congress and would provide for federal regulation of hydraulic
fracturing and require both prefracturing and post-fracturing
disclosure of the chemicals used in the fracturing process.
Also, some states have adopted, and other states are considering
adopting, regulations that could restrict or impose additional
requirements relating to hydraulic fracturing in certain
circumstances. For example, on March 1, 2011, a bill was
introduced in the Texas Senate that, if adopted, would require
written disclosure to the Railroad Commission of Texas of
specific information about the fluids, proppants and additives
used in hydraulic fracturing treatment operations, and on
March 11, 2011, a bill was introduced in the Texas House of
Representatives that would require service companies to submit
master lists of base fluids, additives and chemical
constituents to be used in hydraulic fracturing activities in
Texas, subject to certain trade secret protections, to the
Railroad Commission. Such federal or state legislation could
require the disclosure of chemical constituents used in the
fracturing process to state or federal regulatory authorities
who could then make such information publicly available.
Required disclosure without protection for trade secret or
proprietary products could discourage service companies from
using such products and as a result impact the degree to which
some oil and gas wells may be efficiently and economically
completed or brought into production. Disclosure of chemicals
used in the fracturing process could also make it easier for
third parties opposing hydraulic fracturing to initiate legal
proceedings against producers and service providers based on
allegations that specific chemicals used in the fracturing
process could adversely affect groundwater. In addition, if
hydraulic fracturing is regulated at the federal level, VOC
Sponsors fracturing activities could become subject to
additional permit requirements or operational restrictions and
also to associated permitting delays and potential increases in
costs. Further, some state and local governments in the
Marcellus Shale region in Pennsylvania and New York have
considered or imposed temporary moratoria on drilling operations
using hydraulic fracturing until further study of the potential
environmental and human health impacts by EPA or the relative
state agencies are completed, and at least a couple of local
governments in Texas have imposed temporary moratoria on
drilling activities within city limits so that local ordinances
may be reviewed to assess their adequacy to address such
activities. No assurance can be given as to whether or not
similar measures might be considered or implemented in the
jurisdictions in which we operate. If
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new laws or regulations that significantly restrict or otherwise
impact hydraulic fracturing are passed by Congress or adopted in
Texas or Kansas such legal requirements could make it more
difficult or costly for VOC Sponsor to perform hydraulic
fracturing activities and thereby affect the determination of
whether a well is commercially viable. In addition, restrictions
on hydraulic fracturing could reduce the amount of oil and
natural gas that VOC Sponsor is ultimately able to produce in
commercially paying quantities from the Underlying Properties.
The bankruptcy of VOC Sponsor or any of the VOC Operators
could impede the operation of the wells and the development of
the proved undeveloped reserves.
VOC Sponsor is a privately-held limited partnership engaged in
the production and development of oil and natural gas from
properties located in Kansas and Texas. VOC Sponsor intends to
implement a development and workover program, including the
expenditure over the next five years of approximately
$27.1 million to drill additional wells and recomplete and
workover other wells. Without this development and workover
program, the average decline rate over the life of the trust of
the oil and natural gas production from the proved reserves
attributable to the Underlying Properties will likely exceed the
6.2% per year projected in the reserve reports. The VOC
Operators are privately-held limited partnerships or
corporations engaged in the operation of oil and natural gas
wells in Kansas and Texas that were the operators or contract
operators of Underlying Properties having approximately 98% of
the total proved reserves on the Underlying Properties, based on
PV-10 value.
Therefore, the value of the Net Profits Interest and the
trusts ultimate cash available for distribution will be
highly dependent on the financial condition of VOC Sponsor and
the VOC Operators. None of VOC Sponsor or the VOC Operators will
be a reporting company following this offering or will file
periodic reports with the SEC. Therefore, as a trust unitholder,
you will not have access to financial information about VOC
Sponsor or the VOC Operators. Furthermore, none of VOC Sponsor
or the VOC Operators has agreed with the trust to maintain a
certain net worth or to be restricted by other similar covenants
and VOC Sponsor intends to distribute all of the net proceeds of
this offering to its partners instead of retaining all or a
portion for the development of the Underlying Properties.
The ability of VOC Sponsor to develop the Underlying Properties
and the ability of the VOC Operators to operate the wells on the
Underlying Properties depends on the future financial condition
and economic performance and access to capital of VOC Sponsor
and the VOC Operators, which in turn will depend upon the supply
and demand for oil and natural gas, prevailing economic
conditions and financial, business and other factors, many of
which are beyond the control of VOC Sponsor and the VOC
Operators. See Information about VOC Brazos Energy
Partners, L.P. (VOC Sponsor) found on
page VOC-1
for additional information relating to VOC Sponsor, including
information relating to the business of VOC Sponsor, historical
financial statements of VOC Sponsor and other financial
information relating to VOC Sponsor. This prospectus contains no
financial information about the VOC Operators.
In the event of the bankruptcy of VOC Sponsor or a VOC Operator,
the trust would have to seek a new party to perform the
development and workover program or the operations of the wells
operated by such VOC Operator. The trust may not be able to find
a replacement driller or operator, and it may not be able to
enter into a new agreement with such replacement party on
favorable terms within a reasonable period of time. As a result,
such a bankruptcy may result in reduced production from the
reserves and decreased distributions to trust unitholders.
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The trust may be treated as an unsecured creditor with
respect to the Net Profits Interest attributable to properties
in Kansas in the event of the bankruptcy of VOC Sponsor if a
court were to hold that the conveyance and recording of the Net
Profits Interest was not a conveyance of a fully vested real
property interest or an interest in hydrocarbons in place or to
be produced.
VOC Sponsor and the trust believe that the recording in the
appropriate real property records in Kansas of the Net Profits
Interest should constitute the conveyance of a fully vested real
property interest, interests in hydrocarbons in place or to be
produced or a production payment as such is defined under the
United States Bankruptcy Code, but there is no dispositive
Kansas Supreme Court case directly addressing these issues. In a
bankruptcy of VOC Sponsor, creditors of VOC Sponsor would be
able to claim the Net Profits Interest as an asset of the
bankruptcy estate to satisfy obligations to them if the
conveyance of the Net Profits Interest did not constitute the
conveyance of a real property interest or interests in
hydrocarbons in place or to be produced under applicable state
law or a production payment, in which case the trust would be an
unsecured creditor of VOC Sponsor at risk of losing the entire
value of the Net Profit Interests to senior creditors.
Due to lack of geographic diversification of the
Underlying Properties, adverse developments in Kansas or Texas
could adversely impact the results of operations and cash flows
of the Underlying Properties and reduce the amount of cash
available for distributions to trust unitholders.
The operations of the Underlying Properties are focused on the
production and development of oil and natural gas within the
states of Kansas and Texas. As a result, the results of
operations and cash flows of the Underlying Properties depend
upon continuing operations in these areas. Due to the lack of
diversification in geographic location, adverse developments in
exploration and production of oil and natural gas in either of
these areas of operation could have a significantly greater
impact on the results of operations and cash flows of the
Underlying Properties than if the operations were more
diversified.
The receipt of payments by VOC Sponsor based on the hedge
contracts depends upon the financial position of the hedge
contract counterparties. A default by any of the hedge contract
counterparties could reduce the amount of cash available for
distribution to the trust unitholders.
Payments from hedge contract counterparties to VOC Sponsor are
intended to offset costs and thus have the effect of providing
additional cash to the trust during periods of lower crude oil
prices. In the event that any of the counterparties to the hedge
contracts default on their obligations to make payments to VOC
Sponsor under the hedge contracts, the cash distributions to the
trust unitholders could be materially reduced. VOC Sponsor does
not have any security interest from its hedge counterparties
against which it could recover in the event of a default by any
such counterparty.
VOC Sponsors performance of its obligations to the
trust and the financial results of the trust may differ from the
drilling and financial results of MVO.
As disclosed in this prospectus, certain members of the
management of VOC Sponsor previously participated in the
formation and initial public offering of MVO. Given the
differences in assets comprising the underlying properties,
operators of the underlying properties and commodity price
markets, the historical results of operations and performance of
the MVO should not be relied on as an indicator of how this
trust will perform. Please see MV Oil Trust.
37
TAX RISKS
RELATED TO THE TRUSTS TRUST UNITS
The tax treatment of an investment in trust units could be
affected by recent and potential legislative changes, possibly
on a retroactive basis.
The recently enacted Health Care and Education Affordability
Reconciliation Act of 2010 includes a provision that, in taxable
years beginning after December 31, 2012, subjects an
individual having modified adjusted gross income in excess of
$200,000 (or $250,000 for married taxpayers filing joint
returns) to a medicare tax equal generally to 3.8%
of the lesser of such excess or the individuals net
investment income, which appears to include interest income
derived from investments such as the trust units as well as any
net gain from the disposition of trust units. In addition,
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. Moreover, these rates are subject to change by new
legislation at any time.
The trust has not requested a ruling from the IRS
regarding the tax treatment of ownership of the trust units. If
the IRS were to determine (and be sustained in that
determination) that the trust is not a grantor trust
for federal income tax purposes, or that the Net Profits
Interest is not properly treated as a production payment (and
thus would fail to qualify as a debt instrument) for federal
income tax purposes, the trust unitholders may receive different
and potentially less advantageous tax treatment from that
described in this prospectus.
If the trust were not treated as a grantor trust for federal
income tax purposes, the trust should be treated as a
partnership for such purposes. Although the trust would not
become subject to federal income taxation at the entity level as
a result of treatment as a partnership, and items of income,
gain, loss and deduction would flow through to the trust
unitholders, the trusts tax reporting requirements would
be more complex and costly to implement and maintain, and its
distributions to unitholders could be reduced as a result.
If the Net Profits Interest were not treated as a production
payment (and thus would fail to qualify as a debt instrument for
federal income tax purposes) the amount, timing and character of
income, gain, or loss in respect of an investment in the trust
could be affected. See Federal income tax
consequences.
Neither VOC Sponsor nor the trustee has requested a ruling from
the IRS regarding these tax questions, and neither VOC Sponsor
nor the trust can assure you that such a ruling would be granted
if requested or that the IRS will not challenge these positions
on audit.
Trust unitholders should be aware of the possible state tax
implications of owning trust units. See State tax
considerations.
38
FORWARD-LOOKING
STATEMENTS
This prospectus contains forward-looking statements
about VOC Sponsor and the trust that are subject to risks and
uncertainties. All statements other than statements of
historical fact included in this prospectus, including, without
limitation, statements under Prospectus summary and
Risk factors regarding the financial position,
business strategy, production and reserve growth, and other
plans and objectives for the future operations of VOC Sponsor
and the trust are forward-looking statements. Such statements
may be influenced by factors that could cause actual outcomes
and results to differ materially from those projected.
Forward-looking statements are subject to risks and
uncertainties and include statements made in this prospectus
under Projected cash distributions, statements
pertaining to future development activities and costs, and other
statements in this prospectus that are prospective and
constitute forward-looking statements.
When used in this document, the words believes,
expects, anticipates,
intends or similar expressions are intended to
identify such forward-looking statements. The following
important factors, in addition to those discussed elsewhere in
this prospectus, could affect the future results of the energy
industry in general, and VOC Sponsor and the trust in
particular, and could cause actual results to differ materially
from those expressed in such forward-looking statements:
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risks incident to the drilling and operation of oil and natural
gas wells;
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future production and development costs and plans;
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the effect of existing and future laws and regulatory actions;
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the effect of changes in commodity prices, including changes as
a result of political conditions or hostilities in oil and
natural gas producing regions such as the recent geopolitical
turmoil in North Africa and the Middle East;
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the impact of the hedge contracts;
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conditions in the capital markets;
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competition from others in the energy industry;
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uncertainty of estimates of oil and natural gas reserves and
production; and
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inflation.
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You should not place undue reliance on these forward-looking
statements. All forward-looking statements speak only as of the
date of this prospectus. VOC Sponsor does not undertake any
obligation to release publicly any revisions to the
forward-looking statements to reflect events or circumstances
after the date of this prospectus or to reflect the occurrence
of unanticipated events, unless the securities laws require us
to do so.
This prospectus describes other important factors that could
cause actual results to differ materially from expectations of
VOC Sponsor and the trust, including under the heading
Risk factors. All written and oral forward-looking
statements attributable to VOC Sponsor or the trust or persons
acting on behalf of VOC Sponsor or the trust are expressly
qualified in their entirety by such factors.
39
USE OF
PROCEEDS
VOC Sponsor is offering all of the trust units to be sold in
this offering, including the trust units to be sold upon the
exercise of the underwriters over-allotment option. VOC
Sponsor expects to receive net proceeds from the sale of
10,785,000 trust units offered by this prospectus of
approximately $198.3 million, after deducting underwriting
discounts and commissions, structuring fees and offering
expenses, and an additional $30.1 million if the
underwriters exercise their option to purchase additional trust
units in full. Forty-five days following the closing of this
offering, VOC Sponsor will sell any trust units not sold in this
offering to VOC Partners, LLC at the initial public offering
price.
VOC Sponsor intends to use the net proceeds from this offering,
including any proceeds from the exercise of the
underwriters option to purchase additional trust units and
the sale of trust units to VOC Partners, LLC, to repay
approximately $24.0 million of outstanding borrowings under
its credit facility, to repurchase certain outstanding equity
interests in VOC sponsor for approximately $63.4 million
and to make cash distributions to its remaining limited partners.
40
VOC
SPONSOR
VOC Brazos is a privately-held limited partnership engaged in
the production and development of oil and natural gas from
properties located in Texas. VOC Brazos was formed in May 2003.
Pursuant to the KEP Acquisition, concurrent with the close of
this offering, VOC Brazos will acquire KEP, which was formed in
November 2009 to develop and produce oil and natural gas from
properties primarily located in Kansas along with a limited
number of Texas properties. There are no conditions to the
closing of the KEP Acquisition other than the closing of this
offering. Members of KEP acquired interests in the properties
owned by KEP through various acquisitions and drilling
activities that have occurred since 1979.
As of December 31, 2010, VOC Sponsor held interests in
approximately 881 gross (545.7 net) producing wells,
and proved reserves of the Underlying Properties were
approximately 13.7 MMBoe. As of December 31, 2010,
based on
PV-10 value,
the VOC Operators were the operators or contract operators of
approximately 98% of the total proved reserves attributable to
the Underlying Properties with Vess Oil operating, on behalf of
VOC Sponsor, approximately 91% of the total proved reserves and
L.D. Drilling Inc. and Davis Petroleum, Inc. operating
approximately 7% of the total proved reserves. Vess Oil has
operated oil and natural gas properties in Kansas for more than
30 years and, according to statistics furnished by the
Kansas Geological Survey, during 2010, was the second largest
operator of oil properties in Kansas measured by production
during 2010. Vess Oil currently operates over 1,600 oil, natural
gas and service wells located primarily in Kansas, with growing
operations in Texas. As of December 31, 2010, Vess Oil
employed 19 full-time employees, three contract
professionals and 14 contract personnel in its Wichita office
and in five field and satellite offices.
The trust units do not represent interests in, or obligations
of, VOC Sponsor.
41
SUMMARY
HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL,
OPERATING AND RESERVE DATA OF VOC SPONSOR
The summary combined financial data presented below should be
read in conjunction with VOC Sponsor Selected
historical and unaudited pro forma data of VOC Sponsor and
the accompanying financial statements and related notes of VOC
Sponsor included elsewhere in this prospectus. In connection
with the closing of this offering, VOC Brazos will acquire the
membership interests in KEP in exchange for partnership
interests in VOC Brazos, resulting in KEP becoming a
wholly-owned subsidiary of VOC Brazos. As the Common Control
Properties are deemed to be under common control with VOC
Brazos, accounting rules specify that VOC Brazos and the Common
Control Properties be combined from the earliest date they came
under common control. The financial data and operations of such
assets are referred to herein as Predecessor, and
are described in more detail in Information about VOC
Brazos Energy Partners, L.P. (VOC Sponsor)
Managements discussion and analysis of financial condition
and results of operations of VOC Sponsor. Accordingly, in
order to give full effect to the acquisition by VOC Brazos of
KEP, the following table includes pro forma financial and
operating data of Predecessor giving effect to the acquisition
of the Acquired Underlying Properties. Since the historical
assets and operations of Predecessor will only represent a
portion of the assets and operations to be held by VOC Sponsor
at the closing of this offering, the future results of
operations of VOC Sponsor will not be comparable to the
historical results of Predecessor.
The summary combined historical financial data of Predecessor as
of December 31, 2008, 2009 and 2010 and for each of the
years in the three-year period ended December 31, 2010 have
been derived from Predecessors audited financial
statements.
The summary combined financial unaudited pro forma financial
data as of and for the year ended December 31, 2010 set
forth in the following table have been derived from the
unaudited combined pro forma financial statements of Predecessor
included in this prospectus beginning on
page VOC F-24.
The pro forma adjustments have been prepared as if the
acquisition of the Acquired Underlying Properties and, with
respect to pro forma as adjusted information, the conveyance of
the Net Profits Interest and the offer and sale of the trust
units and application of the net proceeds therefrom, had taken
place (i) on December 31, 2010, in the case of the pro
forma balance sheet information as of December 31, 2010,
and (ii) as of January 1, 2010, in the case of the pro
forma statement of earnings information for the year ended
December 31, 2010.
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Predecessor
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Predecessor Pro Forma
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Pro Forma for the
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As Adjusted for the Offering
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Acquisition of the Acquired
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(including the conveyance of
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Underlying Properties
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the Net Profits Interest)
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Predecessor
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Year Ended
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Year Ended
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Year Ended December 31,
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December 31,
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December 31,
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2008
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2009
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2010
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2010
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2010
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(In thousands)
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(Unaudited)
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(Unaudited)
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Revenue
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$
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32,198
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$
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25,750
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$
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38,635
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$
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62,750
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$
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21,998
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Net earnings
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$
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12,839
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$
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10,861
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$
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20,911
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$
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30,624
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$
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14,020
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Total assets (at year end)
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$
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108,830
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$
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101,280
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$
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109,038
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$
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202,171
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$
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96,358
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Long-term liabilities, excluding current maturities (at year end)
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$
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37,018
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$
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28,315
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$
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26,241
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$
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27,805
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$
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99,392
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42
The table below includes selected production and reserve
information for VOC Sponsor for the periods presented.
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Year Ended December 31,
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Historical Results
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2008
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2009
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2010
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Production (MBoe)
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829
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847
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930
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Net proved reserves (MBoe) (at year end)
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10,821
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13,007
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13,700
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Net proved developed reserves (MBoe) (at year end)
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10,046
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11,536
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11,945
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MANAGEMENT
OF VOC SPONSOR
VOC Sponsor does not currently have any executive officers,
directors or employees. Instead, VOC Sponsor is managed by an
executive management team consisting of certain officers and
employees of Vess Oil on behalf of the general partner, Vess
Texas Partners, LLC. None of the members of the executive
management team of Vess Oil who perform management functions for
VOC Sponsor receive any compensation from the trust or from VOC
Sponsor.
Set forth in the table below are the names, ages, and titles at
Vess Oil of the members of the executive management team of Vess
Oil who perform management functions on behalf of Vess Texas
Partners, LLC, VOC Sponsors general partner:
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Name
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Age
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Title
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J. Michael Vess
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59
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President and Chief Executive Officer
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William R. Horigan
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61
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Vice President of Operations
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Brian Gaudreau
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55
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Vice President of Land
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Barry Hill
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35
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Vice President and Chief Financial Officer
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Alan Howarter
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55
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Vice President of Financial Reporting
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Pursuant to the administrative services agreement, VOC Sponsor
is entitled to an annual administrative fee for services
provided to the trust, which fee will total $75,000 in 2011 and
will increase by 4% each year beginning in January 2012. For a
description of certain overhead and related fees payable by VOC
Sponsor to certain of its affiliates in connection with the
operation of the Underlying Properties, please see Certain
relationships and related party transactions.
EXECUTIVE
MANAGEMENT FROM VESS OIL
J. Michael Vess is the President, Chief Executive
Officer and principal owner of Vess Oil. Mr. Vess
co-founded Vess Oil in 1979 and has continuously been
responsible for the coordination and supervision of exploration
and production and the acquisition of its oil and natural gas
reserves. Mr. Vess has continuously served as the President and
Chief Executive Officer of Vess Oil since 1987. Mr. Vess
received a Bachelor of Business Administration degree from
Wichita State University in 1973 and subsequently received his
CPA certificate. Mr. Vess currently serves on the Board of
Directors and Executive Committees for the Kansas Independent
Oil and Gas Association (KIOGA) and is the current
Chairman of the KIOGA Committee on Electricity. In addition, he
is Past Chairman of the KIOGA Tax Committee and a current member
of the Interstate Oil and Gas Compact Commission Outreach
Committee.
William R. Horigan is the Vice President of Operations
for Vess Oil where he is responsible for the engineering,
enhancement and exploitation of its existing properties as well
as the engineering analysis and evaluation of its future reserve
acquisitions. Mr. Horigan has continuously served as the Vice
President of Operations for Vess Oil since August 1998.
Mr. Horigan joined Vess Oil in 1988 as Operations Manager.
Prior to joining Vess Oil, Mr. Horigan
43
served in various petroleum engineering capacities for Amoco
Production Company beginning in 1975. Mr. Horigan later
served as Division Operations Manager for Slawson Oil
Company. Mr. Horigan graduated from the University of
Kansas in 1974 with a Bachelor of Science degree in Chemical
Engineering. Mr. Horigan is a member of the Society of
Petroleum Engineers and has served on the Executive Board for
the Wichita Section. He is also a member of the Producers
Advisory Board of the KU Tertiary Oil Recovery Project and
a member of the Petroleum Technology Transfer Council of the
North Mid-Continent Region.
Brian Gaudreau is the Vice President of Land and
Acquisitions for Vess Oil where he is responsible for land,
contracts and acquisitions. Mr. Gaudreau has continuously
held the position of Vice President of Land and Acquisitions
since he joined Vess Oil in 2002. Prior to joining Vess Oil, he
held the title of Manager, Land and Acquisitions for Stelbar Oil
Corporation, Inc. beginning in 1989. Mr. Gaudreau graduated
from the University of Kansas in 1977 with a Bachelors degree in
Economics. Mr. Gaudreau belongs to the American Association
of Professional Landmen, is a Director and serves on the
Executive Committee of KIOGA, and belongs to the Dallas
Acquisitions, Divestitures, and Mergers Energy Forum.
Barry Hill is the Vice President and Chief Financial
Officer for Vess Oil responsible for planning, directing and
coordinating finance activities. Mr. Hill has continuously
served as the Vice President and Chief Financial Officer for
Vess Oil since he joined Vess Oil in February 2010.
Mr. Hill spent approximately ten years in the Energy
Investment Banking group of Raymond James & Associates,
Inc., completing numerous public equity offerings, advisory
engagements and private securities assignments for a wide
spectrum of energy industry clients, including many exploration
and production companies, until his departure in January 2010.
During the last five years of his employment with Raymond James
& Associates, Inc., Mr. Hill held the positions of
Senior Associate and Vice President. Mr. Hill earned his
A.B. in Economics with honors from Harvard College in 1998 and
an M.B.A. from the Darden Graduate School of Business at the
University of Virginia in 2003.
Alan Howarter is the Vice President of Financial
Reporting for Vess Oil responsible for the financial reporting
aspects of Vess Oil and other related entities.
Mr. Howarter has continuously served as the Vice President
of Financial Reporting for Vess Oil since he joined Vess Oil in
May 2007. Prior to joining Vess Oil, Mr. Howarter was a
Manager at Regier Carr & Monroe, L.L.P. Mr. Howarter
continuously held the position of Manager since the time he
joined Regier Carr & Monroe, L.L.P. in January of 2005
through his departure in May of 2007. Previously,
Mr. Howarter was a Partner and head of the Audit Department
of the Wichita office of Grant Thornton, LLP. Mr. Howarter
received his Bachelor of Business Administration degree in
Accounting from Wichita State University in 1978. He is a
licensed CPA in Kansas. Mr. Howarter is currently a member
of the Accounting Advisory Board of Wichita State University,
the American Institute of Certified Public Accountants, the
Kansas Society of Certified Public Accountants and the Petroleum
Accountants Society of Kansas. He is also a past president and
treasurer of the Petroleum Accountants Society of Kansas.
44
BENEFICIAL
OWNERSHIP OF VOC SPONSOR
The following table sets forth, as of April 5, 2011, the
beneficial ownership of limited partnership interests of VOC
Sponsor that will be outstanding after giving effect to the
consummation of this offering, including the KEP Acquisition,
and the application of the net proceeds, including the
repurchase of certain outstanding equity interests in VOC
Sponsor as described in Use of Proceeds, and
held by:
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each person who will then beneficially own 5% or more of the
outstanding partner interests in VOC Sponsor;
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each member of Vess Oils executive management team, who
perform management functions on behalf of VOC Sponsor; and
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all members of Vess Oils executive management team, who
perform management functions on behalf of VOC Sponsor, as a
group.
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Except as indicated by footnote, the persons named in the table
below have sole voting and investment power with respect to all
partnership interests of VOC Sponsor shown as beneficially owned
by them.
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Percentage of
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Partnership Interests
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Name of Beneficial Owner
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Beneficially Owned
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L. D. Davis (1)
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31.8
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%
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J. Michael Vess (2)
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27.9
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%
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Will Price (3)
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11.8
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%
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C. J. Lett (4)
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10.7
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%
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William R. Horigan (5)
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7.2
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%
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Brian Gaudreau (6)
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2.6
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%
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Barry Hill (7)
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*
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Alan Howarter (8)
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*
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Executive Management as a Group (2)(5)(6)(7)(8)
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38.2
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%
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(1)
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Includes interests indirectly
beneficially owned in VOC Sponsor through several entities,
including through interests in Davis Energy LLC, which entity
beneficially owns a 13.7% interest in VOC Sponsor. The address
of Mr. Davis is 7 SW 26th Ave., Great Bend, Kansas 67530.
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(2)
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Includes 13.6% of
Mr. Vess interests in VOC Sponsor indirectly
beneficially owned through family trusts. Mr. Vess also has
dispositive power over an additional 14.3% of VOC Sponsor. The
address of Mr. Vess is 1700 Waterfront Parkway, Building
500, Wichita, Kansas 67206.
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(3)
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Includes interests indirectly
beneficially owned through several entities. The address of
Mr. Price is 1700 Waterfront Parkway,
Building 500, Wichita, KS 67206.
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(4)
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Includes interests indirectly
beneficially owned through several entities. The address of
Mr. Lett is 9320 E. Central, Wichita, Kansas
67206.
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(5)
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Includes interests indirectly
beneficially owned through several entities. The address of
Mr. Horigan is 1700 Waterfront Parkway, Building 500,
Wichita, Kansas 67206.
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(6)
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Includes interests indirectly
beneficially owned through several entities. The address of
Mr. Gaudreau is 1700 Waterfront Parkway, Building 500,
Wichita, Kansas 67206.
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(7)
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Mr. Hill beneficially owns less
than 1% of VOC Brazos through his beneficial ownership of a 0.5%
membership interest in VOC Acquisition Partners, LLC, an
indirect subsidiary of VOC Sponsor. The address of Mr. Hill is
1700 Waterfront Parkway, Building 500, Wichita, Kansas 67206.
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45
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(8)
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Mr. Howarter beneficially owns
less than 1% of VOC Brazos through his beneficial ownership of
10% of the membership interests in Vess Oil Company, L.L.C., an
indirect subsidiary of VOC Sponsor, and his beneficial ownership
of a 0.5% membership interest in VOC Acquisition Partners, LLC,
an indirect subsidiary of VOC Sponsor. The address of
Mr. Howarter is 1700 Waterfront Parkway, Building 500,
Wichita, Kansas 67206.
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BENEFICIAL
OWNERSHIP OF VOC ENERGY TRUST
The following table sets forth the beneficial ownership of the
trust units of VOC Energy Trust that will be outstanding after
giving effect to the consummation of this offering, assuming no
exercise of the underwriters over-allotment option, and
held, directly or indirectly, by each person who will then
beneficially own 5% or more of the outstanding partner interests
in VOC Energy Trust.
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Class of
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Percentage
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Name of Beneficial
Owner
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Securities
|
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of Ownership (1)
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VOC Partners, LLC (2)
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Trust Units
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|
34.8% (3)
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(1)
|
|
Does not include any trust units
that may be purchased in the directed unit program. Please see
Underwriting Directed Unit Program on
page 120.
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(2)
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|
The parties who beneficially own
VOC Sponsor as set forth in the table above own VOC Partners,
LLC in the same proportion as they own VOC Sponsor. However,
such ownership percentage described in the table above does not
take into account Class B Units of VOC Partners, LLC. Such
Class B Units are issuable to VOC Management Group at the
discretion of VOC Partners, LLC, and these units may equal up to
1.5% of the outstanding units of VOC Partners, LLC. As of
April 13, 2011, VOC Partners, LLC has not issued any
Class B units and has no current plans to do so.
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(3)
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|
VOC Partners, LLC has entered into
an agreement to acquire from VOC Sponsor all trust units not
sold by VOC Sponsor in this offering at the initial offering
price. The closing of such transaction will occur forty-five
days following the closing of this offering.
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46
MV OIL
TRUST
Certain members of VOC Sponsors management team were
involved in the formation and initial public offering of MV Oil
Trust (NYSE: MVO) (MVO), a publicly-traded trust
that is similar to VOC Energy Trust. In connection with the
formation of MVO, the sponsor conveyed an 80% term net profits
interest in oil and natural gas properties in the Mid-Continent
region in Kansas and Colorado to MVO in exchange for trust
units, a portion of which were sold by the sponsor in MVOs
initial public offering in January 2007. The terms of the net
profits interest being conveyed in connection with the formation
of VOC Energy Trust are similar to those of the net profits
interest that was conveyed to MVO.
To offset the natural decline in production of the proved
developed wells, the sponsor planned and executed a development
and workover program. The results of this program have mitigated
the decline, with daily production being approximately 2,859 Boe
at the time of the initial public offering (or approximately
2,287 Boe attributable to MVOs 80% net profits interest)
and 2,621 Boe (or approximately 2,097 Boe attributable to
MVOs 80% net profits interest) for the year ended
December 31, 2010. As a result of differences in pricing,
wells, costs, development schedule, development expenditures and
regulatory environment, among other things, the historical
results of operations and performance of MVO should not be
relied on as an indicator of how the trust will perform.
The final prospectus relating to the initial public offering of
MVO set forth a projection for the twelve months ended
December 31, 2007 that totaled $3.02 per MVO trust unit.
Actual distributions for each of the second, third and fourth
quarters of 2007 and the twelve months ended December 31,
2007 (totaling $2.48 per MVO trust unit for the twelve
months ended December 31, 2007) were below the projected
amounts outlined in such final prospectus. The net proceeds
received by MVO during such periods were impacted by production
curtailment during the first quarterly payment period affecting
the underlying properties as the result of severe winter storms
that impacted western Kansas and eastern Colorado. The snow and
ice associated with these storms disabled electrical power to
the affected underlying properties for an extended period of
time and rendered some properties inaccessible. Significant snow
accumulations, along with ice and subsequent melting, created
difficult working conditions that extended the curtailment
period and increased costs to operate the underlying properties.
As publicly reported, on July 22, 2008, MVOs revenue
intermediary/crude oil purchaser (Eaglwing L.P.) and its parent
(SemGroup, L.P.) filed voluntary petitions for reorganization
under Chapter 11 of the United States Bankruptcy Code.
Eaglwing purchased substantially all of the crude oil production
of MVOs underlying properties for the month of June 2008
and for the first 18 days of July, after which date further
sales to Eaglwing were terminated. Payment for approximately
$9.5 million of the June sales to Eaglwing was due by
July 20, 2008, and payment for approximately
$5.9 million of the July sales to Eaglwing was due by
August 20, 2008. The specified dollar amounts are
associated with all production from the underlying properties,
and not just the 80% portion attributable to the net profits
interest held by MVO. Because of Eaglwings bankruptcy and
failure to pay for such production, MVO did not make a fourth
quarterly distribution in October 2008 and the first quarterly
distribution in January 2009 was substantially impacted. On
July 31, 2008, Vess Oil and Murfin Drilling recommenced
general sales of production from the underlying properties to
several purchasers other than Eaglwing, including an affiliated
purchaser, under short-term arrangements using market sensitive
pricing. As of August 7, 2008, field operations at the
underlying properties returned to substantially
47
normal operations, although it took until mid-August before the
marketing of crude oil production normalized to the sales
process and volumes that existed prior to July 18, 2008.
From the formation of MVO through April 11, 2011, MVO
distributed approximately $9.65 per MVO trust unit in the
aggregate. On April 7, 2011, MVO announced a quarterly
distribution of $0.82. As of April 11, 2011, the closing
price of each MVO unit as reported by the New York Stock
Exchange was $41.44. MVO is expected to terminate on the later
to occur of (1) June 30, 2026, or (2) the time
when 14.4 MMBoe have been produced and sold from the MVO
underlying properties.
48
CERTAIN
RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
RELATED
PARTY TRANSACTIONS
As of December 31, 2010, the VOC Operators, which includes
Vess Oil, L.D. Drilling, Inc. and Davis Petroleum, Inc.,
operated or operated on a contract basis, approximately 98% of
the total proved reserves attributable to the Underlying
Properties based on PV-10 value, with Vess Oil operating
approximately 91% of the total proved reserves for which VOC
Sponsor is the designated operator and L.D. Drilling Inc.
and Davis Petroleum, Inc. operating approximately 7% of the
total proved reserves. Vess Oil is controlled by J. Michael
Vess, L.D. Drilling Inc. is controlled by L.D. Davis
and Davis Petroleum, Inc. is controlled by both Mr. Vess
and Mr. Davis. Under the terms of the operating arrangement
among VOC Sponsor and Vess Oil, all expenses of Vess Oil
incurred on behalf of VOC Sponsor are paid by VOC Sponsor at the
cost incurred. Below is a summary of the transactions that
occurred between VOC Sponsor and the VOC Operators:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2008
|
|
2009
|
|
2010
|
|
|
|
|
(In thousands)
|
|
|
|
Lease operating expenses incurred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Vess Oil Corporation
|
|
$
|
10,314
|
|
|
$
|
9,334
|
|
|
$
|
10,053
|
|
LD Drilling
|
|
|
768
|
|
|
|
685
|
|
|
|
605
|
|
Davis Petroleum
|
|
|
652
|
|
|
|
704
|
|
|
|
756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
11,734
|
|
|
$
|
10,723
|
|
|
$
|
11,414
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Overhead costs included in lease operating expenses incurred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Vess Oil Corporation
|
|
$
|
1,098
|
|
|
$
|
1,232
|
|
|
$
|
1,314
|
|
LD Drilling
|
|
|
91
|
|
|
|
97
|
|
|
|
100
|
|
Davis Petroleum
|
|
|
64
|
|
|
|
72
|
|
|
|
72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,253
|
|
|
$
|
1,401
|
|
|
$
|
1,486
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized lease equipment and producing leasehold costs
incurred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Vess Oil Corporation
|
|
$
|
1,402
|
|
|
$
|
1,937
|
|
|
$
|
3,246
|
|
LD Drilling
|
|
|
304
|
|
|
|
154
|
|
|
|
(8
|
)
|
Davis Petroleum
|
|
|
220
|
|
|
|
3
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,926
|
|
|
$
|
2,094
|
|
|
$
|
3,252
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment of well development costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Vess Oil Corporation
|
|
$
|
1,709
|
|
|
$
|
2,269
|
|
|
$
|
7,149
|
|
LD Drilling
|
|
|
509
|
|
|
|
137
|
|
|
|
|
|
Davis Petroleum
|
|
|
168
|
|
|
|
|
|
|
|
81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,386
|
|
|
$
|
2,406
|
|
|
$
|
7,230
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment of management fees:
|
|
|
|
|
|
|
|
|
|
|
|
|
Vess Oil Corporation
|
|
$
|
447
|
|
|
$
|
447
|
|
|
$
|
447
|
|
LD Drilling
|
|
|
|
|
|
|
|
|
|
|
|
|
Davis Petroleum
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
447
|
|
|
$
|
447
|
|
|
$
|
447
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
VOC Sponsor pays the VOC Operators an overhead fee based on a
monthly charge per active operated well to operate substantially
all of the Underlying Properties located in Kansas on behalf of
VOC Sponsor. The fee is adjusted annually and will increase or
decrease each year based on changes in the Overhead Adjustment
Index (OAI) published by the Council of Petroleum
49
Accountants Society for that year. The operating activities
include various maintenance, engineering, geological, accounting
and administrative functions.
For the Underlying Properties located in Texas, VOC Sponsor
reimburses Vess Texas Partners, LLC (Vess
LLC) for certain corporate administrative and
accounting services arranged by Vess LLC. This reimbursement
amount is adjusted annually and will increase or decrease each
year based on changes in the OAI for that year. Most of the
services for which Vess LLC is reimbursed are performed on
behalf of Vess LLC by Vess Oil. The fee is currently $37,250 per
month.
Vess LLC pays a portion of this $37,250 as an overhead fee to
Vess Oil to operate substantially all of the Underlying
Properties located in Texas on behalf of VOC Sponsor. The
operating activities include various maintenance, engineering,
geological, accounting and administrative functions. The
overhead fee includes (1) a fixed monthly charge of $13,500
per month, (2) reimbursement for certain geological and
engineering services and (3) a monthly charge per active
well brought on production after September 2009, which is
adjusted annually and based on changes in the Overhead
Adjustment Index.
Vess Oil is not contractually obligated to provide the corporate
administrative and accounting services on behalf of VOC Sponsor
or Vess LLC other than with respect to the operation of the
Underlying Properties, and VOC Sponsor and Vess LLC may contract
for the provision of the corporate administrative and accounting
services from other parties at any time. None of the members of
the executive management team are contractually obligated to
continue performing services on behalf of VOC Sponsor, and Vess
Oil is not contractually obligated to make its employees
available to perform such services.
The fees described above are independent of the fees payable by
the trust pursuant to the trust agreement and the Administrative
Services Agreement. See The trust and
Description of the trust agreement Fees and
expenses.
For the year ended December 31, 2010 VOC Sponsor sold
approximately 32% of the oil produced from the Underlying
Properties to MV Purchasing, LLC, (MV Purchasing), an affiliate
of VOC Sponsor. A summary of sales and trade receivables with MV
Purchasing follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Sales
|
|
$
|
1,207,358
|
|
|
$
|
13,482,074
|
|
|
$
|
19,125,260
|
|
Trade Receivables
|
|
$
|
319,109
|
|
|
$
|
1,359,842
|
|
|
$
|
1,760,141
|
|
MV Purchasing began operations on August 1, 2008.
Forty-five days following the closing of the initial public
offering of trust units, VOC Partners, LLC will
(1) purchase, at the initial offering price, trust units
owned by VOC Sponsor and (2) issue a promissory note to VOC
Sponsor having a face amount equal to 90% of the purchase price
for the trust units and a cash payment equal to 10% of the
purchase price for the trust units. This unsecured note that is
fully recourse to VOC Partners, LLC will have a term of ten
years with interest payable at 5% per year.
In connection with the closing of this offering, VOC Acquisition
Partners, LLC, an affiliate of VOC Sponsor, will acquire
60 days after the closing of this offering all of the
outstanding equity interests in VOC Sponsor held by Vess Holding
Corporation and by affiliates of Carson Private Capital through
CPC Brazos Energy, L.P. and CPC VEP, LLC for approximately
$63.4 million. Vess Holding Corporation is the sole
managing member of VOC Sponsors general partner. Before
giving effect to this transaction, the affiliates of Carson
Private Capital own approximately 19.86% of the equity interests
in VOC Sponsor.
50
THE
TRUST
The trust is a statutory trust created under the Delaware
Statutory Trust Act in November 2010. The business and
affairs of the trust will be managed by The Bank of New York
Mellon Trust Company, N.A., as trustee. VOC Sponsor has no
ability to manage or influence the operations of the trust. In
addition, Wilmington Trust Company will act as Delaware
trustee of the trust. The Delaware trustee will have only
minimal rights and duties as are necessary to satisfy the
requirements of the Delaware Statutory Trust Act. In
connection with the completion of this offering, VOC Sponsor
will contribute the Net Profits Interest to the trust in
exchange for 16,540,000 newly issued trust units. VOC Sponsor
will make its first payment to the trust pursuant to the Net
Profits Interest on or about July 25, 2011, which payment
will cover the net proceeds attributable to the Net Profits
Interest for the first two quarters of 2011 consisting of the
period from January 1 to June 30. Subsequent
distributions will only cover the net proceeds attributable to
the Net Profits Interest for one quarter, and, as a result, will
be smaller.
The trustee can authorize the trust to borrow money to pay trust
administrative or incidental expenses that exceed cash held by
the trust. The trustee may authorize the trust to borrow from
the trustee as a lender provided the terms of the loan are fair
to the trust unitholders. The trustee may also deposit funds
awaiting distribution in an account with itself, if the interest
paid to the trust at least equals amounts paid by the trustee on
similar deposits, and make other short-term investments with the
funds distributed to the trust. The trustee has no current plans
to authorize the trust to borrow money. VOC Sponsor has also
agreed to post a letter of credit in the amount of
$1 million in favor of the trustee to protect the trustee
against the risk that the trust does not have sufficient cash to
pay its expenses.
The trust will pay the trustee an administrative fee of $150,000
per year. The trust will pay the Delaware trustee a fee of
$2,500 per year. The trust will also incur legal, accounting,
tax and engineering fees, printing costs and other expenses that
are deducted by the trust before distributions are made to trust
unitholders, including the $18,750 administrative services fee
payable quarterly to VOC Sponsor pursuant to the administrative
services agreement described below. The trust will also be
responsible for paying other expenses incurred as a result of
being a publicly traded entity, including costs associated with
annual and quarterly reports to unitholders, tax return and
Form 1099 preparation and distribution, NYSE listing fees,
independent auditor fees and registrar and transfer agent fees.
Total administrative expenses of the trust on an annualized
basis for 2011 are initially expected to be approximately
$900,000, including the administrative services fee payable to
VOC Sponsor and the trustee. In connection with the closing of
this offering, the trust will enter into an administrative
services agreement with VOC Sponsor that obligates the trust,
throughout the term of the trust, to pay to VOC Sponsor each
quarter an administrative services fee for accounting,
bookkeeping and informational services to be performed by VOC
Sponsor on behalf of the trust relating to the Net Profits
Interest. The annual fee, payable in equal quarterly
installments, will total $75,000 in 2011 and will increase by 4%
each year beginning in January 2012. The administrative services
agreement will terminate upon the termination of the Net Profits
Interest unless earlier terminated by mutual agreement of the
trustee and VOC Sponsor.
The Net Profits Interest will terminate on the later to occur of
(1) December 31, 2030, or (2) the time from and
after January 1, 2011 when 10.6 MMBoe have been
produced from the Underlying Properties and sold (which amount
is the equivalent of 8.5 MMBoe in respect of the
trusts right to receive 80% of the net proceeds from the
Underlying Properties pursuant to the Net Profits Interest), and
the trust will wind up its affairs and terminate.
51
PROJECTED
CASH DISTRIBUTIONS
Immediately prior to the closing of this offering, VOC Sponsor
will create the term Net Profits Interest through a conveyance
to the trust of a Net Profits Interest carved from VOC
Sponsors interests in substantially all of its oil and
natural gas properties, which properties are located in Kansas
and Texas. The Net Profits Interest will entitle the trust to
receive 80% of the net proceeds from the sale of production of
oil and natural gas attributable to the Underlying Properties
until the later to occur of (1) December 31, 2030, or
(2) the time from and after January 1, 2011 when
10.6 MMBoe have been produced from the Underlying
Properties and sold (which amount is the equivalent of
8.5 MMBoe in respect of the trusts right to receive
80% of the net proceeds from the Underlying Properties pursuant
to the Net Profits Interest).
The amount of trust revenues and cash distributions to trust
unitholders will depend on, among other things:
|
|
|
|
|
oil sales prices and, to a lesser extent, natural gas sales
prices;
|
|
|
|
the volume of oil and natural gas produced and sold attributable
to the Underlying Properties;
|
|
|
|
the payments made or received by VOC Sponsor pursuant to the
hedge contracts;
|
|
|
|
property and production taxes;
|
|
|
|
development expenses;
|
|
|
|
lease operating expenses; and
|
|
|
|
administrative expenses of the trust.
|
UNAUDITED
PRO FORMA AVAILABLE CASH FOR THE YEAR ENDED DECEMBER 31,
2010
If VOC Sponsor and the trust had completed the transactions
described under Prospectus summary Formation
transactions on January 1, 2010, the trusts
unaudited pro forma available cash for the year ended
December 31, 2010 would have been approximately
$26.6 million.
Unaudited pro forma available cash gives effect on a pro forma
basis to assumed trust general and administrative expenses of
$900,000, as described in more detail under The
trust. The pro forma adjustments are based upon currently
available information and specific estimates and assumptions.
The pro forma amounts set forth in the table below do not
purport to present cash available for distribution by the trust
to trust unitholders had the formation transactions contemplated
actually occurred on January 1, 2010. In addition, cash
available for distribution by the trust will be calculated based
upon actual cash receipts of the trust during the applicable
quarter, while the unaudited pro forma available cash
calculation has been prepared using a modified cash basis of
accounting as described in more detail in Note B to the
unaudited pro forma financial statements appearing on
page F-27.
As a result, you should view the amount of unaudited pro forma
available cash only as a general indication of the amount of
cash available for distribution by the trust for the year ended
December 31, 2010 had the formation transactions described
above actually occurred on January 1, 2010.
52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
|
Year Ended
|
|
|
|
March 31,
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2010
|
|
|
2010
|
|
|
2010
|
|
|
2010
|
|
|
|
(Dollars in thousands, except per Bbl, Mcf, MMBtu and per
unit amounts)
|
|
|
Underlying Properties sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
202
|
|
|
|
212
|
|
|
|
206
|
|
|
|
197
|
|
|
|
817
|
|
Natural gas (MMcf)
|
|
|
178
|
|
|
|
173
|
|
|
|
170
|
|
|
|
158
|
|
|
|
679
|
|
Total sales (MBoe)
|
|
|
232
|
|
|
|
241
|
|
|
|
234
|
|
|
|
223
|
|
|
|
930
|
|
Average realized sales price(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
72.82
|
|
|
$
|
72.75
|
|
|
$
|
70.67
|
|
|
$
|
78.65
|
|
|
$
|
73.67
|
|
Natural gas (per Mcf)
|
|
$
|
5.03
|
|
|
$
|
4.76
|
|
|
$
|
4.79
|
|
|
$
|
4.46
|
|
|
$
|
4.77
|
|
Calculation of net proceeds:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross proceeds:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
14,710
|
|
|
$
|
15,423
|
|
|
$
|
14,559
|
|
|
$
|
15,495
|
|
|
$
|
60,187
|
|
Natural gas sales
|
|
|
896
|
|
|
|
824
|
|
|
|
815
|
|
|
|
704
|
|
|
|
3,239
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
15,606
|
|
|
$
|
16,247
|
|
|
$
|
15,374
|
|
|
$
|
16,199
|
|
|
$
|
63,426
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and development costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
3,217
|
|
|
$
|
3,119
|
|
|
$
|
3,612
|
|
|
$
|
3,778
|
|
|
$
|
13,726
|
|
Production and property taxes
|
|
|
1,015
|
|
|
|
994
|
|
|
|
1,037
|
|
|
|
1,091
|
|
|
|
4,137
|
|
Development expenses
|
|
|
2,788
|
|
|
|
2,671
|
|
|
|
3,285
|
|
|
|
1,748
|
|
|
|
10,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
7,020
|
|
|
$
|
6,784
|
|
|
$
|
7,934
|
|
|
$
|
6,617
|
|
|
$
|
28,355
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement of hedge contracts (payment received)(2)
|
|
|
252
|
|
|
|
107
|
|
|
|
(208
|
)
|
|
|
557
|
|
|
|
708
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net proceeds
|
|
$
|
8,334
|
|
|
$
|
9,356
|
|
|
$
|
7,648
|
|
|
$
|
9,025
|
|
|
$
|
34,363
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage allocable to Net Profits Interest
|
|
|
80%
|
|
|
|
80%
|
|
|
|
80%
|
|
|
|
80%
|
|
|
|
80%
|
|
Net proceeds to trust from Net Profits Interest
|
|
$
|
6,667
|
|
|
$
|
7,485
|
|
|
$
|
6,118
|
|
|
$
|
7,220
|
|
|
$
|
27,490
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trust general and administrative expenses
|
|
|
225
|
|
|
|
225
|
|
|
|
225
|
|
|
|
225
|
|
|
|
900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash available for distribution by the trust
|
|
$
|
6,442
|
|
|
$
|
7,260
|
|
|
$
|
5,893
|
|
|
$
|
6,995
|
|
|
$
|
26,590
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distribution per trust unit
|
|
$
|
0.39
|
|
|
$
|
0.44
|
|
|
$
|
0.36
|
|
|
$
|
0.42
|
|
|
$
|
1.61
|
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Sales price net of forecasted
gravity, quality, transportation, and marketing costs.
|
|
(2)
|
|
Costs are reduced by hedge payments
received by VOC Sponsor under the hedge contracts in existence
during the year ended December 31, 2010. If the hedge
payments received by VOC Sponsor under the hedge contracts
exceed costs during a quarterly period, the ability to use such
excess amounts to offset costs will be deferred, with interest
accruing on such amounts at the prevailing money market rate,
until the next quarterly period when the hedge payments are less
than such costs. During the year ended December 31, 2010,
KEP was not a party to any hedge contracts.
|
|
|
|
(3)
|
|
Due to the timing of the payment of
production proceeds to the trust, the production and costs
attributable to the available distributions for the twelve
months ended December 31, 2010 would have been for the
eleven months ended November 30, 2010, if the pro forma
available cash for distribution were calculated based on a
modified cash basis. As a result, the pro forma distributable
income per trust unit for the twelve months ended
December 31, 2010 would have been $1.43.
|
53
PROJECTED
CASH DISTRIBUTIONS FOR THE YEAR ENDING
DECEMBER 31, 2011
The following table presents a calculation of projected cash
distributions to holders of trust units who own trust units as
of the record date for the distribution for the second quarter
of 2011 and continue to own those trust units through the record
date for the cash distribution payable with respect to oil and
natural gas production for the last quarter of 2011. The cash
distribution projections for the year ending December 31,
2011 were prepared by VOC Sponsor based on the hypothetical
assumptions that are described below and in
Significant assumptions used to prepare the
projected cash distributions. Production attributable to
the Underlying Properties for the twelve months ending
December 31, 2011 is estimated to be 878.4 MBoe.
However, due to the timing of the payment of production proceeds
to the trust, the production and costs attributable to the
distributions for the twelve months ending December 31,
2011 will be for the eleven months ending November 30,
2011, which is estimated to be 800.9 MBoe. As a result,
projected cash distributions for the year ending
December 31, 2011 will only include proceeds attributable
to production and costs for the eleven months ending
November 30, 2011. Payments to trust unitholders will
generally be made 45 days following each calendar quarter.
Generally, VOC Sponsor will make payments to the trust that will
include cash from production from the first two months of the
quarter just ended as well as the last month of the immediately
preceding quarter. For the year ending December 31, 2011,
the trust will not make its first payment to the unitholders
pursuant to the Net Profits Interest until on or about
August 15, 2011, which payment will cover the net proceeds
attributable to the Net Profits Interest for the first five
months of 2011, less any general and administrative expenses and
reserves of the trust.
VOC Sponsor does not as a matter of course make public
projections as to future sales, earnings or other results.
However, the management of VOC Sponsor has prepared the
projected financial information set forth below to present the
projected cash distributions to the holders of the trust units
based on the estimates and hypothetical assumptions described
below. The accompanying projected financial information was not
prepared with a view toward complying with the published
guidelines of the SEC or guidelines established by the American
Institute of Certified Public Accountants with respect to
projected financial information.
In the view of VOC Sponsors management, the accompanying
unaudited projected financial information was prepared on a
reasonable basis and reflects the best currently available
estimates and judgments of VOC Sponsor related to oil and
natural gas production, operating expenses and development
expenditures, based on:
|
|
|
|
|
preliminary estimates of realized oil and natural gas production
for January and February 2011 and oil and natural gas production
estimates for March through November 2011 contained in the
reserve reports;
|
|
|
|
|
|
estimated production and development costs for the year ending
December 31, 2011, contained in the reserve
reports; and
|
|
|
|
projected payments made or received pursuant to the hedge
contracts, if any, for the year ending December 31, 2011
assuming the hypothetical prices used in the following table and
the hedge contracts to be entered into by VOC Sponsor as of the
closing of this offering related to production for 2011.
|
54
The assumed oil and natural gas prices utilized for purposes of
preparing the projections are based on spot prices for January,
February and March 2011 and NYMEX futures pricing for April
through November 2011 as reported on March 10, 2011. These
prices represent average prices of $102.07 per Bbl in the case
of crude oil and $4.07 per MMBtu in the case of natural gas.
These hypothetical prices are then adjusted to take into account
VOC Sponsors estimate of the basis differential (based on
location and quality of the production) between published prices
and the prices actually received by VOC Sponsor. Actual prices
paid for oil and natural gas expected to be produced from the
Underlying Properties in 2011 will likely differ from these
hypothetical prices due to fluctuations in the prices generally
experienced with respect to the production of oil and natural
gas and variations in basis differentials. For example, the
published average monthly closing NYMEX crude oil spot price per
Bbl was $79.51 for the year ended December 31, 2010, with
the actual monthly closing prices ranging from $65.96 to $91.49
during such period. See Significant assumptions used to
prepare the projected cash distributions and Risk
factors Prices of oil and natural gas fluctuate due
to a number of factors that are beyond the control of the trust
and VOC Sponsor, and lower prices could reduce proceeds to the
trust and cash distributions to unitholders.
VOC Sponsor utilized these production estimates, hypothetical
oil and natural gas prices and cost estimates in preparing the
projected financial information. This methodology is consistent
with the requirements of the SEC for estimating oil and natural
gas reserves and discounted present value of future net revenues
attributable to the Net Profits Interest, except that VOC
Sponsor utilized average 2011 NYMEX futures prices rather than
average historical monthly prices for oil and natural gas. The
actual production amounts, commodity prices and costs for 2011
may vary from those VOC Sponsor has projected, and such
variations could be material. Accordingly, the projected
financial information should not be relied upon as being
necessarily indicative of future results. Readers of this
prospectus are cautioned not to place undue reliance on the
projected financial information.
Neither VOC Sponsors independent auditors nor any other
independent accountants have compiled, examined or performed any
procedures with respect to the projected financial information
contained herein, nor have they expressed any opinion or any
other form of assurance on such information or its
achievability, and assume no responsibility for, and disclaim
any association with, the projected financial information.
The projections and the estimates and hypothetical assumptions
on which they are based are subject to significant
uncertainties, many of which are beyond the control of VOC
Sponsor or the trust. Actual cash distributions to trust
unitholders, therefore, could vary significantly based upon
events or conditions occurring that are different from the
events or conditions assumed to occur for purposes of these
projections. Cash distributions to trust unitholders will be
particularly sensitive to fluctuations in oil and natural gas
prices. See Risk factors Prices of oil and
natural gas fluctuate due to a number of factors that are beyond
the control of the trust and VOC Sponsor, and lower prices could
reduce proceeds to the trust and cash distributions to
unitholders. As a result of typical production declines
for oil and natural gas properties, production estimates
generally decrease from year to year, and the projected cash
distributions shown in the following table are not necessarily
indicative of distributions for future years. See
Sensitivity of projected cash distributions to
oil and natural gas production and prices below, which
shows projected effects on cash distributions from hypothetical
changes in oil and natural gas production and prices. Because
payments to the trust will be generated by depleting assets and
the trust has a finite life with the production from the
Underlying Properties diminishing over time, a portion of each
distribution will represent a return of your original
investment. See Risk factors The reserves
attributable to the Underlying Properties are depleting assets
and production from those reserves will diminish over time.
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
|
|
|
|
|
|
|
|
|
Projection for
|
|
|
|
|
|
|
Months
|
|
|
|
|
|
|
|
|
Twelve Months
|
|
|
|
|
|
|
Ending
|
|
|
Three Months Ending
|
|
|
Ending
|
|
|
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
|
|
|
2011 (1)
|
|
|
2011 (2)
|
|
|
2011 (3)
|
|
|
2011 (4)
|
|
|
|
|
|
|
(Dollars in thousands, except per Bbl,
|
|
|
|
Mcf, MMBtu and per unit amounts)
|
|
|
Underlying Properties sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
307.2
|
|
|
|
198.5
|
|
|
|
210.9
|
|
|
|
716.5
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
207.5
|
|
|
|
146.8
|
|
|
|
152.0
|
|
|
|
506.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales (MBoe)
|
|
|
341.8
|
|
|
|
222.9
|
|
|
|
236.3
|
|
|
|
800.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX future prices (5):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
97.87
|
|
|
$
|
104.90
|
|
|
$
|
105.54
|
|
|
$
|
102.07
|
|
|
|
|
|
Natural gas (per MMBtu)
|
|
$
|
4.01
|
|
|
$
|
4.02
|
|
|
$
|
4.19
|
|
|
$
|
4.07
|
|
|
|
|
|
Assumed realized sales price (6):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
92.03
|
|
|
$
|
99.35
|
|
|
$
|
100.06
|
|
|
$
|
96.42
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
4.55
|
|
|
$
|
4.89
|
|
|
$
|
5.20
|
|
|
$
|
4.84
|
|
|
|
|
|
Calculation of net proceeds:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross proceeds:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
28,270
|
|
|
$
|
19,717
|
|
|
$
|
21,104
|
|
|
$
|
69,092
|
|
|
|
|
|
Natural gas sales
|
|
|
945
|
|
|
|
717
|
|
|
|
790
|
|
|
|
2,452
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
29,215
|
|
|
$
|
20,434
|
|
|
$
|
21,894
|
|
|
$
|
71,544
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and development costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
5,159
|
|
|
$
|
3,026
|
|
|
$
|
3,054
|
|
|
$
|
11,239
|
|
|
|
|
|
Production and property taxes
|
|
|
1,800
|
|
|
|
1,257
|
|
|
|
1,352
|
|
|
|
4,409
|
|
|
|
|
|
Development expenses
|
|
|
2,594
|
|
|
|
2,905
|
|
|
|
2,673
|
|
|
|
8,171
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
9,553
|
|
|
$
|
7,188
|
|
|
$
|
7,079
|
|
|
$
|
23,819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement of hedge contracts (payment received) (7)
|
|
$
|
267
|
|
|
$
|
618
|
|
|
$
|
677
|
|
|
$
|
1,562
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net proceeds
|
|
$
|
19,395
|
|
|
$
|
12,628
|
|
|
$
|
14,138
|
|
|
$
|
46,163
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage allocable to Net Profits Interest
|
|
|
80%
|
|
|
|
80%
|
|
|
|
80%
|
|
|
|
80%
|
|
|
|
|
|
Net proceeds to trust from Net Profits Interest
|
|
$
|
15,516
|
|
|
$
|
10,103
|
|
|
$
|
11,311
|
|
|
$
|
36,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trust general and administrative expenses (8)
|
|
|
450
|
|
|
|
225
|
|
|
|
225
|
|
|
|
900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash reserve
|
|
|
1,000
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
|
|
|
Cash available for distribution by the trust
|
|
$
|
14,066
|
|
|
$
|
9,878
|
|
|
$
|
11,086
|
|
|
$
|
35,030
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distribution per trust unit
|
|
$
|
0.85
|
|
|
$
|
0.60
|
|
|
$
|
0.67
|
|
|
$
|
2.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Includes proceeds and costs
attributable to production from January 1, 2011 through
May 31, 2011.
|
|
(2)
|
|
Includes proceeds and costs
attributable to production from June 1, 2011 through
August 31, 2011.
|
|
(3)
|
|
Includes proceeds and costs
attributable to production from September 1, 2011 through
November 30, 2011.
|
|
(4)
|
|
Includes proceeds and costs
attributable to production from January 1, 2011 through
November 30, 2011.
|
56
|
|
|
(5)
|
|
The assumed oil and natural gas
prices utilized for purposes of preparing the projections are
based on spot prices for January, February and March 2011 and
NYMEX futures pricing for April through November 2011 as
reported on March 10, 2011. For a description of the effect
of lower NYMEX prices on projected cash distributions, please
read Sensitivity of projected cash distributions to
oil and natural gas production and prices.
|
|
|
|
(6)
|
|
Assumed realized sales price net of
forecasted gravity, quality, transportation, and marketing
costs. For more information about the estimates and hypothetical
assumptions made in preparing the table above, see
Significant assumptions used to prepare the
projected cash distributions.
|
|
(7)
|
|
Costs will be reduced by hedge
payments received by VOC Sponsor under the hedge contracts. If
the hedge payments received by VOC Sponsor under the hedge
contracts exceed costs during a quarterly period, the ability to
use such excess amounts to offset costs will be deferred, with
interest accruing on such amounts at the prevailing money market
rate, until the next quarterly period when the hedge payments
are less than such costs.
|
|
(8)
|
|
Total general and administrative
expenses of the trust on an annualized basis for 2011 are
expected to be $900,000, which includes an annual administrative
fee to VOC Sponsor in the amount of $75,000 in 2011, which fee
will increase by 4% annually beginning in January 2012, the
annual fee to the trustees, accounting fees, engineering fees,
printing costs and other expenses properly chargeable to the
trust.
|
SIGNIFICANT
ASSUMPTIONS USED TO PREPARE THE PROJECTED CASH
DISTRIBUTIONS
Timing of distributions. In preparing the
projected cash distributions and sensitivity analysis above, the
revenues and expenses of the trust were calculated based on the
terms of the conveyance creating the trusts Net Profits
Interest. These calculations are described under
Computation of net proceeds Net Profits
Interest. Quarterly cash distributions will be made on or
about the 45th day following the end of each calendar
quarter to trust unitholders of record on or about the
30th day following each calendar quarter. Due to the timing
of VOC Sponsors receipt of cash for production, it has
been assumed that cash distributions for each quarter will
include production from the first two months of the quarter just
ended as well as the last month of the immediately preceding
quarter. The first distribution, which will cover the first and
second quarters of 2011, is expected to be made on or about
August 15, 2011 to record trust unitholders as of
August 1, 2011, and will include sales for oil and natural
gas for the months January through May 2011. Thereafter,
quarterly distributions will generally relate to production of
oil and natural gas for a three month period, including one
month of the prior quarter.
Production estimates and development
expenses. Production estimates for 2011 are based
on the reserve reports for March through November 2011 and
preliminary estimates of realized production for January and
February 2011. Production from the Underlying Properties for the
first 11 months of 2011 is estimated to be 717 MBbls
of oil and 506 MMcf of natural gas. Net sales for the year
ended December 31, 2010 were 817 MBbls of oil and
679 MMcf of natural gas. Reductions in projected production
volumes in the forecasted period are primarily attributable to
the natural production decline of the Underlying Properties.
Although VOC Sponsor expects annual production from the
Underlying Properties to decline at an average annual rate of
6.2% over the next 20 years, VOC Sponsor expects the actual
annual decline rate to be smaller during the beginning of that
period and to increase over the course of that period. The
expected increase in the annual decline rate over the course of
this 20-year
period is primarily a result of the assumption that no
additional development drilling or other development
expenditures will be made after 2014 on the Underlying
Properties.
Oil and natural gas prices. The assumed oil
and natural gas prices utilized for purposes of preparing the
projections are based on spot prices for January, February and
March 2011 and NYMEX futures pricing for April through November
2011 as reported on March 10, 2011. Published NYMEX
benchmark prices for crude oil are based upon an assumed light,
sweet crude oil of a particular gravity that is stored in
Cushing, Oklahoma while published NYMEX benchmark prices for
natural gas are based upon delivery at the Henry Hub in
Louisiana. These prices differ from the average or actual price
received for production attributable to the
57
Underlying Properties. Differentials between published oil and
natural gas prices and the prices actually received for the oil
and natural gas production may vary significantly due to market
conditions, transportation costs, quality of production and
other factors.
In the above table, $5.65 per barrel is deducted from the
average 2011 NYMEX futures price for crude oil to reflect these
differentials. This deduction is based on VOC Sponsors
estimate of the average difference between the NYMEX published
price of crude oil and the price to be received by VOC Sponsor
for production attributable to the Underlying Properties during
2011. These projections are based on the historical price
differentials as of December 31, 2010. Projected average
oil prices appearing in this prospectus have been adjusted for
these differentials.
In the above table, $0.77 per Mcf is the average 2011 NYMEX
price adjustment for natural gas in 2011 to reflect these
differentials. This adjustment is based on VOC Sponsors
estimate of the average difference between the NYMEX published
price of natural gas and the price to be received by VOC Sponsor
for production attributable to the Underlying Properties during
2011. These projections are based on the historical price
differentials as of December 31, 2010. Projected average
natural gas prices appearing in this prospectus have been
adjusted for these differentials.
The differentials to published oil and natural gas prices
applied in the above projected cash distribution estimate are
based upon an analysis by VOC Sponsor of the historic price
differentials for production from the Underlying Properties with
consideration given to historic gravity, quality and
transportation and marketing costs that may affect these
differentials in 2011. Historic variability of the impact of
gravity, quality and transportation and marketing costs have
been minimal on an aggregate basis, with historical variances
from these costs impacting crude oil prices by approximately $2
per Bbl. Accordingly, VOC Sponsor has assumed for purposes of
the projected cash distributions that the impact of gravity,
quality and transportation and marketing costs will remain
consistent with the impact thereof for the year ended
December 31, 2010. There is no assurance that these assumed
differentials will occur in 2011.
When oil and natural gas prices decline, the operators of the
properties comprising the Underlying Properties may elect to
reduce or completely suspend production. No adjustments have
been made to estimated 2011 production to reflect potential
reductions or suspensions of production.
Settlement of Hedge Contracts. VOC Sponsor has
entered into fixed price swap contracts for the first
11 months of 2011 with respect to 379,912 Bbls of oil
expected to be produced from the Underlying Properties at a
weighted average price per Bbl of $99.43 that hedge
approximately 57% of the expected oil production from the proved
developed producing reserves attributable to the Underlying
Properties for 2011 in the reserve reports. The crude oil swap
contracts will settle based on the average of the settlement
price for each commodity business day in the contract month. In
a swap transaction, the counterparty is required to make a
payment to VOC Sponsor for the difference between the fixed
price and the settlement price if the settlement price is below
the fixed price. VOC Sponsor is required to make a payment to
the counterparty for the difference between the fixed price and
the settlement price if the settlement price is above the fixed
price.
Costs. For the first 11 months of 2011,
VOC Sponsor estimates lease operating expenses to be
$11.2 million, production and property taxes to be
$4.4 million and development expenses to be
$8.2 million. For the year ended December 31, 2010,
lease operating expenses were $13.7 million, production and
property taxes were $4.1 million and development expenses
were $10.5 million. The lower anticipated costs for the
first 11 months of 2011 are the result of costs associated
with production which is not included in the forecast period and
litigation costs incurred in 2010 which are no longer being
incurred. For a description of production expenses
58
and development costs, see Computation of net
proceeds Net Profits Interest. VOC Sponsor
expects its costs in 2011 to be substantially the same as its
costs in 2010.
Administrative expense. The trust will be
responsible for paying all legal, accounting, tax advisory,
engineering and stock exchange fees, printing costs and other
administrative and
out-of-pocket
expenses incurred by or at the direction of the trustee or the
Delaware trustee. The trust will also be responsible for paying
other expenses incurred as a result of being a publicly traded
entity, including costs associated with annual and quarterly
reports to unitholders, preparation and distribution of tax
information material, independent auditor fees and registrar and
transfer agent fees. These trust administrative expenses are
anticipated to aggregate approximately $900,000 for the full
year 2011. Administrative expenses for subsequent years could be
greater or less depending on future events that cannot be
predicted. Included in the $900,000 annual estimate is an annual
administrative fee of $150,000 for the trustee and an annual
administrative fee of $2,500 for the Delaware trustee as well as
an annual administrative fee payable to VOC Sponsor, which fee
will total $75,000 in 2011 and will increase by 4% each year
beginning in January 2012. The trust will pay, out of the first
cash payment received by the trust, the trustees and
Delaware trustees legal expenses incurred in forming the
trust as well as the Delaware trustees acceptance fee in
the amount of $4,000. These costs will be deducted by the trust
before distributions are made to trust unitholders. See
The trust.
SENSITIVITY
OF PROJECTED CASH DISTRIBUTIONS TO OIL AND NATURAL GAS
PRODUCTION AND PRICES
The amount of revenues of the trust and cash distributions to
the trust unitholders will be directly dependent on the sales
price for oil and natural gas production sold from the
Underlying Properties, the volumes of oil and natural gas
produced attributable to the Underlying Properties, payments
made or received under the hedge contracts and variations in
lease operating expenses, production and property taxes and
development costs.
The table and discussion below sets forth sensitivity analyses
of annual cash distributions per trust unit for the year ending
December 31, 2011, on the assumption that a trust
unitholder purchased a trust unit in the initial public offering
and held such trust unit until the quarterly record date for
distributions made with respect to oil and natural gas
production in the last quarter of 2011, based upon: (1) the
assumption that a total of 16,540,000 trust units are issued and
outstanding after the closing of the offering made hereby;
(2) various realizations of the production levels estimated
in the summary reserve report; (3) various hypothetical
commodity prices based upon NYMEX futures prices; (4) the
impact of the hedge contracts entered into by VOC Sponsor that
relate to production from the Underlying Properties; and
(5) other assumptions described under
Significant assumptions used to prepare the
projected cash distributions. The hypothetical commodity
prices of oil and natural gas production shown have been chosen
solely for illustrative purposes. For a description of the
effect of calculating annual cash distributions on an accrual
basis rather than on a cash basis as prescribed in the
conveyance of the Net Profits Interest, see
Significant assumptions used to prepare the
projected cash distributions Timing of actual
distributions.
59
The table below is not a projection or forecast of the actual
or estimated results from an investment in the trust units. The
purpose of the table below is to illustrate the sensitivity of
cash distributions to changes in oil and natural gas production
levels and oil and natural gas pricing (giving effect to the
hedge contracts that are in place in 2011). There is no
assurance that the hypothetical assumptions described below will
actually occur or that production levels or NYMEX futures prices
will not change by amounts different from those shown in the
tables.
The trusts crude oil hedging contracts will be in effect
only through December 31, 2013, and thus there is likely to
be greater fluctuation in cash distributions resulting from
fluctuations in realized crude oil prices in periods subsequent
to the expiration of those contracts. See Risk
factors for a discussion of various items that could
impact production levels and the price of crude oil.
Sensitivity
of Total 2011 Projected Cash Distribution Per Trust Unit
to Changes in Estimated Oil and Natural Gas Production and NYMEX
Futures Pricing
|
|
|
(1) |
|
Estimated oil and natural gas production is based on the reserve
reports, and the sensitivity analysis assumes there will be no
variation by location and that oil and natural gas production
will continue to represent the same percentage of total
production as estimated for the first 11 months of 2011 in
the reserve report. |
60
THE
UNDERLYING PROPERTIES
The Underlying Properties consist of VOC Sponsors net
interests in substantially all of its oil and natural gas
properties after deduction of all royalties and other burdens on
production thereon as of the date of conveyance of the Net
Profits Interest to the trust. As of December 31, 2010,
these oil and natural gas properties consisted of approximately
881 gross (545.7 net) producing oil and natural gas wells
in 191 fields in VOC Sponsors two operating areas, Kansas
and Texas. During the year ended December 31, 2010, average
net production from the Underlying Properties was approximately
2,547 Boe per day (or 2,038 Boe per day attributable to the
trust) comprised of approximately 88% oil and 12% natural gas.
As of December 31, 2010, proved reserves attributable to
the Underlying Properties, as estimated in the reserve reports,
were approximately 13.7 MMBoe with a
PV-10 value
of $268.3 million.
VOC Sponsors interests in the properties comprising the
Underlying Properties require VOC Sponsor to bear its
proportionate share along with the other working interest owners
of the costs of development and operation of such properties.
The properties comprising the Underlying Properties are burdened
by non-working interests owned by third parties consisting
primarily of overriding royalty and royalty interests retained
by the owners of the land subject to the working interests.
These landowners royalty interests typically entitle the
landowner to receive 12.5% of the revenue derived from oil and
natural gas production resulting from wells drilled on the
landowners land, without any deduction for drilling costs
or other costs related to production of oil and natural gas. A
working interest percentage represents a working interest
owners proportionate ownership interest in a property in
relation to all other working interest owners in that property,
whereas a net revenue interest percentage is a working interest
owners percentage of production after reducing such
percentage by the percentage of burdens on such production such
as royalties and overriding royalties. As of December 31,
2010, VOC Sponsor held average working interests of 74.4% and
68.0% in the Underlying Properties located in the States of
Kansas and Texas, respectively. As of December 31, 2010,
the VOC Operators were the operators or contract operators of
98% of the proved reserves attributable to the Underlying
Properties, based on
PV-10 value,
and VOC Sponsor held an average net revenue interest of 61.8%
and 56.1% for the Underlying Properties located in Kansas and
Texas, respectively.
Based on the reserve reports, the Net Profits Interest would
entitle the trust to receive net proceeds from the sale of
production of not less than 8.5 MMBoe of proved reserves
attributable to the Underlying Properties expected to be
produced over the term of the trust. The trust is entitled to
receive 80% of the net proceeds from the sale of production of
oil and natural gas attributable to the Underlying Properties
that are produced during the term of the trust, whereas total
reserves as reflected on the summary reserve reports and
attributable to the Underlying Properties include all reserves
expected to be economically produced during the economic life of
the properties.
VOC Sponsor has agreed to use commercially reasonable efforts to
cause the operators of the Underlying Properties to operate
these properties as would a reasonably prudent operator acting
with respect to its own properties (without regard to the
existence of the Net Profit Interest). In addition, after giving
effect to the conveyance of the Net Profits Interest to the
trust, VOC Sponsors interest in the Underlying Properties
entitles it to 20% of the net proceeds from the sale of
production of oil and natural gas attributable to VOC
Sponsors interest in the Underlying Properties during the
term of the trust, and 100% thereafter. VOC Sponsor believes
that its retained interests in the Underlying Properties
combined with VOC Partners, LLCs ownership of trust units
representing a 34.8% beneficial interest in the trust, which
collectively entitle VOC Sponsor and VOC Partners, LLC to
receive approximately 48% of the net proceeds from the
Underlying Properties, will provide sufficient incentive to
operate and develop the oil and
61
natural gas properties comprising the Underlying Properties in
an efficient and cost-effective manner.
In general, the producing wells included in the Underlying
Properties have stable production profiles and their production
is long-lived. Based on the reserve report, annual production
from the Underlying Properties is expected to decline at an
average annual rate of 6.2% over the next 20 years assuming
no additional development drilling or other development
expenditures are made on the Underlying Properties after 2015.
VOC Sponsor expects total development expenditures for the
Underlying Properties through December 31, 2015 will be
approximately $27.1 million, which it expects will
partially offset the natural decline in production otherwise
expected to occur with respect to the Underlying Properties as
described in more detail below.
SELECTED
HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL AND OPERATING DATA
OF THE UNDERLYING PROPERTIES
The following table sets forth revenues, direct operating
expenses and the excess of revenues over direct operating
expenses relating to the Predecessor Underlying Properties and
the Acquired Underlying Properties for the three years in the
period ended December 31, 2010 derived from the audited
statements of historical revenues and direct operating expenses
of each of the Predecessor Underlying Properties and the
Acquired Underlying Properties included elsewhere in this
prospectus.
The following table also sets forth revenues, direct operating
expenses and the excess of revenues over direct operating
expenses relating to the Predecessor Underlying Properties after
giving pro forma effect to the acquisition of the Acquired
Underlying Properties for the year ended December 31, 2010.
The information included in this table is derived from the
unaudited pro forma statements of historical revenues and direct
operating expenses of the Predecessor Underlying Properties
included in this prospectus beginning on
page F-18.
The pro forma adjustments have been prepared as if the
acquisition of the Acquired Underlying Properties by Predecessor
had taken place (1) on December 31, 2010, in the case
of the pro forma balance sheet
62
information, and (2) as of January 1, 2010, in the
case of the pro forma statement of earnings information for the
year ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
(In thousands)
|
|
|
Predecessor Underlying Properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
36,632
|
|
|
$
|
22,758
|
|
|
$
|
36,914
|
|
Natural gas sales
|
|
|
3,350
|
|
|
|
1,511
|
|
|
|
2,396
|
|
Hedge and other derivative income (expense)
|
|
|
(7,784
|
)
|
|
|
1,477
|
|
|
|
(707
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
32,198
|
|
|
$
|
25,746
|
|
|
$
|
38,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bad debt expense (recovery)
|
|
$
|
1,727
|
|
|
$
|
(719
|
)
|
|
|
|
|
Direct operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
7,667
|
|
|
|
6,788
|
|
|
|
7,325
|
|
Production and property taxes
|
|
|
2,532
|
|
|
|
1,646
|
|
|
|
2,720
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
10,199
|
|
|
|
8,434
|
|
|
|
10,045
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
$
|
20,272
|
|
|
$
|
18,031
|
|
|
$
|
28,558
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquired Underlying Properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
29,297
|
|
|
$
|
17,602
|
|
|
$
|
23,273
|
|
Natural gas sales
|
|
|
2,248
|
|
|
|
781
|
|
|
|
842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
31,545
|
|
|
$
|
18,383
|
|
|
$
|
24,115
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bad debt expense
|
|
$
|
2,166
|
|
|
$
|
|
|
|
$
|
|
|
Direct operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
6,046
|
|
|
|
5,969
|
|
|
|
6,402
|
|
Production and property taxes
|
|
|
1,614
|
|
|
|
1,170
|
|
|
|
1,417
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
7,660
|
|
|
|
7,139
|
|
|
|
7,819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
$
|
21,719
|
|
|
$
|
11,244
|
|
|
$
|
16,296
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
|
(In thousands)
|
|
|
Predecessor Pro Forma (unaudited)
|
|
|
|
|
Revenues:
|
|
|
|
|
Oil sales
|
|
$
|
60,187
|
|
Natural gas sales
|
|
|
3,239
|
|
Hedge and other derivative income (expense)
|
|
|
(707
|
)
|
|
|
|
|
|
Total
|
|
$
|
62,719
|
|
|
|
|
|
|
Direct operating expenses:
|
|
|
|
|
Lease operating expenses
|
|
$
|
13,727
|
|
Production and property taxes
|
|
|
4,137
|
|
|
|
|
|
|
Total
|
|
|
17,864
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
$
|
44,855
|
|
|
|
|
|
|
63
The following table provides oil and natural gas sales volumes,
average sales prices and capital expenditures relating to the
Underlying Properties for the three years in the period ended
December 31, 2010. Average sales prices do not include the
effect of hedge activity.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Underlying Properties
(1)
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
704
|
|
|
|
732
|
|
|
|
817
|
|
Natural gas (MMcf)
|
|
|
750
|
|
|
|
693
|
|
|
|
679
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales (MBoe)
|
|
|
829
|
|
|
|
847
|
|
|
|
930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
93.67
|
|
|
$
|
55.16
|
|
|
$
|
73.71
|
|
Natural gas (per Mcf)
|
|
$
|
7.46
|
|
|
$
|
3.31
|
|
|
$
|
4.77
|
|
Capital expenditures (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition
|
|
$
|
7,899
|
|
|
$
|
4,134
|
|
|
$
|
3,262
|
|
Well development
|
|
|
2,499
|
|
|
|
2,407
|
|
|
|
7,230
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
10,398
|
|
|
$
|
6,541
|
|
|
$
|
10,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The operating data includes the
effect of the Acquired Underlying Properties for all periods
presented.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Predecessor Underlying
Properties
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
389
|
|
|
|
407
|
|
|
|
495
|
|
Natural gas (MMcf)
|
|
|
426
|
|
|
|
415
|
|
|
|
447
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
460
|
|
|
|
477
|
|
|
|
569
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
94.11
|
|
|
$
|
55.86
|
|
|
$
|
74.59
|
|
Natural gas (per Mcf)
|
|
$
|
7.86
|
|
|
$
|
3.64
|
|
|
$
|
5.36
|
|
Capital expenditures (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition
|
|
$
|
6,715
|
|
|
$
|
2,369
|
|
|
$
|
2,606
|
|
Well development
|
|
|
1,063
|
|
|
|
1,955
|
|
|
|
6,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
7,778
|
|
|
$
|
4,324
|
|
|
$
|
9,372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Acquired Underlying
Properties
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
315
|
|
|
|
324
|
|
|
|
322
|
|
Natural gas (MMcf)
|
|
|
324
|
|
|
|
278
|
|
|
|
232
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
369
|
|
|
|
371
|
|
|
|
360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
93.12
|
|
|
$
|
54.27
|
|
|
$
|
72.35
|
|
Natural gas (per Mcf)
|
|
$
|
6.94
|
|
|
$
|
2.81
|
|
|
$
|
3.63
|
|
Capital expenditures (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition
|
|
$
|
1,184
|
|
|
$
|
1,765
|
|
|
$
|
655
|
|
Well development
|
|
|
1,436
|
|
|
|
452
|
|
|
|
464
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,620
|
|
|
$
|
2,217
|
|
|
$
|
1,119
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DISCUSSION
AND ANALYSIS OF HISTORICAL RESULTS OF THE UNDERLYING
PROPERTIES
Predecessor
Underlying Properties
Comparison
of Results of the Predecessor Underlying Properties for the
Years Ended December 31, 2010 and 2009
Excess of revenues over direct operating expenses for the
Predecessor Underlying Properties was $28.6 million for the
year ended December 31, 2010, compared to
$18.0 million for the year ended December 31, 2009.
The increase was primarily a result of increases in oil
production and in the average price received for the oil and
natural gas sold. This was partially offset by an increase in
direct operating expenses and an increase in hedge expense.
Revenues. Revenues from oil and natural gas sales
increased $15.0 million between the periods. This increase
in revenues was primarily the result of an increase in the
average price received for crude oil sold from $55.86 per Bbl
for the year ended December 31, 2009 to $74.59 per Bbl for
the year ended December 31, 2010 and a 87.5 MBbl
increase in oil volumes sold. The increase in revenues was also
the result of an increase in the average price received for
natural gas sold from $3.64 per Mcf for the year ended
December 31, 2009 to $5.36 per Mcf for the year ended
December 31, 2010, and a 32.2 MMcf increase in natural
gas volumes sold.
Hedge activity. Hedge activity income was
$1.5 million for the year ended December 31, 2009
compared to hedge activity expense of $0.7 million for the
year ended December 31, 2010. This decrease in income and
increase in expense was due to an increase in realized hedge
losses for the period and the recording of the change in market
value of some of the hedges to the income statement.
The increase in hedge expense was due to the higher average
NYMEX price per Bbl of crude oil for the year ended
December 31, 2010 of $79.53 compared to $61.80 for the
year ended December 31, 2009. The weighted average
settlement price of hedges for the year ended December 31,
2010 was $74.40 compared to $68.51 for the year ended
December 31, 2009.
65
Bad debt expense (recovery). Bad debt recovery was
$0.7 million for the year ended December 31, 2009
reflecting the reversal of the bad debt expense recorded in 2008
with respect to the Texas Underlying Properties as described
below. There was no bad debt expense or recovery during the year
ended December 31, 2010.
As publicly reported on July 22, 2008, the revenue
intermediary/crude oil purchaser (Eaglwing L.P.) and its parent
(SemGroup, L.P.) filed voluntary petitions for reorganization
under Chapter 11 of the United States Bankruptcy Code.
During this process, the monies that had been transferred to the
revenue intermediary by certain of Predecessors oil and
gas purchasers for distribution to Predecessor and other working
interest, royalty interest and overriding royalty interest
owners were erroneously retained by the revenue intermediary.
Vess Oil, as primary operator of Predecessors oil and gas
leases, filed suit to recover these funds which were estimated
to be $1.4 million for Predecessors ownership of the
Texas Underlying Properties. In addition, Vess Oil filed a proof
of claim for a statutory lien claim with the bankruptcy court on
behalf of the working interest owners (inclusive of Predecessor
interests), overriding royalty owners and royalty owners. In
2008, as there was no assurance as to the dollar amount, if any,
that would be recovered or the timing of such recovery, an
allowance for doubtful accounts of $0.7 million or 50% of the
total estimated amount owed from Eaglwing, L.P. to Predecessor
for the Texas Underlying Properties, was established as of
December 31, 2008. In addition, an allowance was set up for
the oil purchased from the Kansas Underlying Properties in the
amount of $1.0 million which represents approximately 87%
of June 2008 sales made to Eaglwing, L.P.
Prices. The average price received for the crude oil sold
increased primarily as a result of an increase in the oil price
index on which the sales prices for a majority of the oil
production were based. The average price for natural gas sold
increased as a result of an increase in the natural gas price
index on which the sales prices for a majority of the natural
gas production were based.
Volumes. The increase in overall production sales volumes
during the year ended December 31, 2010 compared to the
year ended December 31, 2009 is primarily attributable to
the drilling of horizontal wells in the Texas Underlying
Properties during the last quarter of 2009 and the year ended
December 31, 2010. One well was drilled in the fourth
quarter of 2009 and four were drilled in year ended
December 31, 2010.
Lease operating expenses. Lease operating expenses
increased from $6.8 million for the year ended
December 31, 2009 to $7.3 million for the year ended
December 31, 2010. This increase was primarily a result of
an increase in general operating expenses and increased costs
due to additional wells being added which was partially offset
by the cost of electronification of wells in the Texas
Underlying Properties. The VOC Operators are replacing the gas
pumping motors in the Texas Underlying Properties with
electronic motors which can be shut off and restarted during the
day as needed. This process also reduces wear on the moving
parts of the well thereby reducing repairs and maintenance costs.
Production and property taxes. Production and property
taxes increased $1.1 million as a result of the increases
in the price of crude oil and in revenues from oil and natural
gas sales, on which these taxes are based.
Comparison
of Results of the Predecessor Underlying Properties for the
Years Ended December 31, 2009 and 2008
Excess of revenues over direct operating expenses for the
Predecessor Underlying Properties was $18.0 million for the
year ended December 31, 2009, compared to
$20.3 million for the year ended December 31, 2008.
The decrease was primarily a result of a decrease in the average
price
66
received for the oil and natural gas sold. This was partially
offset by an increase in production and a decrease in direct
operating expenses.
Revenues. Revenues from oil and natural gas sales
decreased $15.7 million between the periods. This decrease
in revenues was primarily the result of a decrease in the
average price received for crude oil sold from $94.11 per Bbl
for the year ended December 31, 2008 to $55.88 per Bbl for
the year ended December 31, 2009, partially offset by an
18.1 MBbl increase in oil volumes sold. The decrease in
revenues was also the result of a decrease in the average price
received for natural gas sold from $7.86 per Mcf for the year
ended December 31, 2008 to $3.64 per Mcf for the year ended
December 31, 2009, and an 11.6 MMcf decrease in
natural gas volumes sold.
Bad debt expense (recovery). Bad debt expense was
$1.7 million for the year ended December 31, 2008 and
bad debt recovery was $0.7 million for the year ended
December 31, 2009. During the year ended December 31,
2009, recovery was made of the $1.4 million due for the
Texas Underlying Properties. As a result of the recovery, VOC
Sponsor recorded bad debt recovery of $0.7 million, which
reverses the bad debt expense which was recorded for the Texas
properties in 2008.
As publicly reported on July 22, 2008, the revenue
intermediary/crude oil purchaser (Eaglwing L.P.) and its parent
(SemGroup, L.P.) filed voluntary petitions for reorganization
under Chapter 11 of the United States Bankruptcy Code.
During this process, the monies that had been transferred to the
revenue intermediary by certain of Predecessors oil and
gas purchasers for distribution to Predecessor and other working
interest, royalty interest and overriding royalty interest
owners was erroneously retained by the revenue intermediary.
Vess Oil, as primary operator of Predecessors oil and gas
leases, filed suit to recover these funds which were estimated
to be $1.4 million for Predecessors ownership of the
Texas properties. In addition, Vess Oil filed a proof of claim
for a statutory lien claim with the bankruptcy court on behalf
of the working interest owners (inclusive of Predecessor
interests), overriding royalty owners and royalty owners. In
2008, as there was no assurance as to the dollar amount, if any,
that would be recovered or the timing of such recovery, an
allowance for doubtful accounts of $0.7 million, or 50% of
the total estimated amount owed from Eaglwing, L.P. to
Predecessor for the Texas Underlying Properties was established
as of December 31, 2008. In addition, an allowance was set
up for the oil purchased from the Kansas Underlying Properties
in the amount of $1.0 million which represents
approximately 87% of June 2008 sales made to Eaglwing, L.P.
Hedge activity. Hedge activity expense was
$7.8 million for the year ended December 31, 2008
compared to hedge activity income of $1.5 million for the
year ended December 31, 2009. This change was due primarily
to the lower average NYMEX settlement price for the year ended
December 31, 2009 of $61.80 compared to $99.65 for the year
ended December 31, 2008. The weighted average hedge price
for 2009 was $68.51 compared to $70.03 for 2008.
Prices. The average price received for crude oil and
natural gas sold decreased primarily as a result of a decrease
in the oil price and natural gas price indices on which the
sales prices for a majority of the production were based.
Volumes. The increase in oil and natural gas sales
volumes was primarily attributable to the acquisition of various
oil and gas working interests during August 2008.
Production during 2008 reflects 4 months production from
the purchase and production during 2009 includes 12 months
production.
Lease operating expenses. Lease operating expenses
decreased from $7.7 million for the year ended
December 31, 2008 to $6.8 million for the year ended
December 31, 2009. This decrease
67
was the result of the decline in oil prices and the
electronification of wells in the Texas properties.
Production and property taxes. Production and property
taxes decreased $0.9 million as a result of the decrease in
revenues from oil and natural gas sales and decreased property
value on which these taxes are based.
Acquired
Underlying Properties
Comparison
of Results of the Acquired Underlying Properties for the Years
Ended December 31, 2010 and 2009
Excess of revenues over direct operating expenses for the
Acquired Underlying Properties was $16.3 million for the
year ended December 31, 2010, compared to
$11.2 million for the year ended December 31, 2009.
The increase was primarily a result of an increase in the
average price received for the oil and natural gas sold. This
was partially offset by a decrease in oil and natural gas
volumes and an increase in direct operating expenses.
Revenues. Revenues from oil and natural gas sales
increased $5.7 million between the periods. This increase
in revenues was primarily the result of an increase in the
average price received for crude oil sold from $54.27 per Bbl
for the year ended December 31, 2009 to $72.35 per Bbl for
the year ended December 31, 2010, partially offset by a
2.7 MBbl decrease in oil volumes sold. The increase in
revenues was also the result of an increase in the average price
received for natural gas sold from $2.81 per Mcf for the year
ended December 31, 2009 to $3.63 per Mcf for the year
ended December 31, 2010, partially offset by a
45.8 MMcf decrease in natural gas volumes sold.
Prices. The average price received for the crude oil sold
increased primarily as a result of an increase in the oil price
index on which the sales prices for a majority of the oil
production were based. The average price for natural gas sold
increased as a result of an increase in the natural gas price
index on which the sales prices for a majority of the natural
gas production were based.
Volumes. The decrease in overall production sales volumes
during the year ended December 31, 2010 compared to the
year ended December 31, 2009 is primarily attributable to
the natural decline of the producing properties.
Lease operating expenses. Lease operating expenses
increased from $6.0 million for the year ended
December 31, 2009 to $6.4 million for the year ended
December 31, 2010. This increase was primarily a result of
an increase in general operating expenses.
Production and property taxes. Production and property
taxes increased $0.2 million as a result of the increases
in the price of crude oil and in revenues from oil and natural
gas sales, on which these taxes are based.
Comparison
of Results of the Acquired Underlying Properties for the Years
Ended December 31, 2009 and 2008
Excess of revenues over direct operating expenses for the
Acquired Underlying Properties was $11.2 million for the
year ended December 31, 2009, compared to
$21.7 million for the year ended December 31, 2008.
The decrease was primarily a result of a decrease in the average
price received for the oil and natural gas sold. This was
partially offset by an increase in production and a decrease in
direct operating expenses.
68
Revenues. Revenues from oil and natural gas sales
decreased $13.2 million between the periods. This decrease
in revenues was primarily the result of a decrease in the
average price received for crude oil sold from $93.12 per Bbl
for the year ended December 31, 2008 to $54.27 per Bbl for
the year ended December 31, 2009, partially offset by a
9.7 MBbl increase in oil volumes sold. The decrease in
revenues was also the result of a decrease in the average price
received for natural gas sold from $6.94 per Mcf for the year
ended December 31, 2008 to $2.81 per Mcf for the year ended
December 31, 2009, and a 45.9 MMcf decrease in natural
gas volumes sold.
Bad debt expense (recovery). Bad debt expense was
$2.2 million for the year ended December 31, 2008.
During the year ended December 31, 2009 there was no bad
debt expense or recovery.
As publicly reported on July 22, 2008, the crude oil
purchaser (Eaglwing L.P.) and its parent (SemGroup, L.P.) filed
voluntary petitions for reorganization under Chapter 11 of
the United States Bankruptcy Code. An allowance was set up for
the oil purchased from the Acquired Underlying Properties in the
amount of $2.2 million, which represents approximately 87%
of June 2008 sales made to Eaglwing, L.P.
Prices. The average price received for crude oil and
natural gas sold decreased primarily as a result of a decrease
in the oil price and natural gas price indices on which the
sales prices for a majority of the production were based.
Volumes. The small increase in oil and natural gas sales
volumes is primarily attributable to the development program
which was partially offset by the natural decline of the proved
producing properties.
Lease operating expenses. Lease operating expenses
remained stable at $6.0 million for the years ended
December 31, 2008 and 2009.
Production and property taxes. Production and property
taxes decreased $0.4 million as a result of the decrease in
revenues from oil and natural gas sales and decreased property
value on which these taxes are based.
HEDGE
CONTRACTS
The revenues derived from the Underlying Properties depend
substantially on prevailing crude oil prices and, to a lesser
extent, natural gas prices. As a result, commodity prices also
affect the amount of cash flow available for distribution to the
trust unitholders. Lower prices may also reduce the amount of
oil and natural gas that VOC Sponsor can economically produce.
VOC Sponsor sells the oil and natural gas production from the
Underlying Properties under floating market price contracts each
month. VOC Sponsor has entered into the hedge contracts for
2011, 2012 and 2013 to reduce the exposure of the revenues from
oil production from the Underlying Properties to fluctuations in
crude oil prices and to achieve more predictable cash flow.
However, these contracts limit the amount of cash available for
distribution if prices increase above the fixed hedge price. The
hedge contracts consist of fixed price swap contracts that have
been placed with major trading counterparties in whom VOC
Sponsor believes represent minimal credit risks. VOC Sponsor
cannot provide assurance, however, that these trading
counterparties will not become credit risks in the future.
The crude oil swap contracts will settle based on the average of
the settlement price for each commodity business day in the
contract month. In a swap transaction, the counterparty is
required to make a payment to VOC Sponsor for the difference
between the fixed price and the
69
settlement price if the settlement price is below the fixed
price. VOC Sponsor is required to make a payment to the
counterparty for the difference between the fixed price and the
settlement price if the settlement price is above the fixed
price. From January 1, 2011 through December 31, 2013,
VOC Sponsors crude oil price risk management positions in
swap contracts are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Swaps
|
|
|
|
|
Weighted
|
|
|
Volumes
|
|
Average Price
|
Month
|
|
(Bbls)
|
|
(Per Bbl)
|
|
January 2011
|
|
|
|
|
|
|
13,689
|
|
|
$
|
94.90
|
|
February 2011
|
|
|
|
|
|
|
13,621
|
|
|
$
|
94.90
|
|
March 2011
|
|
|
|
|
|
|
20,014
|
|
|
$
|
96.77
|
|
April 2011
|
|
|
|
|
|
|
43,407
|
|
|
$
|
99.99
|
|
May 2011
|
|
|
|
|
|
|
42,828
|
|
|
$
|
99.98
|
|
June 2011
|
|
|
|
|
|
|
42,285
|
|
|
$
|
99.98
|
|
July 2011
|
|
|
|
|
|
|
41,766
|
|
|
$
|
99.97
|
|
August 2011
|
|
|
|
|
|
|
41,271
|
|
|
$
|
99.96
|
|
September 2011
|
|
|
|
|
|
|
40,796
|
|
|
$
|
99.95
|
|
October 2011
|
|
|
|
|
|
|
40,337
|
|
|
$
|
99.94
|
|
November 2011
|
|
|
|
|
|
|
39,898
|
|
|
$
|
99.94
|
|
December 2011
|
|
|
|
|
|
|
39,476
|
|
|
$
|
99.93
|
|
January 2012
|
|
|
|
|
|
|
39,038
|
|
|
$
|
100.84
|
|
February 2012
|
|
|
|
|
|
|
38,631
|
|
|
$
|
100.84
|
|
March 2012
|
|
|
|
|
|
|
38,251
|
|
|
$
|
100.85
|
|
April 2012
|
|
|
|
|
|
|
37,882
|
|
|
$
|
100.85
|
|
May 2012
|
|
|
|
|
|
|
37,523
|
|
|
$
|
100.85
|
|
June 2012
|
|
|
|
|
|
|
37,176
|
|
|
$
|
100.85
|
|
July 2012
|
|
|
|
|
|
|
36,839
|
|
|
$
|
100.86
|
|
August 2012
|
|
|
|
|
|
|
36,513
|
|
|
$
|
100.86
|
|
September 2012
|
|
|
|
|
|
|
36,194
|
|
|
$
|
100.86
|
|
October 2012
|
|
|
|
|
|
|
35,883
|
|
|
$
|
100.86
|
|
November 2012
|
|
|
|
|
|
|
35,562
|
|
|
$
|
100.87
|
|
December 2012
|
|
|
|
|
|
|
35,268
|
|
|
$
|
100.87
|
|
January 2013
|
|
|
|
|
|
|
34,975
|
|
|
$
|
99.01
|
|
February 2013
|
|
|
|
|
|
|
34,686
|
|
|
$
|
99.01
|
|
March 2013
|
|
|
|
|
|
|
34,406
|
|
|
$
|
99.01
|
|
April 2013
|
|
|
|
|
|
|
34,166
|
|
|
$
|
99.01
|
|
May 2013
|
|
|
|
|
|
|
33,959
|
|
|
$
|
99.01
|
|
June 2013
|
|
|
|
|
|
|
33,727
|
|
|
$
|
99.01
|
|
July 2013
|
|
|
|
|
|
|
33,526
|
|
|
$
|
99.01
|
|
August 2013
|
|
|
|
|
|
|
33,317
|
|
|
$
|
99.01
|
|
September 2013
|
|
|
|
|
|
|
33,122
|
|
|
$
|
99.01
|
|
October 2013
|
|
|
|
|
|
|
32,929
|
|
|
$
|
99.01
|
|
November 2013
|
|
|
|
|
|
|
32,741
|
|
|
$
|
99.01
|
|
December 2013
|
|
|
|
|
|
|
32,554
|
|
|
$
|
99.01
|
|
The amounts received by VOC Sponsor from the hedge contract
counterparty upon settlement of the hedge contracts will reduce
the operating expenses related to the Underlying Properties in
calculating the net proceeds. However, if the hedge payments
received by VOC Sponsor under the hedge contracts and other
non-production revenue exceed operating expenses during a
quarterly period, the ability to use such excess amounts to
offset operating expenses will be deferred, with interest
accruing on such amounts at the prevailing prime rate, until the
next quarterly period where the hedge payments and the other
non-production revenue are less than such expenses. In addition,
the aggregate amounts paid by VOC Sponsor on settlement of the
hedge contracts will reduce the amount of net proceeds paid to
the trust. See Computation of net proceeds Net
Profits Interest.
70
PRODUCING
ACREAGE AND WELL COUNTS
For the following data, gross refers to the total
number of wells or acres in which VOC Sponsor owns a working
interest and net refers to gross wells or acres
multiplied by the percentage working interest owned by VOC
Sponsor. Although many of VOC Sponsors wells produce both
oil and natural gas, a well is categorized as an oil well or a
natural gas well based upon the ratio of oil to natural gas
production. The Underlying Properties are interests in
properties located in oil and natural gas producing regions of
Kansas and Texas. The following is a summary of the approximate
acreage of the Underlying Properties at December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Net
|
|
|
|
(Acres)
|
|
|
Kansas
|
|
|
76,217
|
|
|
|
45,326.1
|
|
Texas
|
|
|
23,693
|
|
|
|
16,841.3
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
99,910
|
|
|
|
62,167.4
|
|
|
|
|
|
|
|
|
|
|
The following is a summary of the producing wells on the
Underlying Properties as of December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated Wells
|
|
|
Non-Operated Wells
|
|
|
Total
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Oil
|
|
|
805
|
|
|
|
512.7
|
|
|
|
31
|
|
|
|
7.3
|
|
|
|
836
|
|
|
|
520.0
|
|
Natural gas
|
|
|
31
|
|
|
|
21.1
|
|
|
|
14
|
|
|
|
4.6
|
|
|
|
45
|
|
|
|
25.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
836
|
|
|
|
533.8
|
|
|
|
45
|
|
|
|
11.9
|
|
|
|
881
|
|
|
|
545.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following is a summary of the number of developmental and
exploratory wells drilled by VOC Sponsor on the Underlying
Properties during the last three years. VOC Sponsor drilled two
exploratory wells during the periods presented.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Completed:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil wells
|
|
|
13
|
|
|
|
8.3
|
|
|
|
6
|
|
|
|
4.6
|
|
|
|
7
|
|
|
|
5.3
|
|
Natural gas wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-productive
|
|
|
4
|
|
|
|
2.4
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
1.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
17
|
|
|
|
10.7
|
|
|
|
6
|
|
|
|
4.6
|
|
|
|
9
|
|
|
|
6.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table shows the average sales prices per Bbl of
oil and Mcf of natural gas produced and the production costs and
production and property taxes per Boe for the Underlying
Properties. Average prices do not include the effect of hedge
activity.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
93.67
|
|
|
$
|
55.16
|
|
|
$
|
73.71
|
|
Natural gas (per Mcf)
|
|
$
|
7.46
|
|
|
$
|
3.31
|
|
|
$
|
4.77
|
|
Lease operating expense (per Boe)
|
|
$
|
16.54
|
|
|
$
|
15.06
|
|
|
$
|
14.76
|
|
Production and property taxes (per Boe)
|
|
$
|
5.00
|
|
|
$
|
3.32
|
|
|
$
|
4.45
|
|
71
OPERATING
AREAS
The following table summarizes the estimated proved reserves by
operating area attributable to the Underlying Properties
according to the reserve reports, the corresponding pre-tax
PV-10 value
as of December 31, 2010 and the average net production
attributable to the Underlying Properties for the year ended
December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
Proved Reserves (1)
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of
|
|
|
2010 Average
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
% of
|
|
|
Pre-Tax
|
|
|
Pre-Tax
|
|
|
Net
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Total
|
|
|
PV-10%
|
|
|
PV-10%
|
|
|
Production
|
|
Operating Area
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBoe)
|
|
|
Reserves
|
|
|
Value
|
|
|
Value
|
|
|
(Boe per day)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
Kansas (188 Fields)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fairport
|
|
|
889
|
|
|
|
0
|
|
|
|
889
|
|
|
|
6.5
|
%
|
|
$
|
17,334
|
|
|
|
6.5
|
%
|
|
|
123
|
|
Marcotte
|
|
|
474
|
|
|
|
0
|
|
|
|
474
|
|
|
|
3.5
|
%
|
|
|
10,638
|
|
|
|
4.0
|
%
|
|
|
94
|
|
Chase-Silica
|
|
|
434
|
|
|
|
0
|
|
|
|
434
|
|
|
|
3.2
|
%
|
|
|
8,075
|
|
|
|
3.0
|
%
|
|
|
85
|
|
Bindley
|
|
|
365
|
|
|
|
0
|
|
|
|
365
|
|
|
|
2.7
|
%
|
|
|
7,097
|
|
|
|
2.6
|
%
|
|
|
53
|
|
Moore-Johnson
|
|
|
351
|
|
|
|
0
|
|
|
|
351
|
|
|
|
2.6
|
%
|
|
|
6,853
|
|
|
|
2.6
|
%
|
|
|
52
|
|
Griston SW
|
|
|
121
|
|
|
|
0
|
|
|
|
121
|
|
|
|
0.9
|
%
|
|
|
4,164
|
|
|
|
1.6
|
%
|
|
|
36
|
|
Wesley
|
|
|
169
|
|
|
|
0
|
|
|
|
169
|
|
|
|
1.2
|
%
|
|
|
3,979
|
|
|
|
1.5
|
%
|
|
|
34
|
|
Mueller
|
|
|
175
|
|
|
|
0
|
|
|
|
175
|
|
|
|
1.3
|
%
|
|
|
3,947
|
|
|
|
1.5
|
%
|
|
|
32
|
|
Codell
|
|
|
145
|
|
|
|
0
|
|
|
|
145
|
|
|
|
1.1
|
%
|
|
|
3,757
|
|
|
|
1.4
|
%
|
|
|
65
|
|
Adell Northwest
|
|
|
104
|
|
|
|
0
|
|
|
|
104
|
|
|
|
0.8
|
%
|
|
|
2,211
|
|
|
|
0.8
|
%
|
|
|
19
|
|
Dopita
|
|
|
110
|
|
|
|
0
|
|
|
|
110
|
|
|
|
0.8
|
%
|
|
|
2,157
|
|
|
|
0.8
|
%
|
|
|
19
|
|
Yaege
|
|
|
110
|
|
|
|
0
|
|
|
|
110
|
|
|
|
0.8
|
%
|
|
|
2,153
|
|
|
|
0.8
|
%
|
|
|
19
|
|
Spivey-Grabs-Basil
|
|
|
59
|
|
|
|
891
|
|
|
|
207
|
|
|
|
1.5
|
%
|
|
|
2,075
|
|
|
|
0.8
|
%
|
|
|
39
|
|
Other
|
|
|
3,029
|
|
|
|
2,660
|
|
|
|
3,473
|
|
|
|
25.3
|
%
|
|
|
60,333
|
|
|
|
22.5
|
%
|
|
|
863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Kansas Total
|
|
|
6,535
|
|
|
|
3,550
|
|
|
|
7,127
|
|
|
|
52.0
|
%
|
|
$
|
134,772
|
|
|
|
50.2
|
%
|
|
|
1,536
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas (3 Fields)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Kurten
|
|
|
4,054
|
|
|
|
3,398
|
|
|
|
4,620
|
|
|
|
33.7
|
%
|
|
|
91,880
|
|
|
|
34.2
|
%
|
|
|
695
|
|
Sand Flat
|
|
|
927
|
|
|
|
0
|
|
|
|
927
|
|
|
|
6.8
|
%
|
|
|
23,067
|
|
|
|
8.6
|
%
|
|
|
169
|
|
Hitts Lake North
|
|
|
1,026
|
|
|
|
1
|
|
|
|
1,026
|
|
|
|
7.5
|
%
|
|
|
18,564
|
|
|
|
6.9
|
%
|
|
|
147
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas Total
|
|
|
6,007
|
|
|
|
3,399
|
|
|
|
6,573
|
|
|
|
48.0
|
%
|
|
$
|
133,511
|
|
|
|
49.8
|
%
|
|
|
1,011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
12,542
|
|
|
|
6,949
|
|
|
|
13,700
|
|
|
|
100
|
%
|
|
$
|
268,283
|
|
|
|
100.0
|
%
|
|
|
2,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
In accordance with the rules and
regulations promulgated by the SEC, the proved reserves
presented above were determined using the twelve month
unweighted arithmetic average of the
first-day-of-the-month
price for the period from January 1, 2010 through
December 1, 2010, without giving effect to any hedge
transactions, and were held constant for the life of the
properties. This yielded a price for oil of $79.43 per barrel
and a price for natural gas of $4.37 per MMBtu.
|
|
(2)
|
|
PV-10
is the present value of estimated future net revenue to be
generated from the production of proved reserves, discounted
using an annual discount rate of 10%, calculated without
deducting future income taxes. Standardized measure of
discounted net cash flows is calculated the same as
PV-10 except
that it deducts future income taxes. Because the trust bears no
federal tax expense and taxable income is passed through to the
unitholders of the trust, no provision for federal or state
income taxes is included in the summary reserve reports and
therefore the standardized measure of discounted future net cash
flows attributable to the Underlying Properties is equal to the
pre-tax
PV-10 value.
PV-10 may not be considered a GAAP financial measure as defined
by the SEC and is derived from the standardized measure of
discounted future net cash flows, which is the most directly
comparable GAAP financial measure. The pre-tax
PV-10 value
and the standardized measure of discounted future net cash flows
do not purport to present the fair value of the oil and natural
gas reserves attributable to Underlying Properties.
|
The Underlying Properties are located in Kansas and Texas in
areas characterized by long production histories and by several
additional development opportunities, which may help to diminish
natural declines in production from the Underlying Properties.
See Planned development and workover
program for a summary of VOC Sponsors development
plans. Based on the reserve reports, approximately 92% of the
future production from the Underlying Properties is expected to
be oil and approximately 8% is expected to be natural gas.
72
Kansas. As of December 31, 2010, proved
reserves attributable to the portion of the Kansas Underlying
Properties were approximately 7.1 MMBoe and are located in
three primary areas the Central Kansas Uplift,
Western Kansas and South Central Kansas. As of December 31,
2010, the Kansas Underlying Properties covered approximately
76,217 gross acres (45,326.1 net acres) and included
188 fields. As of December 31, 2010, the VOC Operators
operated 97% of the total proved reserves attributable to the
Kansas Underlying Properties based on
PV-10 value.
The major fields in the Central Kansas Uplift include Fairport
Field, Chase-Silica Field and Marcotte Field, all of which are
producing primarily from the Arbuckle and Lansing Kansas City
zones. The major fields in Western Kansas include the Bindley,
Moore-Johnson and Wesley fields, which are producing primarily
from the Mississippian, Morrow, Lansing Kansas City and Cherokee
zones. The major fields in South Central Kansas include the
Gerberding, Spivey Grabs and Alford fields, which are producing
primarily from the Mississippian, Simpson and Lansing Kansas
City zones. During the year ended December 31, 2010, the
average net production for the Kansas Underlying Properties was
approximately 1,536 Boe per day, which represented 4.3% of total
fluid production (water production averaged 95.7%).
The following table summarizes VOC Sponsors interests in
the major fields in Kansas as of December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
No. of Wells
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Operated/
|
|
|
|
|
|
|
|
|
|
Average
|
|
Net
|
|
|
Non-
|
|
|
|
|
|
Productive
|
|
Gross/
|
|
Working
|
|
Revenue
|
Field
|
|
Operated
|
|
Operator
|
|
County
|
|
Zones
|
|
Net Acres
|
|
Interest
|
|
Interest
|
|
Fairport
|
|
59/5
|
|
Vess Oil, Counts Kellis
|
|
Russell
|
|
Arbuckle, LKC, Dodge, Reagan, Wabaunsee
|
|
|
1,320/963.5
|
|
|
|
73.6
|
%
|
|
|
63.3
|
%
|
Marcotte
|
|
25/0
|
|
Vess Oil
|
|
Rooks
|
|
Arbuckle, LKC
|
|
|
1,760/1,676.7
|
|
|
|
95.4
|
%
|
|
|
79.5
|
%
|
Chase-Silica
|
|
48/0
|
|
Vess Oil, Davis Petroleum Inc, L D Drilling
|
|
Barton, Rice, Stafford
|
|
Arbuckle, LKC
|
|
|
2,760/2,038.1
|
|
|
|
82.0
|
%
|
|
|
67.0
|
%
|
Bindley
|
|
18/0
|
|
Vess Oil
|
|
Hodgeman
|
|
Mississippian
|
|
|
1,360/1,166.0
|
|
|
|
85.5
|
%
|
|
|
73.8
|
%
|
Moore-Johnson
|
|
10/0
|
|
Vess Oil
|
|
Greeley
|
|
Morrow
|
|
|
1,621/1,292.3
|
|
|
|
79.7
|
%
|
|
|
64.6
|
%
|
Griston SW
|
|
7/0
|
|
Vess Oil
|
|
Scott
|
|
LKC, Mississippian
|
|
|
160/82.7
|
|
|
|
50.3
|
%
|
|
|
40.2
|
%
|
Wesley
|
|
5/0
|
|
Davis Petroleum Inc, L D Drilling
|
|
Ness
|
|
Mississippian
|
|
|
480/444.5
|
|
|
|
92.2
|
%
|
|
|
80.1
|
%
|
Mueller
|
|
14/0
|
|
Vess Oil,
L D Drilling
|
|
Stafford
|
|
Arbuckle, Conglomerate, LKC
|
|
|
640/497.0
|
|
|
|
85.2
|
%
|
|
|
69.4
|
%
|
Codell
|
|
3/0
|
|
Vess Oil
|
|
Rooks
|
|
Arbuckle, LKC
|
|
|
106/100.6
|
|
|
|
95.0
|
%
|
|
|
76.5
|
%
|
Adell Northwest
|
|
7/0
|
|
Vess Oil
|
|
Decatur
|
|
LKC
|
|
|
800/797.6
|
|
|
|
99.7
|
%
|
|
|
86.7
|
%
|
Dopita
|
|
9/0
|
|
Vess Oil
|
|
Rooks
|
|
Arbuckle, Toronto
|
|
|
380/357.1
|
|
|
|
93.5
|
%
|
|
|
81.8
|
%
|
Yaege
|
|
26/0
|
|
Vess Oil
|
|
Riley
|
|
Hunton
|
|
|
2,098/1,094.1
|
|
|
|
52.2
|
%
|
|
|
45.6
|
%
|
Spivey-Grabs-Basil
|
|
10/1
|
|
Vess Oil
|
|
Harper, Kingman
|
|
Mississippian
|
|
|
1,470/1,123.7
|
|
|
|
86.6
|
%
|
|
|
72.5
|
%
|
Texas. As of December 31, 2010, proved reserves
attributable to the Texas Underlying Properties were
approximately 6.6 MMBoe and are located in two
areas Central Texas and East Texas. As of
December 31, 2010, the Texas Underlying Properties covered
approximately 23,693 gross acres (16,841.3 acres) and
included three fields. As of December 31, 2010, the VOC
Operators operated approximately 99% of the total proved
reserves attributable to the Texas Underlying Properties based
on PV-10
value.
Central Texas production is attributable to the Kurten Woodbine
Unit, which is producing primarily from the Woodbine Interval
and Buda Georgetown zones. East Texas properties include
73
the Sand Flat field and Hitts Lake North field, each of which is
producing primarily from the Paluxy and Chisum zones. During the
year ended December 31, 2010, the average net production
for the Texas Underlying Properties was approximately 1,011 Boe
per day, which represented 9.4% of total fluid production (water
production averaged 90.6%).
The following table summarizes VOC Sponsors interests in
the major fields in Texas as of December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
No. of Wells
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Operated/
|
|
|
|
|
|
|
|
|
|
Average
|
|
Net
|
|
|
Non-
|
|
|
|
|
|
Productive
|
|
Gross/
|
|
Working
|
|
Revenue
|
Field
|
|
Operated
|
|
Operator
|
|
County
|
|
Zones
|
|
Net Acres
|
|
Interest
|
|
Interest
|
|
Kurten
|
|
108/7
|
|
Vess Oil, CML,
Ogden Resources
|
|
Brazos
|
|
Austin Chalk,
Woodbine
Sand, Buda-
Georgetown
|
|
|
20,908/15,280.4
|
|
|
|
72.7
|
%
|
|
|
58.6
|
%
|
Sand Flat
|
|
18/1
|
|
Vess Oil, Carrizo
|
|
Smith
|
|
Paluxy, Rodessa
|
|
|
2,579/1,418.0
|
|
|
|
54.9
|
%
|
|
|
48.1
|
%
|
Hitts Lake North
|
|
5/0
|
|
Vess Oil
|
|
Smith
|
|
Paluxy
|
|
|
206/142.9
|
|
|
|
59.6
|
%
|
|
|
52.5
|
%
|
PLANNED
DEVELOPMENT AND WORKOVER PROGRAM
The primary goals of VOC Sponsors development and workover
program have been to develop proved undeveloped reserves, manage
workovers and minimize the natural decline in production in
areas in which it operates. However, VOC Sponsor is not
obligated to undertake any development activities, so any
drilling and completing activities will be subject to the
reasonable discretion of VOC Sponsor. No assurance can be given,
however, that any development well will produce in commercially
paying quantities or that the characteristics of any development
well will match the characteristics of VOC Sponsors
existing wells or VOC Sponsors historical drilling success
rate. With respect to the Underlying Properties, VOC Sponsor
expects, but is not obligated, to implement the following
development strategies specific to each of its primary operating
areas.
|
|
|
|
|
Kansas. VOC Sponsors historical development
and workover program for the Kansas Underlying Properties has
included recompleting certain existing wells, drilling infill
development wells, conducting
3-D seismic
surveys, completing workovers and applying new production
technologies. VOC Sponsor intends to continue this program with
respect to the Kansas Underlying Properties, and expects to
incur total development expenditures for these properties
through December 31, 2015 of approximately
$3.2 million, of which VOC Sponsor contemplates spending
approximately $2.5 million to drill and complete
13 vertical wells. The remaining approximate
$0.7 million is expected to be used for recompletions and
workovers of 12 wells.
|
|
|
|
Texas. VOC Sponsors historical development
program for the Texas Underlying Properties has included
recompleting certain existing wells, drilling infill development
wells, completing workovers and applying new production
technologies. In 2009, after an extensive review of horizontal
development drilling in the area, VOC Sponsor commenced drilling
horizontal wells in the Kurten Woodbine Unit in order to
accelerate the development of proved undeveloped reserves. VOC
Sponsor has successfully completed each of its first four
horizontal wells to the Woodbine C sand in this area with
average lateral lengths of approximately 3,000 feet. VOC
Sponsor intends to continue developing the Woodbine C sand
underlying the Kurten Woodbine Unit, utilizing horizontal wells
completed with multiple fracture stimulations together with
recompletions of existing vertical wellbores into additional pay
intervals. VOC Sponsor expects total development expenditures
for the Texas Underlying Properties through December 31,
2015 to be approximately $24.0 million. Of this total, VOC
Sponsor
|
74
|
|
|
|
|
contemplates spending approximately $22.5 million to drill
and complete 11 horizontal wells in the Woodbine C sand. The
remaining approximate $1.5 million is expected to be used
for recompletions and workovers of 12 Woodbine vertical wells to
additional Woodbine sands and seven existing wells in the Sand
Flat Unit.
|
The trust is not directly obligated to pay any portion of any
development expenditures made with respect to the Underlying
Properties; however, development expenditures made by VOC
Sponsor with respect to the Underlying Properties will be
included among the costs that will be deducted from the gross
proceeds in calculating cash distributions attributable to the
Net Profits Interest. As a result, the trust will indirectly
bear an 80% share of any development expenditures made with
respect to the Underlying Properties (subject to certain
limitations near the end of the term of the trust, as described
below). Accordingly, higher or lower development expenditures
will, in general, directly decrease or increase, respectively,
the cash received by the trust. In making development
expenditure determinations, VOC Sponsor will attempt to balance
the impact of the development expenditures on current cash
distributions to the trust unitholders with the longer term
benefits of increased oil and natural gas production expected to
result from the development expenditure. In addition, VOC
Sponsor may establish a capital reserve of up to a maximum of
$1.0 million in the aggregate at any given time.
VOC Sponsor, as the designated operator of the Underlying
Properties, is entitled to make all determinations related to
development expenditures with respect to the Underlying
Properties, and there are no limitations on the amount of
development expenditures that VOC Sponsor may incur with respect
to the Underlying Properties, except as described below. VOC
Sponsor is required under the applicable Net Profits Interest
conveyance to use commercially reasonable efforts to cause the
operators of the Underlying Properties to operate these
properties as would a reasonably prudent operator acting with
respect to its own properties (without regard to the existence
of the Net Profits Interest). As the trust unitholders would not
be expected to fully realize the benefits of development
expenditures made with respect to the Underlying Properties
which occur near the end of the term of the trust, during each
twelve-month period beginning on the later to occur of
(1) December 31, 2027 and (2) the time when
9.8 MMBoe have been produced from the Underlying Properties
and sold (which is the equivalent of 7.8 MMBoe in respect
of the Net Profits Interest), development expenditures that may
be included among the costs that will be taken into account in
calculating net proceeds attributable to the Net Profits
Interest will be limited to the average annual development
expenditures incurred by VOC Sponsor during the preceding three
years, as increased by 2.5% to account for expected increased
costs due to inflation. See Computation of net
proceeds Net Profits Interest.
RESERVE
REPORTS
Technologies. The reserve reports were prepared
using production performance decline curve analyses and analogy
performance to determine the reserves of the Underlying
Properties in Kansas and Texas. After estimating the reserves of
each proved developed property, a reasonable level of certainty
exists with respect to the reserves which can be expected from
individual undeveloped wells in the fields. The consistency of
reserves attributable to the proved developed producing wells in
fields in Kansas and Texas, which cover a wide area, further
supports proved undeveloped classification.
The proved undeveloped locations in Underlying Properties are
direct offsets of other producing wells.
3-D seismic
data has been used to target well placement for most proved
undeveloped locations in Kansas so as to avoid encountering
significant unfavorable faults or structural features. Data from
both VOC Sponsor and offset operators with which VOC Sponsor has
exchanged technical data demonstrate a consistency in this
resource play over an area much larger than the Underlying
Properties. In addition, information from other producing wells
has
75
also been used to analyze reservoir properties such as porosity,
thickness, and stratigraphic conformity.
Estimates of reserves may also be obtained using extensive
pressure and temperature data, production data, fluid analysis
and knowledge of the nature of a reservoir, and complex
calculations on computer models processing such data. Reserve
estimates obtained by this method generally provide a degree of
certainty that is directly related to the complexity of the
reservoir and the quality and quantity of the data available.
Reserve engineers may also analyze physical measurements of rock
and fluid properties to calculate volumes of hydrocarbons in
place. The degree of accuracy of such analysis is directly
related to the quality of the rock, the subsurface control and
the complexity of the reservoir.
Internal controls. Cawley, Gillespie, &
Associates, Inc., the independent petroleum engineering
consultant, estimated all of the proved reserve information for
the Underlying Properties in this registration statement in
accordance with appropriate engineering, geologic, and
evaluation principles and techniques that are in accordance with
practices generally accepted in the petroleum industry, and
definitions and guidelines established by the SEC. These
reserves estimation methods and techniques are widely taught in
university petroleum curricula and throughout the
industrys ongoing training programs. Although these
engineering, geologic, and evaluation principles and techniques
are based upon established scientific concepts, the application
of such principles and techniques involves extensive judgment
and is subject to changes in existing knowledge and technology,
economic conditions and applicable statutory and regulatory
provisions. These same industry-wide applied techniques are used
in determining estimated reserve quantities. The technical
persons responsible for preparing the reserves estimates
presented herein meet the requirements regarding qualifications,
independence, objectivity and confidentiality set forth in the
Society of Petroleum Engineers Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserves Information.
Vice President of Operations of Vess Oil, William R. Horigan,
consults regularly with Cawley, Gillespie during the reserve
estimation process to review properties, assumptions, and any
new data available. Additionally, VOC Sponsors senior
management reviewed and approved all Cawley, Gillespie summary
reserve reports contained herein.
The independent engineering reserve estimates are reviewed by
Mr. Horigan, who has a Bachelor of Science in Chemical
Engineering, is a member of the Society of Petroleum Engineers
and served on the Executive Board for the Wichita Section. He is
also a member of the Producers Advisory Board of the KU Tertiary
Oil Recovery Project and a member of the Petroleum Technology
Transfer Council of the North Mid-Continent Region. He has over
35 years of oil and gas industry experience in drilling and
completions, reservoir engineering, and acquisitions and
divestitures.
Cawley, Gillespie & Associates, Inc. estimated oil and
natural gas reserves attributable to VOC Brazos and KEP and the
Net Profit Interest as of December 31, 2010. Numerous
uncertainties are inherent in estimating reserve volumes and
values, and the estimates are subject to change as additional
information becomes available. The reserves actually recovered
and the timing of production of the reserves may vary
significantly from the original estimates.
The discounted estimated future net revenues presented below
were prepared using the twelve month unweighted arithmetic
average of the
first-day-of-the-month
price for the period from January 1, 2010 through
December 1, 2010, without giving effect to any derivative
transactions, and were held constant for the life of the
properties. This yielded a price for oil of $79.43 per barrel
and a price for natural gas of $4.37 per MMBtu. Oil equivalents
in the table are the sum of the Bbls of oil and the Boe of the
stated Mcfs of natural gas, calculated on the basis that six
Mcfs of natural gas is the energy equivalent of one Bbl of oil.
The estimated future net revenues attributable to the Net
Profits Interest as of December 31, 2010 are net of the
trusts
76
proportionate share of all estimated costs deducted from revenue
pursuant to the terms of the conveyance creating the Net Profits
Interest and include only the reserves attributable to the
Underlying Properties that are expected to be produced during
the term of the trust. Because oil and natural gas prices are
influenced by many factors, use of the twelve month unweighted
arithmetic average of the
first-day-of-the-month
price for the period from January 1, 2010 through
December 1, 2010, as required by the SEC, may not be the
most accurate basis for estimating future revenues of reserve
data. Future net cash flows are discounted at an annual rate of
10%. There is no provision for federal income taxes with respect
to the future net cash flows attributable to the Underlying
Properties or the Net Profits Interest because future net
revenues are not subject to taxation at the VOC Sponsor or trust
level.
VOC Brazos natural gas realized price is adjusted for BTU
content and natural gas liquids (NGLs) sales through
percent-of-proceeds
(POP) contracts. VOC Brazos has natural gas production with high
BTU content. Furthermore, VOC Brazos has several POP contracts
where the produced natural gas is sent to a gas plant and NGLs
are removed from the stream. VOC Brazos is then paid for its
share of the processed natural gas sales and a percentage of the
NGL sales. The revenue VOC Brazos receives for NGLs is added to
the natural gas revenue in the pricing calculation and is at
pricing levels that exceed equivalent natural gas sales. VOC
Brazos sold 34,321 Bbls of NGLs for the year ended
December 31, 2010.
Therefore, in the reserve report, two adjustments are made to
the assumed Henry Hub gas price on certain properties, including
the Kurten Woodbine Unit: (1) BTU adjustment factor of
1.3218 and (2) POP factor of 1.2376. The following table
provides an example calculation of the Realized Price ($6.27 per
Mcf) from the assumed Henry Hub gas price ($3.833 per MMBTU):
|
|
|
|
|
Assumed HHUB Price ($/MMBTU)
|
|
$
|
3.833
|
|
x BTU Adjustment Factor
|
|
|
1.3218
|
|
|
|
|
|
|
|
|
$
|
5.066
|
|
x POP Factor
|
|
|
1.2376
|
|
|
|
|
|
|
Realized Price ($/Mcf)
|
|
$
|
6.270
|
|
|
|
|
|
|
Proved reserves of Underlying Properties. The
following table sets forth, as of December 31, 2010,
certain estimated proved reserves, estimated future net revenues
and the discounted present value thereof attributable to the
Underlying Properties and the Net Profits Interest, in each case
derived from the reserve reports. Summaries of the reserve
reports are included in Annexes A, B, and C to this prospectus.
|
|
|
|
|
|
|
|
|
|
|
Underlying
|
|
Net Profits
|
|
|
Properties (1)
|
|
Interest (2)
|
|
|
(In thousands, except MBbls, MMcf and MBoe amounts)
|
|
Proved Reserves:
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
12,542
|
|
|
|
7,712
|
|
Natural gas (MMcf)
|
|
|
6,949
|
|
|
|
4,819
|
|
Oil equivalents (MBoe)
|
|
|
13,700
|
|
|
|
8,515
|
|
Future net revenues
|
|
$
|
569,829
|
|
|
$
|
379,296
|
|
Discounted estimated future net revenues (3)
|
|
$
|
268,283
|
|
|
$
|
208,552
|
|
Standardized measure (3)(4)
|
|
$
|
268,283
|
|
|
$
|
208,552
|
|
|
|
|
(1)
|
|
Reserve volumes and estimated
future net revenues for Underlying Properties reflect volumes
and revenues attributable to VOC Sponsors net interests in
the properties comprising the Underlying Properties.
|
77
|
|
|
(2)
|
|
Reflects 80% of proved reserves
attributable to the Underlying Properties expected to be
produced during the term of the trust based on the reserve
reports.
|
|
(3)
|
|
The present values of future net
revenues for the Underlying Properties and the Net Profits
Interest were determined using a discount rate of 10% per annum.
As of December 31, 2010, VOC Sponsor was structured as a
limited partnership. Accordingly, no provision for federal or
state income taxes has been provided because taxable income was
passed through to the partners of VOC Sponsor. Therefore, the
standardized measure of the Underlying Properties is equal to
the PV-10
value, which totaled $268.3 million as of December 31,
2010.
|
|
(4)
|
|
Standardized measure of discounted
net cash flows is calculated the same as
PV-10 except
that it deducts future income taxes. Because VOC Sponsor bears
no federal income tax expense and taxable income is passed
through to the unitholders of the trust, no provision for
federal or state income taxes is included in the reserve reports
and therefore the standardized measure of discounted future net
cash flows attributable to the Underlying Properties is equal to
the pretax
PV-10 value.
PV-10 may
not be considered a GAAP financial measure as defined by the SEC
and is derived from the standardized measure of discounted
future net cash flows, which is the most directly comparable
GAAP financial measure. The pre-tax
PV-10 value
and the standardized measure of discounted future net cash flows
do not purport to present the fair value of the oil and natural
gas reserves attributable to Underlying Properties.
|
Information concerning historical changes in net proved reserves
attributable to the Underlying Properties is contained in the
unaudited supplemental information contained elsewhere in this
prospectus. VOC Sponsor has not filed reserve estimates covering
the Underlying Properties with any other federal authority or
agency.
78
The following table summarizes the changes in estimated proved
reserves of the Underlying Properties for the periods indicated.
The data presents the proved reserves attributable to the
Underlying Properties for the economic life of such properties
and is not limited to the term of the trust. The data is
presented assuming VOC Sponsor owns all the Underlying
Properties as of December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Equivalents
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBoe)
|
|
|
Proved Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
|
11,993
|
|
|
|
7,380
|
|
|
|
13,223
|
|
Revisions of previous estimates
|
|
|
(1,834
|
)
|
|
|
(151
|
)
|
|
|
(1,859
|
)
|
Purchases of minerals in place
|
|
|
222
|
|
|
|
378
|
|
|
|
285
|
|
Extensions and discoveries
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
Production
|
|
|
(704
|
)
|
|
|
(750
|
)
|
|
|
(829
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
9,678
|
|
|
|
6,857
|
|
|
|
10,821
|
|
Revisions of previous estimates
|
|
|
2,640
|
|
|
|
173
|
|
|
|
2,668
|
|
Purchases of minerals in place
|
|
|
129
|
|
|
|
126
|
|
|
|
150
|
|
Extensions and discoveries
|
|
|
215
|
|
|
|
|
|
|
|
215
|
|
Production
|
|
|
(732
|
)
|
|
|
(693
|
)
|
|
|
(847
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
11,930
|
|
|
|
6,463
|
|
|
|
13,007
|
|
Revisions of previous estimates
|
|
|
1,429
|
|
|
|
1,165
|
|
|
|
1,623
|
|
Production
|
|
|
(817
|
)
|
|
|
(679
|
)
|
|
|
(930
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2010
|
|
|
12,542
|
|
|
|
6,949
|
|
|
|
13,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
|
11,416
|
|
|
|
7,122
|
|
|
|
12,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
8,952
|
|
|
|
6,562
|
|
|
|
10,046
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
10,567
|
|
|
|
5,813
|
|
|
|
11,536
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2010
|
|
|
10,971
|
|
|
|
5,844
|
|
|
|
11,945
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
|
577
|
|
|
|
258
|
|
|
|
620
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
726
|
|
|
|
295
|
|
|
|
775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
1,363
|
|
|
|
650
|
|
|
|
1,471
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2010
|
|
|
1,570
|
|
|
|
1,106
|
|
|
|
1,754
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
79
The Standardized Measure for the periods indicated is presented
assuming the KEP Acquisition had taken place as of
December 31, 2008.
STANDARDIZED
MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
FROM PROVED OIL AND GAS RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Future cash inflows
|
|
$
|
415,644
|
|
|
$
|
692,391
|
|
|
$
|
967,223
|
|
Future costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(221,761
|
)
|
|
|
(295,606
|
)
|
|
|
(370,260
|
)
|
Development
|
|
|
(12,501
|
)
|
|
|
(25,317
|
)
|
|
|
(27,134
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
181,382
|
|
|
|
371,468
|
|
|
|
569,829
|
|
Less 10% discount factor
|
|
|
(86,766
|
)
|
|
|
(192,778
|
)
|
|
|
(301,546
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
94,616
|
|
|
$
|
178,690
|
|
|
$
|
268,283
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets for the changes in Standardized Measure
for the periods indicated and is presented assuming the KEP
Acquisition had taken place as of December 31, 2008.
CHANGES
IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED OIL AND GAS RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Standardized measure at beginning of year
|
|
$
|
339,972
|
|
|
$
|
94,616
|
|
|
$
|
178,690
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(53,630
|
)
|
|
|
(27,032
|
)
|
|
|
(45,562
|
)
|
Net changes in price and production costs
|
|
|
(259,275
|
)
|
|
|
55,081
|
|
|
|
74,089
|
|
Extensions, discoveries and improved recovery, net of future
production, and development costs
|
|
|
42
|
|
|
|
8,592
|
|
|
|
|
|
Changes in estimated future development costs
|
|
|
(2,727
|
)
|
|
|
(14,504
|
)
|
|
|
(16,114
|
)
|
Development costs incurred during the period which reduce future
development costs
|
|
|
53
|
|
|
|
2,700
|
|
|
|
7,733
|
|
Revisions of quantity estimates
|
|
|
(18,877
|
)
|
|
|
42,950
|
|
|
|
31,795
|
|
Accretion of discount
|
|
|
33,997
|
|
|
|
9,462
|
|
|
|
17,869
|
|
Purchase of reserves in place
|
|
|
4,832
|
|
|
|
3,150
|
|
|
|
|
|
Change in production rates and other
|
|
|
50,229
|
|
|
|
3,675
|
|
|
|
19,783
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure at end of year
|
|
$
|
94,616
|
|
|
$
|
178,690
|
|
|
$
|
268,283
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SALE AND
ABANDONMENT OF UNDERLYING PROPERTIES
VOC Sponsor and any transferee of an Underlying Property will
have the right to abandon its interest in any well or property
if it reasonably believes a well or property ceases to produce
or is not capable of producing in commercially paying
quantities. To reduce the potential conflict of interest between
VOC Sponsor and the trust in determining whether a well is
capable of producing in commercially paying quantities, VOC
Sponsor is required under the applicable conveyance to use
commercially reasonable efforts to cause the operators of the
Underlying Properties to operate these properties as would a
reasonably prudent operator acting with respect
80
to its own properties (without regard to the existence of the
Net Profits Interest). Upon termination of the lease, the
portion of the Net Profits Interest relating to the abandoned
property will be extinguished. For the years ended
December 31, 2008, 2009 and 2010, VOC Sponsor plugged and
abandoned six, 15 and 27 wells, respectively, located on
leases within the Underlying Properties based on its
determination that such wells could no longer produce oil or
natural gas in commercially economic quantities. The number of
wells abandoned during this time period accounted for less than
3.13% of the producing wells attributable to the Underlying
Properties.
VOC Sponsor generally may sell all or a portion of its interests
in the Underlying Properties, subject to and burdened by the Net
Profits Interest, without the consent of the trust unitholders.
In addition, VOC Sponsor may, without the consent of the trust
unitholders, require the trust to release the Net Profits
Interest associated with any lease that accounts for less than
or equal to 0.25% of the total production from the Underlying
Properties in the prior 12 months and provided that the Net
Profits Interest covered by such releases cannot exceed, during
any 12-month
period, an aggregate fair market value to the trust of $500,000.
These releases will be made only in connection with a sale by
VOC Sponsor to a non-affiliate of the relevant Underlying
Properties and are conditioned upon the trust receiving an
amount equal to the fair value to the trust of such Net Profits
Interest. Any net sales proceeds paid to the trust are
distributable to trust unitholders for the quarter in which they
are received. VOC Sponsor has not identified for sale any of the
Underlying Properties.
MARKETING
AND POST-PRODUCTION SERVICES
Pursuant to the terms of the conveyance creating the Net Profits
Interest, VOC Sponsor will have the responsibility to market, or
cause to be marketed, the oil and natural gas production
attributable to the Underlying Properties. The terms of the
conveyance creating the Net Profits Interest do not permit VOC
Sponsor to charge any marketing fee when determining the net
proceeds upon which the Net Profits Interest will be calculated.
As a result, the net proceeds to the trust from the sales of oil
and natural gas production from the Underlying Properties will
be determined based on the same price that VOC Sponsor receives
for oil and natural gas production attributable to VOC
Sponsors remaining interest in the Underlying Properties.
Texas is a mature oil producing state with a well-developed
crude oil refining, transportation and marketing infrastructure.
According to the Texas Railroad Commission, more than 5,000
operators reported aggregate oil production of approximately
349 million barrels for the state of Texas during 2010.
There were 27 operating oil refineries located in Texas in 2010
with combined capacity to refine over 4.6 million barrels
of oil per day. With oil production in the state of Texas
averaging approximately 1 million barrels of oil per day,
Texas refineries are net importers of crude oil. As a result,
oil producers in Texas benefit from competitive marketing
conditions for their oil production as a result of the high
demand from the crude oil marketing companies and refineries
located in Texas.
Kansas is a mature oil producing state with a well-developed
transportation infrastructure for crude oil transportation and
marketing. According to the Kansas Geological Society, more than
2,100 operators reported aggregate oil production of
approximately 34 million barrels for the state of Kansas
for the first ten months of 2010. Kansas is home to three oil
refineries located in McPherson, El Dorado and Coffeyville,
Kansas. These refineries have combined capacity to refine over
300,000 barrels of oil per day. With oil production in the
state of Kansas averaging approximately 100,000 barrels of
oil per day, Kansas is a net importer of crude oil. As a result,
Kansas operators benefit from the competitive marketing
conditions for their oil production as a result of the high
demand from the refineries located in Kansas.
81
During the year ended December 31, 2010, VOC Sponsor sold
approximately 32% of the oil produced from the Underlying
Properties to MV Purchasing, LLC, an affiliate of VOC Sponsor.
The remaining oil production is sold to third-party crude oil
purchasers. These purchasers buy crude oil from VOC Sponsor
under short-term contracts using market sensitive pricing. VOC
Sponsor does not believe that the loss of any of these parties,
including MV Purchasing LLC, as a purchaser of crude oil
production from the Underlying Properties would have a material
impact on the business or operations of VOC Sponsor or the
Underlying Properties because of the competitive marketing
conditions in Texas and Kansas as described above.
Vess Oil has committed to sell all of its natural gas production
attributable to the Kurten Woodbine Unit in Texas to ETC Texas
Pipeline, Ltd., subject to certain exceptions, until
October 1, 2013, at which time the commitment will
automatically convert to a year-to-year basis. Vess Oil has
also committed to sell to ONEOK Field Services Company, L.L.C.
all of its natural gas production attributable to nine wells in
Kingman and Barber Counties, Texas until August 31, 2015,
at which time the commitment will automatically convert to a
month-to-month basis.
Vess Oil has committed to sell its crude oil in the Kurten
Woodbine Units in Texas to Enterprise Crude Oil, LLC until May
31, 2011, at which time the commitment will automatically
convert to a month-to-month arrangement.
VOC Sponsor does not have any volume commitments or take or pay
arrangements.
Oil production is typically transported by truck from the field
to the closest gathering facility or refinery. VOC Sponsor sells
the majority of the oil production from the Underlying
Properties under short-term contracts using market sensitive
pricing. The price received by VOC Sponsor for the oil
production from the Underlying Properties is usually based on
the NYMEX price applied to equal daily quantities on the month
of delivery that is then reduced for differentials based upon
delivery location and oil quality.
All natural gas produced by VOC Sponsor is marketed and sold to
third-party purchasers. The natural gas is sold on contract
basis and the contracts are in their secondary terms and are on
a
month-to-month
basis. In all cases, the contract price is based on a percentage
of a published regional index price, after adjustments for Btu
content, transportation and related charges.
TITLE TO
PROPERTIES
The properties comprising the Underlying Properties are subject
to certain burdens that are described in more detail below. To
the extent that these burdens and obligations affect VOC
Sponsors rights to production and the value of production
from the Underlying Properties, they have been taken into
account in calculating the trusts interests and in
estimating the size and the value of the reserves attributable
to the Underlying Properties.
VOC Sponsors interests in the oil and natural gas
properties comprising the Underlying Properties are typically
subject, in one degree or another, to one or more of the
following:
|
|
|
|
|
royalties, overriding royalties and other burdens, express and
implied, under oil and natural gas leases;
|
|
|
|
overriding royalties, production payments and similar interests
and other burdens created by VOC Sponsors predecessors in
title;
|
82
|
|
|
|
|
a variety of contractual obligations arising under operating
agreements, farm-out agreements, production sales contracts and
other agreements that may affect the Underlying Properties or
their title;
|
|
|
|
liens that arise in the normal course of operations, such as
those for unpaid taxes, statutory liens securing unpaid
suppliers and contractors and contractual liens under operating
agreements that are not yet delinquent or, if delinquent, are
being contested in good faith by appropriate proceedings;
|
|
|
|
pooling, unitization and communitization agreements,
declarations and orders;
|
|
|
|
easements, restrictions,
rights-of-way
and other matters that commonly affect property;
|
|
|
|
conventional rights of reassignment that obligate VOC Sponsor to
reassign all or part of a property to a third party if VOC
Sponsor intends to release or abandon such property; and
|
|
|
|
rights reserved to or vested in the appropriate governmental
agency or authority to control or regulate the Underlying
Properties and the Net Profits Interest therein.
|
VOC Sponsor believes that the burdens and obligations affecting
the properties comprising the Underlying Properties are
conventional in the industry for similar properties. VOC Sponsor
also believes that the existing burdens and obligations do not,
in the aggregate, materially interfere with the use of the
Underlying Properties and will not materially adversely affect
the value of the Net Profits Interest.
VOC Sponsor will record the conveyance of the Net Profits
Interest in Kansas and Texas in the real property records in
each Kansas or Texas county in which the Underlying Properties
are located. Although under Texas law it is well-established
that the recording in the appropriate real property records of
an interest such as the Net Profits Interest will constitute the
conveyance of a fully vested real property interest to the
trust, the law in Kansas is less certain. VOC Sponsor and the
trust believe, that the recording in the appropriate real
property records in Kansas of the Net Profits Interest should
constitute the conveyance of a fully vested real property
interest, interests in hydrocarbons in place or to be produced
or a production payment as such is defined under the United
States Bankruptcy Code; however, there is no dispositive Kansas
Supreme Court case directly addressing these issues. In a
bankruptcy of VOC Sponsor, creditors of VOC Sponsor would be
able to claim the Net Profits Interest as an asset of the
bankruptcy estate to satisfy obligations to them if the
conveyance of the Net Profits Interest did not constitute the
conveyance of a real property interest or interests in
hydrocarbons in place or to be produced under applicable state
law or a production payment, in which case the trust would be an
unsecured creditor of VOC Sponsor at risk of losing the entire
value of the Net Profit Interests to senior creditors.
VOC Sponsor believes that its title to the Underlying Properties
is, and the trusts title to the Net Profits Interest will
be, good and defensible in accordance with standards generally
accepted in the oil and gas industry, subject to such exceptions
as are not so material to detract substantially from the use or
value of such properties or royalty interests. Please see
Risk factorsThe trust units may lose value as a
result of title deficiencies with respect to the Underlying
Properties.
COMPETITION
AND MARKETS
The oil and natural gas industry is highly competitive. VOC
Sponsor competes with major oil and natural gas companies and
independent oil and natural gas companies for oil and natural
83
gas, equipment, personnel and markets for the sale of oil and
natural gas. Many of these competitors are financially stronger
than VOC Sponsor, but even financially troubled competitors can
affect the market because of their need to sell oil and natural
gas at any price to attempt to maintain cashflow. The trust will
be subject to the same competitive conditions as VOC Sponsor and
other companies in the oil and natural gas industry.
Oil and natural gas compete with other forms of energy available
to customers, primarily based on price. These alternate forms of
energy include electricity, coal and fuel oils. Changes in the
availability or price of oil, natural gas or other forms of
energy, as well as business conditions, conservation,
legislation, regulations and the ability to convert to alternate
fuels and other forms of energy may affect the demand for oil
and natural gas.
Future price fluctuations for oil and natural gas will directly
impact trust distributions, estimates of reserves attributable
to the trusts interests and estimated and actual future
net revenues to the trust. In view of the many uncertainties
that affect the supply and demand for oil and natural gas,
neither the trust nor VOC Sponsor can make reliable predictions
of future oil and natural gas supply and demand, future product
prices or the effect of future product prices on the trust.
ENVIRONMENTAL
MATTERS AND REGULATION
General. The oil and natural gas exploration and
production operations of VOC Sponsor are subject to stringent
and comprehensive federal, regional, state and local laws and
regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection.
These laws and regulations may impose significant obligations on
VOC Sponsors operations, including requirements to:
|
|
|
|
|
obtain permits to conduct regulated activities;
|
|
|
|
limit or prohibit drilling activities on certain lands lying
within wilderness, wetlands and other protected areas;
|
|
|
|
restrict the types, quantities and concentration of materials
that can be released into the environment in the performance of
drilling and production activities;
|
|
|
|
initiate remedial activities or corrective actions to mitigate
pollution from former or current operations, such as restoration
of drilling pits and plugging of abandoned wells;
|
|
|
|
apply specific health and safety criteria addressing worker
protection; and
|
|
|
|
impose substantial liabilities on VOC Sponsor for pollution
resulting from VOC Sponsors operations.
|
Failure to comply with environmental laws and regulations may
result in the assessment of administrative, civil and criminal
sanctions, including monetary penalties, the imposition of
investigatory and remedial obligations, and the issuance of
injunctions limiting or prohibiting some or all of our
operations. Moreover, these laws, rules and regulations may
restrict the rate of oil and natural gas 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.
VOC Sponsor believes that it is in substantial compliance with
all existing environmental laws and regulations applicable to
its current operations and that its continued compliance with
existing requirements will not have a material adverse effect on
the cash distributions to the trust unitholders. However, the
clear trend in environmental
84
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 emission or discharge limits or waste
handling, disposal or remediation obligations could have a
material adverse effect on VOC Sponsors development
expenditures, results of operations and financial position. VOC
Sponsor may be unable to pass on those increases to its
customers.
The following is a summary of the more significant existing
environmental, health and safety laws and regulations, each as
amended from time to time, to which VOC Sponsors business
operations are subject.
Hazardous substance and wastes. The Comprehensive
Environmental Response, Compensation and Liability Act, or
CERCLA, also known as the Superfund law, and
comparable state laws impose liability without regard to fault
or the legality of the original conduct on certain classes of
persons who are considered to be responsible for the release of
a hazardous substance into the environment. Under
CERCLA, these responsible persons may include the
owner or operator of the site where the release occurred, and
entities that transport or disposed or arranged for the
transport or disposal of hazardous substances released at the
site. These responsible 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. CERCLA also authorizes the
U.S. Environmental Protection Agency, or EPA
and, in some instances, third parties to act in response to
threats to the public health or the environment and to seek to
recover from the responsible classes of persons the costs they
incur. It is not uncommon for neighboring landowners and other
third-parties to file claims for personal injury and property
damage allegedly caused by the hazardous substances released
into the environment. VOC Sponsor generates materials in the
course of its operations that may be regulated as hazardous
substances.
The Resource Conservation and Recovery Act, or RCRA,
and comparable state laws regulate the generation,
transportation, treatment, storage, disposal and cleanup of
hazardous and non-hazardous wastes. Under the auspices of the
EPA, the individual states administer some or all of the
provisions of RCRA, sometimes in conjunction with their own,
more stringent requirements. Drilling fluids, produced waters
and most of the other wastes associated with the exploration,
production and development of crude oil or natural gas are
currently exempt from regulations as hazardous wastes under
RCRA. However, it is possible that certain oil and natural gas
exploration and production wastes now classified as
non-hazardous could be classified as hazardous wastes in the
future. In September 2010, the Natural Resources Defense Council
filed a petition with the EPA asking them to reconsider the RCRA
exemption for exploration, production, and development wastes.
To date, the EPA has not taken any action on the petition. Any
change in the RCRA exemption for such wastes could result in an
increase in the costs to manage and dispose of wastes, which
could have a material adverse effect on the cash distributions
to the trust unitholders. In addition, VOC Sponsor generates
industrial wastes in the ordinary course of its operations that
may be regulated as hazardous wastes.
The real properties upon which VOC Sponsor conducts its
operations have been used for oil and natural gas exploration
and production for many years. Although VOC Sponsor may have
utilized operating and disposal practices that were standard in
the industry at the time, petroleum hydrocarbons and wastes may
have been disposed of or released on or under the real
properties upon which VOC Sponsor conducts its operations, or on
or under other, offsite locations, where these petroleum
hydrocarbons and wastes have been taken for recycling or
disposal. In addition, the real properties upon which VOC
Sponsor conducts its operations may 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 VOC Sponsors control.
85
These real properties and the petroleum hydrocarbons and wastes
disposed or released thereon may be subject to CERCLA, RCRA and
analogous state laws. Under such laws, VOC Sponsor could be
required to remove or remediate previously disposed wastes, to
clean up contaminated property, and to perform remedial
operations such as restoration of pits and plugging of abandoned
wells to prevent future contamination.
Water discharges and hydraulic fracturing. The
Federal Water Pollution Control Act, also known as the
Clean Water Act, and analogous state laws impose
restrictions and strict controls with respect to the discharge
of pollutants, including spills and leaks of oil, into federal
and state waters. The discharge of pollutants into regulated
waters is prohibited, except in accordance with the terms of a
permit issued by EPA or an analogous state agency. Any
unpermitted discharge of pollutants could result in penalties
and significant remedial obligations. Spill prevention, control
and countermeasure requirements under federal law require
appropriate containment berms and similar structures to help
prevent the contamination of navigable waters in the event of a
petroleum hydrocarbon tank spill, rupture or leak.
It is customary to recover oil and natural gas from deep shale
and tight sand formations through the use of hydraulic
fracturing, combined with sophisticated horizontal drilling.
Hydraulic fracturing involves the injection of water, sand and
chemical additives under pressure into rock formations to
stimulate gas production. Due to public concerns raised
regarding potential impacts of hydraulic fracturing on
groundwater quality, legislative and regulatory efforts at the
federal level and in some states have been initiated to require
or make more stringent the permitting and compliance
requirements for hydraulic fracturing operations. In particular,
the EPA has commenced a study of the potential environmental
impacts of hydraulic fracturing activities, with initial results
of the study anticipated to be available by late 2012 and final
results in 2014. Legislation that was introduced in the
111th
session of Congress was re-introduced in the
112th
Congress and would provide for federal regulation of hydraulic
fracturing and require both pre-fracturing and post-fracturing
disclosure of the chemicals used in the fracturing process. In
addition, some states have adopted, and other states are
considering adopting, regulations that could restrict hydraulic
fracturing in certain circumstances. For example, in March 2011,
bills were introduced into Texas Senate and House of
Representatives that, if adopted, would require disclosure of
fluids, additives and other chemicals used in hydraulic
fracturing treatment operations on Texas, subject to certain
trade secret protections, to the Railroad Commission of Texas.
Also, some state and local governments in the Marcellus Shale
region in Pennsylvania and New York have considered or imposed
moratoria on drilling operations using hydraulic fracturing
until further study of the potential environmental and human
health impacts by the EPA or the state agencies are completed.
For example, New York has imposed a de facto moratorium on
the issuance of permits for high-volume, horizontal hydraulic
fracturing until state-administered environmental studies are
completed, a draft of which must be published by June 1,
2011, followed by a
30-day
comment period. Further, Pennsylvania has adopted a variety of
regulations limiting how and where fracturing can be performed.
If new laws or regulations that significantly restrict hydraulic
fracturing are adopted, such legal requirements could make it
more difficult or costly for VOC Sponsor to perform hydraulic
fracturing activities. Moreover, required disclosure without
protection for trade secret or proprietary products could
discourage service companies from using such products and as a
result impact the degree to which some oil and gas wells may be
efficiently and economically completed or brought into
production. Finally, VOC Sponsor believes that enactment of
legislation regulating hydraulic fracturing at the federal level
may have a material adverse effect on its business.
Air emissions. The federal Clean Air Act and
comparable state laws restrict the emission of air pollutants
from many sources through air emissions permitting programs and
also impose various monitoring and reporting requirements. These
laws and regulations may require VOC Sponsor to obtain
pre-approval for the construction or modification of certain
projects or facilities
86
expected to produce or significant increase air emissions,
obtain and strictly comply with stringent air permit
requirements or incur development expenditures to install and
utilize specific equipment or technologies to control emissions.
Obtaining permits has the potential to delay the development of
oil and natural gas projects. Federal and state regulatory
agencies may impose administrative, civil and criminal penalties
for non-compliance with air permits or other requirements of the
federal Clean Air Act and associated state laws and regulations.
Climate change. In response to certain scientific
studies suggesting that emissions of certain gases, commonly
referred to as greenhouse gases, or GHGs, and
including carbon dioxide and methane, are contributing to the
warming of the Earths atmosphere and other climatic
conditions, both houses of Congress have actively 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. These allowances would be expected to escalate
significantly in cost over time. Although it is not possible at
this time to predict when Congress may pass climate change
legislation, any future federal or state laws that may be
adopted to address GHG emissions could require VOC Sponsor to
incur increased operating costs and could adversely affect
demand for the oil and natural gas VOC Sponsor produces.
In addition, on December 15, 2009, the EPA published its
findings that emissions of GHGs present an endangerment to
public heath and the environment. 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
take effect on January 2, 2011. On June 3, 2010, the
EPA published its final rule to address the permitting of GHG
emissions from stationary sources under the Prevention of
Significant Deterioration, or PSD, and Title V
permitting programs. This rule tailors these
permitting programs to apply to certain stationary sources of
GHG emissions in a multi-step process, with the largest sources
first subject to permitting. It is widely expected that
facilities required to obtain PSD permits for their GHG
emissions also will be required to reduce those emissions
according to best available control technology
standards for GHGs that have yet to be developed. In addition,
on November 30, 2010, the EPA published its final
regulations expanding the existing GHG monitoring and reporting
rule to include onshore and offshore oil and natural gas
production facilities and onshore oil and natural gas
processing, transmission, storage, and distribution facilities.
Reporting of GHG emissions from such facilities is required on
an annual basis, with reporting beginning in 2012 for emissions
occurring in 2011. The adoption of any regulations that requires
reporting of GHGs or otherwise limits emissions of GHGs from the
equipment and operations of VOC Sponsor could require VOC
Sponsor to incur costs to monitor and report on GHG emissions or
reduce emissions of GHGs associated with its operations, and
such requirements also could adversely affect demand for the oil
and natural gas that VOC Sponsor produces.
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, floods and other climatic events. If any
such effects were to occur, they could adversely affect or delay
demand for the oil or natural gas produced by VOC Sponsor or
otherwise cause VOC Sponsor to incur significant costs in
preparing for or responding to those effects.
87
Endangered Species Act. The federal Endangered
Species Act, or ESA, restricts activities that may
affect endangered and threatened species or their habitats. The
designation of previously unidentified endangered or threatened
species could cause VOC Sponsor to incur additional costs or
become subject to operating delays, restrictions or bans in the
affected areas. While some of VOC Sponsors facilities or
leased acreage may be located in areas that are designated as
habitat for endangered or threatened species, VOC Sponsor
believes that it is in substantial compliance with the ESA.
Employee health and safety. The operations of VOC
Sponsor are subject to a number of federal and state laws and
regulations, including the federal Occupational Safety and
Health Act, 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 EPA
community
right-to-know
regulations under Title III of the federal Superfund
Amendment and Reauthorization Act and comparable state statutes
require that information be maintained concerning hazardous
materials used or produced in operations and that this
information be provided to employees, state and local government
authorities and citizens. VOC Sponsor believes that it is in
substantial compliance with all applicable laws and regulations
relating to worker health and safety.
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COMPUTATION
OF NET PROCEEDS
The provisions of the conveyance governing the computation of
the net proceeds are detailed and extensive. The following
information summarizes the material information contained in the
conveyance related to the computation of the net proceeds. This
summary may not contain all information that is important to
you. For more detailed provisions concerning the Net Profits
Interest, you should read the conveyance. A copy of the
conveyance has been filed as an exhibit to the registration
statement. See Where you can find more information.
NET
PROFITS INTEREST
Under the conveyance, 80% of the aggregate net proceeds
attributable to the sale of oil and natural gas production from
the Underlying Properties for each calendar quarter will be paid
to the trust on or before the 30th day of the month
following the end of each quarter (with the exception of the
first quarterly payment, which will be made on or about
August 1, 2011). VOC Sponsor will not pay to the trust any
interest on the net proceeds held by VOC Sponsor prior to
payment to the trust. The trustee will make distributions to
trust unitholders quarterly. See Description of the trust
units Distributions and income computations.
Gross proceeds means the aggregate amount
received by VOC Sponsor from sales of oil and natural gas
produced from the Underlying Properties (other than amounts
received for certain future non-consent operations). However,
gross proceeds does not include consideration for the transfer
or sale of any underlying property by VOC Sponsor or any
subsequent owner to any new owner. Gross proceeds also does not
include any amount for oil or natural gas lost in production or
marketing or used by the owner of the Underlying Properties in
drilling, production and plant operations. Gross proceeds
includes payments for future production if they are not subject
to repayment in the event of insufficient subsequent production.
Net proceeds means gross proceeds less the
following costs:
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all payments to mineral or landowners, such as royalties,
overriding royalties or other burdens against production, delay
rentals, shut-in oil and natural gas payments, minimum royalty
or other payments for drilling or deferring drilling;
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any taxes paid by the owner of an Underlying Property to the
extent not deducted in calculating gross proceeds, including
estimated and accrued general property (ad valorem), production,
severance, sales, gathering, excise and other taxes;
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the aggregate amount paid by VOC Sponsor upon settlement of
hedge contracts on a quarterly basis, as specified in the hedge
contracts;
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any extraordinary taxes or windfall profits taxes that may be
assessed in the future that are based on profits realized or
prices received for production from the Underlying Properties;
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costs paid by an owner of a property comprising the Underlying
Properties under any joint operating agreement pursuant to the
terms of the conveyance;
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all other costs and expenses, development costs and liabilities
of drilling, recompleting, workovers, operating and producing
oil and natural gas, including allocated expenses such as labor,
vehicle and travel costs and materials and any plugging and
abandonment liabilities (net of any development costs for which
a reserve had already been made to the
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extent such development costs are incurred during the
computation period) other than costs and expenses for certain
future non-consent operations;
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costs or charges associated with gathering, treating and
processing oil and natural gas, (provided, however, that any
proceeds attributable to treatment or processing will offset
such costs or changes, if any);
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any overhead charge incurred pursuant to any operating agreement
or other arrangement relating to an Underlying Property as
permitted under the applicable conveyance, including the
overhead fees payable by VOC Sponsor to VOC Operators and Vess
Texas LLC as described in Certain relationship and related
party transactions;
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costs for recording the conveyance and costs estimated to record
the termination and for release of the conveyance;
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costs paid to counterparties under the hedge contracts or to the
persons that provide credit to maintain any hedge contracts,
excluding any hedge settlement amounts;
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amounts previously included in gross proceeds but subsequently
paid as a refund, interest or penalty;
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costs and expenses for renewals or extensions of leases; and
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at the option of VOC Sponsor (or any subsequent owner of the
Underlying Properties), amounts reserved for approved
development expenditure projects, including well drilling,
recompletion and workover costs, which amounts will at no time
exceed $1.0 million in the aggregate, and will be subject
to the limitations described below (provided that such costs
shall not be debited from gross proceeds when actually incurred).
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All of the hedge payments received by VOC Sponsor from hedge
contract counterparties upon settlements of hedge contracts and
certain other non-production revenues, including salvage value
for equipment related to plugged and abandoned wells, as
detailed in the conveyance, will offset the costs outlined above
in calculating the net proceeds. If the hedge payments received
by VOC Sponsor and certain other non-production revenues exceed
the costs during a quarterly period, the ability to use such
excess amounts to offset costs will be deferred and utilized as
offsets in the next quarterly period to the extent such amounts,
plus accrued interest thereon, together with other offsets to
costs, for the applicable quarter, are less than the costs
arising in such quarter. If any excess amounts have not been
used to offset costs at the time when the later to occur of
(1) December 31, 2030, or (2) the time from and
after January 1, 2011 when 10.6 MMBoe (which is the
equivalent of 8.5 MMBoe in respect of the Net Profits
Interest) have been produced from the Underlying Properties and
sold, then trust unitholders will not be entitled to receive the
benefit of such excess amounts.
During each twelve-month period beginning on the later to occur
of (1) December 31, 2027 and (2) the time from
and after January 1, 2011 when 9.8 MMBoe have been
produced from the Underlying Properties and sold (which is the
equivalent of 7.8 MMBoe in respect of the Net Profits
Interest) (in either case, the Capital Expenditure
Limitation Date), the sum of the development expenditures
and amounts reserved for approved development expenditure
projects for such twelve-month period may not exceed the Average
Annual Capital Expenditure Amount. The Average Annual
Capital Expenditure Amount means the quotient of
(x) the sum of the development expenditures and amounts
reserved for approved development expenditure projects with
respect to the three twelve-month periods ending on the Capital
Expenditure Limitation Date, divided by (y) three.
Commencing on the Capital Expenditure Limitation Date, and each
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anniversary of the Capital Expenditure Limitation Date
thereafter, the Average Annual Capital Expenditure Amount will
be increased by 2.5% to account for expected increased costs due
to inflation.
In the event that the net proceeds for any computation period is
a negative amount, the trust will receive no payment for that
period, and any such negative amount plus accrued interest will
be deducted from gross proceeds in the following computation
period for purposes of determining the net proceeds for that
following computation period.
Gross proceeds and net proceeds are calculated on a cash basis,
except that certain costs, primarily ad valorem taxes and
expenditures of a material amount, may be determined on an
accrual basis.
ADDITIONAL
PROVISIONS
If a controversy arises as to the sales price of any production,
then for purposes of determining gross proceeds:
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amounts withheld or placed in escrow by a purchaser are not
considered to be received by the owner of the Underlying
Property until actually collected;
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amounts received by the owner of the Underlying Property and
promptly deposited with a nonaffiliated escrow agent will not be
considered to have been received until disbursed to it by the
escrow agent; and
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amounts received by the owner of the Underlying Property and not
deposited with an escrow agent will be considered to have been
received.
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The trustee is not obligated to return any cash received from
the Net Profits Interest. Any overpayments made to the trust by
VOC Sponsor due to adjustments to prior calculations of net
proceeds or otherwise will reduce future amounts payable to the
trust until VOC Sponsor recovers the overpayments plus interest
at the prime rate.
The conveyance generally permits VOC Sponsor to transfer without
the consent or approval of the trust unitholders all or any part
of its interest in the Underlying Properties, subject to the Net
Profits Interest. The trust unitholders are not entitled to any
proceeds of a sale or transfer of VOC Sponsors interest
unless certain conditions set forth in the following paragraph
are satisfied. Except in certain cases where the Net Profits
Interest is released, following a sale or transfer, the
Underlying Properties will continue to be subject to the Net
Profits Interest, and the net proceeds attributable to the
transferred property will be calculated as part of the
computation of net proceeds described in this prospectus.
In addition, VOC Sponsor may, without the consent of the trust
unitholders, require the trust to release the Net Profits
Interest associated with any lease that accounts for less than
or equal to 0.25% of the total production from the Underlying
Properties in the prior 12 months and provided that the Net
Profits Interest covered by such releases cannot exceed, during
any 12-month
period, an aggregate fair market value to the trust of $500,000.
These releases will be made only in connection with a sale by
VOC Sponsor to a non-affiliate of the relevant Underlying
Properties and are conditioned upon the trust receiving an
amount equal to the fair value to the trust of such Net Profits
Interest. Any net sales proceeds paid to the trust are
distributable to trust unitholders for the quarter in which they
are received. VOC Sponsor has not identified for sale any of the
Underlying Properties.
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As the designated operator of a property comprising the
Underlying Properties, VOC Sponsor may enter into farm-out,
operating, participation and other similar agreements to develop
the property. VOC Sponsor may enter into any of these agreements
without the consent or approval of the trustee or any trust
unitholder.
VOC Sponsor and any transferee of an Underlying Property will
have the right to abandon its interest in any well or property
if it reasonably believes the well or property ceases to produce
or is not capable of producing in commercially paying
quantities. In making such decisions, VOC Sponsor or any
transferee of an Underlying Property is required under the
applicable conveyance to operate, or to use commercially
reasonable efforts to cause the operators of the Underlying
Properties to operate these properties as would a reasonably
prudent operator acting with respect to its own properties
(without regard to the existence of the Net Profits Interest).
Upon termination of the lease, the portion of the Net Profits
Interest relating to the abandoned property will be extinguished.
VOC Sponsor must maintain books and records sufficient to
determine the amounts payable for the Net Profits Interest to
the trust. Quarterly and annually, VOC Sponsor must deliver to
the trustee a statement of the computation of the net proceeds
for each computation period. The trustee has the right to
inspect and copy the books and records maintained by VOC Sponsor
during normal business hours and upon reasonable notice.
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DESCRIPTION
OF THE TRUST AGREEMENT
The following information and the information included under
Description of the trust units summarize the
material information contained in the trust agreement and the
conveyance. For more detailed provisions concerning the trust
and the conveyance, you should read the trust agreement and the
conveyance. Copies of the trust agreement and the conveyance
will be filed as exhibits to the registration statement. See
Where you can find more information.
CREATION
AND ORGANIZATION OF THE TRUST; AMENDMENTS
Immediately prior to the closing of this offering, VOC Sponsor
will contribute to the trust the term Net Profits Interest in
consideration of the receipt of 16,540,000 trust units. The
trusts first quarterly distribution will consist of an
amount in cash paid by VOC Sponsor equal to the amount that
would have been payable to the trust had the Net Profits
Interest been in effect during the period from January 1,
2011 through June 30, 2011, less any general and
administrative expenses and reserves of the trust. After the
offering made hereby, VOC Sponsor will own its net interests in
the Underlying Properties subject to and burdened by the Net
Profits Interest.
The trust was created under Delaware law to acquire and hold the
Net Profits Interest for the benefit of the trust unitholders
pursuant to an agreement between VOC Sponsor, the trustee and
the Delaware trustee. The Net Profits Interest is passive in
nature and neither the trust nor the trustee has any control
over or responsibility for costs relating to the operation of
the properties comprising the Underlying Properties. Neither VOC
Sponsor nor other operators of the properties comprising the
Underlying Properties have any contractual commitments to the
trust to provide additional funding or to conduct further
drilling on or to maintain their ownership interest in any of
these properties. After the conveyance of the Net Profits
Interest, however, VOC Sponsor will retain an interest in each
of the Underlying Properties. For a description of the
Underlying Properties and other information relating to them,
see The Underlying Properties.
The trust agreement will provide that the trusts
activities will be limited to owning the Net Profits Interest
and any activity reasonably related to such ownership, including
activities required or permitted by the terms of the conveyance
related to the Net Profits Interest. As a result, the trust will
not be permitted to acquire other oil and natural gas properties
or Net Profits Interests or otherwise to engage in activities
beyond those necessary for the conservation and protection of
the Net Profits Interest.
The beneficial interest in the trust is divided into 16,540,000
trust units. Each of the trust units represents an equal
undivided beneficial interest in the assets of the trust. You
will find additional information concerning the trust units in
Description of the trust units.
Amendment of the trust agreement requires a vote of holders of a
majority of the outstanding trust units. However, no amendment
may:
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increase the power of the trustee or the Delaware trustee to
engage in business or investment activities; or
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alter the rights of the trust unitholders as among themselves.
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Certain amendments to the trust agreement do not require the
vote of the trust unitholders. The trustee may, without approval
of the trust unitholders, from time to time supplement or amend
the trust agreement in order to cure any ambiguity, to correct
or supplement any defective or inconsistent provisions, to grant
any benefit to all of the trust unitholders or to change the
name of the trust, provided such supplement or amendment is not
adverse to the interest of the
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trust unitholders. The affairs of the trust will be managed by
the trustee. VOC Sponsor has no ability to manage or influence
the operations of the trust. Likewise, the trust has no ability
to manage or influence the operations of VOC Sponsor.
ASSETS OF
THE TRUST
Upon completion of this offering, the assets of the trust will
consist of the Net Profits Interest and any cash and temporary
investments being held for the payment of expenses and
liabilities and for distribution to the trust unitholders.
DUTIES
AND POWERS OF THE TRUSTEE
The duties of the trustee are specified in the trust agreement
and by the laws of the state of Delaware, except as modified by
the trust agreement. The trustees principal duties consist
of:
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collecting cash attributable to the Net Profits Interest;
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paying expenses, charges and obligations of the trust from the
trusts assets;
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distributing distributable cash to the trust unitholders;
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causing to be prepared and distributed a tax information report
for each trust unitholder and to prepare and file tax returns on
behalf of the trust;
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causing to be prepared and filed reports required to be filed
under the Securities Exchange Act of 1934 and by the rules of
any securities exchange or quotation system on which the trust
units are listed or admitted to trading;
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causing to be prepared and filed a reserve report by or for the
trust by independent reserve engineers as of December 31 of
each year in accordance with criteria established by the SEC;
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establishing, evaluating and maintaining a system of internal
controls over financial reporting in compliance with the
requirements of Section 404 of the Sarbanes-Oxley Act of
2002;
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enforcing the rights under certain agreements entered into in
connection with this offering; and
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taking any action it deems necessary and advisable to best
achieve the purposes of the trust.
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In connection with the formation of the trust, the trustee
entered into several agreements with VOC Sponsor that impose
obligations upon VOC Sponsor that are enforceable by the trustee
on behalf of the trust. For example, when making decisions with
respect to the development, operation, abandonment or sale of
the Underlying Properties, VOC Sponsor is obligated under the
terms of the conveyance of the Net Profits Interest to use
commercially reasonable efforts to cause the operators of the
Underlying Properties to operate these properties as would a
reasonably prudent operator acting with respect to its own
properties (without regard to the existence of the Net Profits
Interest). In addition, the trust has entered into an
administrative services agreement with VOC Sponsor pursuant to
which VOC Sponsor has agreed to perform specified administrative
services on behalf of the trust in a good and workmanlike manner
in accordance
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with the sound and prudent practices of providers of similar
services. The trustee has the power and authority under the
trust agreement to enforce these agreements on behalf of the
trust.
The trustee may create a cash reserve to pay for future
liabilities of the trust. If the trustee determines that the
cash on hand and the cash to be received are insufficient to
cover the trusts liabilities, the trustee may borrow funds
to pay liabilities of the trust. The trustee may borrow the
funds from any person, including itself or its affiliates. The
trustee may also mortgage the assets of the trust to secure
payment of the indebtedness. If the trust does not have
sufficient cash to pay future liabilities, it may, in limited
circumstances, sell all or a portion of the Net Profits
Interest. The terms of such indebtedness and security interest,
if funds were loaned by the entity serving as trustee or
Delaware trustee or an affiliate thereof, would be similar to
the terms which such entity would grant to a similarly situated
commercial customer with whom it did not have a fiduciary
relationship, and such entity shall be entitled to enforce its
rights with respect to any such indebtedness and security
interest as if it were not then serving as trustee or Delaware
trustee. If the trustee borrows funds, the trust unitholders
will not receive distributions until the borrowed funds are
repaid. VOC Sponsor has agreed to provide a letter of credit in
the amount of $1.0 million to the trustee to protect the trust
against the risk that it does not have sufficient cash to pay
future liabilities.
Each quarter, the trustee will pay trust obligations and
expenses and distribute to the trust unitholders the remaining
proceeds received from the Net Profits Interest. The cash held
by the trustee as a reserve against future liabilities or for
distribution at the next distribution date must be
invested in:
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interest bearing obligations of the United States government;
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money market funds that invest only in United States government
securities;
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repurchase agreements secured by interest-bearing obligations of
the United States government; or
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bank certificates of deposit.
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The trust may not acquire any asset except the Net Profits
Interest, cash and temporary cash investments, and it may not
engage in any investment activity except investing cash on hand.
The trust may merge or consolidate with or into one or more
limited partnerships, general partnerships, corporations,
business trusts, limited liability companies, or associations or
unincorporated businesses if such transaction is agreed to by
the trustee and by the affirmative vote of the holders of a
majority of the outstanding trust units and such transaction is
permitted under the Delaware Statutory Trust Act and any
other applicable law.
VOC Sponsor may request that the trustee sell all or a portion
of its Net Profits Interest under any of the following
circumstances:
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the sale does not involve a material part of the trusts
assets and is in the judgment of VOC sponsor in the best
interests of the trust unitholders; or
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the sale constitutes a material part of the trusts assets
and is in the best interests of the trust unitholders.
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In addition, under certain limited circumstances, the Trustee
may be required to sell all or a portion of the Net Profits
Interest without approval of the trust unitholders.
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The trustee may also mortgage, pledge, grant security interests
in or otherwise encumber the trust estate to secure payment of
indebtedness and sell the assets constituting the trust estate
upon dissolution of the trust.
The trustee will distribute the net proceeds from any sale of
the Net Profits Interest and other assets to the trust
unitholders.
Upon dissolution of the trust, the trustee must sell the Net
Profits Interest. No trust unitholder approval is required in
this event.
The trustee may require any trust unitholder to dispose of his
trust units if an administrative or judicial proceeding seeks to
cancel or forfeit any of the property in which the trust holds
an interest because of the nationality or any other status of
that trust unitholder. If a trust unitholder fails to dispose of
his trust units, the trustee has the right to purchase them and
to borrow funds to make that purchase.
The trustee is not expected to maintain a website for filings
made by the trust with the SEC.
The trustee may agree to modifications of the terms of the
conveyance or to settle disputes involving the conveyance. The
trustee may not agree to modifications or settle disputes
involving the Net Profits Interest part of the conveyance if
these actions would change the character of the Net Profits
Interest in such a way that the Net Profits Interest becomes a
working interest or that the trust would fail to continue to
qualify as a grantor trust for U.S. federal income tax
purposes.
LIABILITIES
OF THE TRUST
Because the trust does not conduct an active business and the
trustee has little power to incur obligations, it is expected
that the trust will incur liabilities for only routine
administrative expenses, such as the trustees fees,
accounting, engineering, legal, tax advisory and other
professional fees and other fees and expenses applicable to
public companies.
FEES AND
EXPENSES
The trust will be responsible for paying all legal, accounting,
tax advisory, engineering and stock exchange fees, printing
costs and other administrative and
out-of-pocket
expenses incurred by or at the direction of the trustee or the
Delaware trustee. The trust will also be responsible for paying
other expenses incurred as a result of being a publicly traded
entity, including costs associated with annual and quarterly
reports to unitholders, preparation of tax information material
and distribution, independent auditor fees and registrar and
transfer agent fees. These trust administrative expenses are
anticipated to aggregate approximately $900,000 for 2011.
Administrative expenses for subsequent years could be greater or
less depending on future events that cannot be predicted.
Included in the $900,000 annual estimate is an annual
administrative fee of $150,000 for the trustee and an annual
administrative fee of $2,500 for the Delaware trustee as well as
an annual administrative fee payable to VOC Sponsor, which fee
will total $75,000 in 2011 and will increase by 4% each year
beginning in January 2012. See The trust. The trust
will pay, out of the first cash payment received by the trust,
the trustees and Delaware trustees fees and legal
expenses incurred in forming the trust, in connection with this
initial public offering and related matters, as well as the
Delaware trustees acceptance fee in the amount of $4,000.
These costs will be deducted by the trust before distributions
are made to trust unitholders.
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The fees described above are independent of the overhead fee
payable by Vess LLC on behalf of VOC Sponsor to VOC Operators
and the overhead reimbursement amount payable by VOC Sponsor to
Vess LLC. See VOC Sponsor Management of VOC
Sponsor.
FIDUCIARY
RESPONSIBILITY AND LIABILITY OF THE TRUSTEE
The trustee will not make business or investment decisions
affecting the assets of the trust except to the extent it
enforces its rights under the conveyance agreement related to
the Net Profits Interest and the administrative services
agreement described above under Duties and
powers of the trustee that will be executed in connection
with this offering. Therefore, substantially all of the
trustees functions under the trust agreement are expected
to be ministerial in nature. See Duties and
powers of the trustee above. The trust agreement, however,
provides that the trustee may:
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charge for its services as trustee;
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retain funds to pay for future expenses and deposit them with
one or more banks or financial institutions (which may include
the trustee to the extent permitted by law);
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lend funds at commercial rates to the trust to pay the
trusts expenses; and
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seek reimbursement from the trust for its
out-of-pocket
expenses.
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In discharging its duty to trust unitholders, the trustee may
act in its discretion and will be liable to the trust
unitholders only for (i) its own fraud, or acts or
omissions in bad faith or which constitute gross negligence and
(ii) taxes, fees or other charges on, based or measured by
any fees, commissions or compensation received by it in
connection with any of the transactions set forth in the trust
agreement. The trustee will not be liable for any act or
omission of its agents or employees unless the trustee acted in
bad faith or with gross negligence in their selection and
retention. The trustee will be indemnified individually or as
the trustee for any liability or cost that it incurs in the
administration of the trust, except in cases of fraud, gross
negligence or bad faith. The trustee will have a lien on the
assets of the trust as security for this indemnification and its
compensation earned as trustee. Trust unitholders will not be
liable to the trustee for any indemnification. See
Description of the trust units Liability of
trust unitholders. The trustee must ensure that all
contractual liabilities of the trust are limited to the assets
of the trust and the trustee will be liable for its failure to
do so.
The trustee may consult with counsel, accountants, tax advisors,
geologists, engineers and other parties the trustee believes to
be qualified as experts on the matters for which advice is
sought. The trustee will be protected for any action it takes in
reasonable reliance upon the opinion of the expert.
Except as expressly set forth in the trust agreement, neither
the trustee, the Delaware trustee nor the other indemnified
parties have any duties or liabilities, including fiduciary
duties, to the trust or any trust unitholder. The provisions of
the trust agreement, to the extent they restrict, eliminate or
otherwise modify the duties and liabilities, including fiduciary
duties of these persons otherwise existing at law or in equity,
are agreed by the trust unitholders to replace such other duties
and liabilities of these persons. The Delaware trustee and the
trustee may, jointly, from time to time supplement or amend the
conveyance, the administrative services agreement and the
registration rights agreement to which the trust is a party
without the approval of trust unitholders in order to cure any
ambiguity, to correct or supplement any provision contained
therein which may be defective or inconsistent with any other
provisions therein, to grant any benefit to all of the trust
unitholders, or to change the name of the trust. Such supplement
or amendment, however, may not adversely affect the interests of
the trust unitholders.
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DURATION
OF THE TRUST; SALE OF THE NET PROFITS INTEREST
The Net Profits Interest will terminate on the later to occur of
(1) December 31, 2030, or (2) the time from and
after January 1, 2011 when 10.6 MMBoe have been
produced from the Underlying Properties and sold (which amount
is the equivalent of 8.5 MMBoe in respect of the
trusts right to receive 80% of the net proceeds from the
Underlying Properties pursuant to the Net Profits Interest), and
the trust will wind up its affairs and terminate. The trust will
dissolve prior to its termination if:
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the trust sells the Net Profits Interest;
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annual cash available for distribution to the trust is less than
$1 million for each of two consecutive years;
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the holders of a majority of the outstanding trust units vote in
favor of dissolution; or
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the trust is judicially dissolved.
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The trustee would then sell all of the trusts assets,
either by private sale or public auction, and distribute the net
proceeds of the sale to the trust unitholders, after paying,
satisfying and discharging all liabilities of the trust, or if
necessary, establishing cash reserves in such amounts as the
trustee in its discretion deems appropriate for contingent
liabilities.
DISPUTE
RESOLUTION
Any dispute, controversy or claim that may arise between VOC
Sponsor and the trustee relating to the trust will be submitted
to binding arbitration before a tribunal of three arbitrators.
COMPENSATION
OF THE TRUSTEE AND THE DELAWARE TRUSTEE
The trustees and the Delaware trustees compensation
will be paid out of the trusts assets. See
Fees and expenses.
MISCELLANEOUS
The principal offices of the trustee are located at 919 Congress
Avenue, Suite 500, Austin, Texas 78701, and its telephone
number is
(512) 236-6599.
The Delaware trustee and the trustee may resign at any time or
be removed with or without cause at any time by a vote of not
less than a majority of the outstanding trust units. Any
successor must be a bank or trust company meeting certain
requirements including having combined capital, surplus and
undivided profits of at least $20,000,000, in the case of the
Delaware trustee, and $100,000,000, in the case of the trustee.
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DESCRIPTION
OF THE TRUST UNITS
Each trust unit is a unit of beneficial interest in the trust
and is entitled to receive cash distributions from the trust on
a pro rata basis. Each trust unitholder has the same rights
regarding each of his trust units as every other trust
unitholder has regarding his units. The trust units will be in
book-entry form only and will not be represented by
certificates. The trust will have 16,540,000 trust units
outstanding upon completion of this offering.
DISTRIBUTIONS
AND INCOME COMPUTATIONS
Each quarter, the trustee will determine the amount of funds
available for distribution to the trust unitholders. Available
funds are the excess cash, if any, received by the trust from
the Net Profits Interest and other sources (such as interest
earned on any amounts reserved by the trustee) that quarter,
over the trusts liabilities for that quarter. Available
funds will be reduced by any cash the trustee decides to hold as
a reserve against future liabilities. It is expected that
quarterly cash distributions during the term of the trust, other
than the first quarterly cash distribution, will be made by the
trustee on or about the 45th day following the end of each
quarter to the trust unitholders of record on the 30th day
following the end of each quarter (or the next succeeding
business day). The first distribution to trust unitholders
purchasing trust units in this offering will be made on or about
August 15, 2011 to trust unitholders owning trust units on
or about August 1, 2011.
Unless otherwise advised by counsel or the IRS, the trustee will
treat the income and expenses of the trust for each quarter as
belonging to the trust unitholders of record on the quarterly
record date. Trust unitholders will recognize income and
expenses for tax purposes in the quarter the trust receives or
pays those amounts, rather than in the quarter the trust
distributes them. Minor variances may occur. For example, the
trustee could establish a reserve in one quarter that would not
result in a tax deduction until a later quarter. The trustee
could also make a payment in one quarter that would be amortized
for tax purposes over several quarters. See Federal income
tax consequences.
TRANSFER
OF TRUST UNITS
Trust unitholders may transfer their trust units in accordance
with the trust agreement. The trustee will not require either
the transferor or transferee to pay a service charge for any
transfer of a trust unit. The trustee may require payment of any
tax or other governmental charge imposed for a transfer. The
trustee may treat the owner of any trust unit as shown by its
records as the owner of the trust unit. The trustee will not be
considered to know about any claim or demand on a trust unit by
any party except the record owner. A person who acquires a trust
unit after any quarterly record date will not be entitled to the
distribution relating to that quarterly record date. Delaware
law will govern all matters affecting the title, ownership or
transfer of trust units.
PERIODIC
REPORTS
The trustee will file all required trust federal and state
income tax and information returns. The trustee will prepare and
mail to trust unitholders annual reports that trust unitholders
need to correctly report their share of the income and
deductions of the trust. The trustee will also cause to be
prepared and filed reports required to be filed under the
Securities Exchange Act of 1934, as amended, and by the rules of
any securities exchange or quotation system on which the trust
units are listed or admitted to trading, and will also cause the
trust to comply with all of the provisions of the Sarbanes-Oxley
Act, including but not limited to, establishing, evaluating and
maintaining a system of internal controls over financial
reporting in compliance with the requirements of
Section 404 thereof.
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Each trust unitholder and his representatives may examine, for
any proper purpose, during reasonable business hours, the
records of the trust and the trustee.
LIABILITY
OF TRUST UNITHOLDERS
Under the Delaware Statutory Trust Act, trust unitholders
will be entitled to the same limitation of personal liability
extended to stockholders of private corporations for profit
under the General Corporation Law of the state of Delaware. No
assurance can be given, however, that the courts in
jurisdictions outside of Delaware will give effect to such
limitation.
VOTING
RIGHTS OF TRUST UNITHOLDERS
The trustee or trust unitholders owning at least 10% of the
outstanding trust units may call meetings of trust unitholders.
The trust will be responsible for all costs associated with
calling a meeting of trust unitholders unless such meeting is
called by the trust unitholders, in which case the trust
unitholders will be responsible for all costs associated with
calling such meeting of trust unitholders. Meetings must be held
in such location as is designated by the trustee in the notice
of such meeting. The trustee must send written notice of the
time and place of the meeting and the matters to be acted upon
to all of the trust unitholders at least 20 days and not
more than 60 days before the meeting. Trust unitholders
representing a majority of trust units outstanding must be
present or represented to have a quorum. Each trust unitholder
is entitled to one vote for each trust unit owned.
Unless otherwise required by the trust agreement, a matter may
be approved or disapproved by the vote of a majority of the
trust units held by the trust unitholders at a meeting where
there is a quorum. This is true, even if a majority of the total
trust units did not approve it. The affirmative vote of the
holders of a majority of the outstanding trust units is required
to:
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dissolve the trust;
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remove the trustee or the Delaware trustee;
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amend the trust agreement (except with respect to certain
matters that do not adversely affect the rights of trust
unitholders in any material respect);
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merge or consolidate the trust with or into another
entity; or
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approve the sale of all or any material part of the assets of
the trust.
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In addition, certain amendments to the trust agreement may be
made by the trustee without approval of the trust unitholders.
See Description of the trust agreement
Creation and organization of the trust; amendments. The
trustee must consent before all or any part of the trust assets
can be sold except in connection with the dissolution of the
trust or limited sales directed by VOC Sponsor in conjunction
with its sale of Underlying Properties.
COMPARISON
OF TRUST UNITS AND COMMON STOCK
Trust unitholders have more limited voting rights than those of
stockholders of most public corporations. For example, there is
no requirement for annual meetings of trust unitholders or for
annual or other periodic re-election of the trustee.
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You should also be aware of the following ways in which an
investment in trust units is different from an investment in
common stock of a corporation.
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Trust Units
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Common Stock
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Voting
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The trust agreement provides voting rights to trust unitholders
to remove and replace the trustee and to approve or disapprove
major trust transactions.
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Corporate statutes provide voting rights to stockholders to
elect directors and to approve or disapprove major corporate
transactions.
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Income Tax
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The trust is not subject to income tax; trust unitholders are
subject to income tax on their pro rata share of trust income,
gain, loss and deduction.
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Corporations are taxed on their income and their stockholders
are taxed on dividends.
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Distributions
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Substantially all of the cash receipts of the trust is required
to be distributed to trust unitholders.
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Stockholders receive dividends at the discretion of the board of
directors.
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Business and Assets
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The business of the trust is limited to specific assets with a
finite economic life.
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A corporation conducts an active business for an unlimited term
and can reinvest its earnings and raise additional capital to
expand.
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Fiduciary Duties
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The trustee shall not be liable to the trust unitholders for any
of its acts or omissions absent its own fraud, gross negligence
or bad faith.
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Officers and directors have a fiduciary duty of loyalty to
stockholders and a duty to use due care in management and
administration of a corporation.
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TRUST UNITS
ELIGIBLE FOR FUTURE SALE
GENERAL
Prior to this offering, there has been no public market for the
trust units. Sales of substantial amounts of the trust units in
the open market, or the perception that those sales could occur,
could adversely affect prevailing market prices.
Upon completion of this offering, there will be outstanding
16,540,000 trust units. All of the 10,785,000 trust units sold
in this offering, or 12,402,750 trust units if the underwriters
exercise their option to purchase additional trust units in
full, will be freely tradable without restriction under the
Securities Act of 1933, as amended (the Securities
Act). All of the trust units outstanding other than the
trust units sold in this offering (a total of 5,755,000 trust
units, or 4,137,250 trust units if the underwriters exercise
their option to purchase additional trust units in full) will be
restricted securities within the meaning of
Rule 144 under the Securities Act and may not be sold other
than through registration under the Securities Act or pursuant
to an exemption from registration, subject to the restrictions
on transfer contained in the
lock-up
agreements described below and in Underwriting.
LOCK-UP
AGREEMENTS
In connection with this offering, VOC Sponsor and certain of its
affiliates, including VOC Partners, LLC, have agreed, for a
period of 180 days after the date of this prospectus, not
to offer, sell, contract to sell or otherwise dispose of or
transfer any trust units or any securities convertible into or
exchangeable for trust units without the prior written consent
of Raymond James & Associates, Inc., subject to
specified exceptions. See Underwriting for a
description of these
lock-up
arrangements. Upon the expiration of these
lock-up
agreements, 5,755,000 trust units, or 4,137,250 trust units if
the underwriters exercise their option to purchase additional
trust units in full, will be eligible for sale in the public
market under Rule 144 of the Securities Act, subject to
volume limitations and other restrictions contained in
Rule 144, or through registration under the Securities Act.
RULE 144
The trust units sold in the offering will generally be freely
transferable without restriction or further registration under
the Securities Act, except that any trust units owned by an
affiliate of the trust, including those held by VOC
Partners, LLC, 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 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 trust 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 the trust. A person who is not deemed to have been an
affiliate of VOC Sponsor or the trust at any time during the
three months preceding a sale, and who has beneficially owned
his trust units for at least six months (provided the trust is
in compliance with the current public information requirement)
or one year (regardless of whether the trust is in compliance
with the current public information requirement), would be
entitled to sell trust units under Rule 144 without regard
to
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the rules public information requirements, volume
limitations, manner of sale provisions and notice requirements.
REGISTRATION
RIGHTS
The trustee on behalf of the trust intends to enter into a
registration rights agreement with VOC Partners, LLC in
connection with the closing of this offering. In the
registration rights agreement, the trustee will agree to
register the trust units sold to VOC Partners, LLC.
Specifically, the trust will agree:
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subject to the restrictions described above under
Lock-up
agreements and under Underwriting
Lock-up
agreements, to use its reasonable best efforts to file a
registration statement, including, if so requested, a shelf
registration statement, with the SEC as promptly as practicable
following receipt of a notice requesting the filing of a
registration statement from holders representing a majority of
the then outstanding registrable trust units;
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to use its reasonable best efforts to cause the registration
statement or shelf registration statement to be declared
effective under the Securities Act as promptly as practicable
after the filing thereof; and
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to use commercially reasonable efforts to maintain the
effectiveness of the registration statement under the Securities
Act for 90 days (or for three years if a shelf registration
statement is requested) after the effectiveness thereof or until
the trust units covered by the registration statement have been
sold pursuant to such registration statement or until all
registrable trust units:
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have been sold pursuant to Rule 144 under the Securities
Act if the transferee thereof does not receive restricted
securities;
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have been sold in a private transaction in which the
transferors rights under the registration rights agreement
are not assigned to the transferee of the trust units; or
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become eligible for resale pursuant to Rule 144 (or any
similar rule then in effect under the Securities Act).
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VOC Partners, LLC will have the right to require the trust to
file no more than three registration statements in aggregate.
In connection with the preparation and filing of any
registration statement, VOC Partners, LLC will bear all costs
and expenses incidental to any registration statement, excluding
certain internal expenses of the trust, which will be borne by
the trust, and any underwriting discounts and commissions, which
will be borne by VOC Partners, LLC.
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FEDERAL
INCOME TAX CONSEQUENCES
U.S.
FEDERAL INCOME TAX CONSEQUENCES
The following is a discussion of the material U.S. federal
income tax considerations that may be relevant to prospective
trust unitholders and, unless otherwise noted in the following
discussion, expresses the opinion of Vinson & Elkins
L.L.P., insofar as it relates to matters of law and legal
conclusions. This section is based upon current provisions of
the Internal Revenue Code of 1986, as amended (the
Code), existing (and, to the extent noted, proposed)
Treasury regulations thereunder, and current administrative
rulings and court decisions, all of which are subject to change
or different interpretation at any time, possibly with
retroactive effect. Subsequent changes in such authorities may
cause the U.S. federal income tax consequences to vary
substantially from the consequences described below. No attempt
has been made in the following discussion to comment on all
U.S. federal income tax matters affecting the trust or the
trust unitholders.
The following discussion is limited to trust unitholders who
purchase the trust units upon the initial issuance at the
initial issue price (which will equal the first price at which a
substantial amount of trust units are sold to the public for
cash) and who hold the trust units as capital assets
(generally, property held for investment). All references to
trust unitholders (including U.S. trust
unitholders and
non-U.S. trust
unitholders) are to beneficial owners of the trust units. This
summary does not address the effect of the U.S. federal
estate or gift tax laws or the tax considerations arising under
the law of any state, local or
non-U.S. jurisdiction.
Moreover, the discussion has only limited application to trust
unitholders subject to specialized tax treatment such as,
without limitation:
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banks, insurance companies or other financial institutions;
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trust unitholders subject to the alternative minimum tax;
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tax-exempt organizations;
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dealers in securities or commodities;
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regulated investment companies;
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traders in securities that elect to use a
mark-to-market
method of accounting for their securities holdings;
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non-U.S. trust
unitholders (as defined below) that are controlled foreign
corporations or passive foreign investment
companies;
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persons that are S-corporations, partnerships or other
pass-through entities;
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persons that own their interest in the trust units through
S-corporations, partnerships or other pass-through entities;
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persons that at any time own more than 5% of the aggregate fair
market value of the trust units;
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expatriates and certain former citizens or long-term residents
of the United States;
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U.S. trust unitholders (as defined below) whose functional
currency is not the U.S. dollar;
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persons who hold the trust units as a position in a hedging
transaction, straddle, conversion
transaction or other risk reduction transaction; or
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persons deemed to sell the trust units under the constructive
sale provisions of the Code.
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Prospective investors are urged to consult their own tax
advisors as to the particular tax consequences to them of the
ownership and disposition of an investment in trust units,
including the applicability of any U.S. federal income,
federal estate or gift tax, state, local and foreign tax laws,
changes in applicable tax laws and any pending or proposed
legislation.
As used herein, the term U.S. trust unitholder
means a beneficial owner of trust units that for
U.S. federal income tax purposes is:
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an individual who is a citizen of the United States or who is a
resident of the United States for U.S. federal income
tax purposes,
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a corporation, or an entity treated as a corporation for
U.S. federal income tax purposes, created or organized in
or under the laws of the United States, a state thereof or the
District of Columbia,
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an estate the income of which is subject to U.S. federal
income taxation regardless of its source, or
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a trust if it is subject to the primary supervision of a
U.S. court and the control of one or more United States
persons (as defined for U.S. federal income tax purposes)
or that has a valid election in effect under applicable
U.S. Treasury regulations to be treated as a United States
person.
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The term
non-U.S. trust
unitholder means any beneficial owner of a trust unit,
other than an entity that is classified for U.S. federal
income tax purposes as a partnership, that is not a
U.S. trust unitholder.
If a partnership (including for this purpose any entity or
arrangement treated as a partnership for U.S. federal
income tax purposes) is a beneficial owner of trust units, the
tax treatment of a partner in the partnership will depend upon
the status of the partner and the activities of the partnership.
A trust unitholder that is a partnership, and the partners in
such partnership, should consult their own tax advisors about
the U.S. federal income tax consequences of purchasing,
owning, and disposing of trust units.
Classification
and Taxation of the Trust
In the opinion of Vinson & Elkins L.L.P., for
U.S. federal income tax purposes, the trust will be treated
as a grantor trust and not as an unincorporated business entity.
As a grantor trust, the trust will not be subject to tax at the
trust level. Rather, the grantors, who in this case are the
trust unitholders, will be considered to own and receive the
trusts assets and income and will be directly taxable
thereon as though no trust were in existence.
No ruling has been or will be requested from the Internal
Revenue Service (IRS) with respect to the
U.S. federal income tax treatment of the trust, including a
ruling as to the status of the trust as a grantor trust or as a
partnership for U.S. federal income tax purposes. Thus, no
assurance can be provided that the opinions and statements set
forth in this discussion of U.S. federal income tax
consequences would be sustained by a court if contested by the
IRS.
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The remainder of the discussion below is based on
Vinson & Elkins L.L.P.s opinion that the trust
will be classified as a grantor trust for federal income tax
purposes.
Reporting
Requirements for Widely-Held Fixed Investment
Trusts
Under Treasury Regulations, the trust is classified as a
widely-held fixed investment trust. Those Treasury Regulations
require the sharing of tax information among trustees and
intermediaries that hold a trust interest on behalf of or for
the account of a beneficial owner or any representative or agent
of a trust interest holder of fixed investment trusts that are
classified as widely-held fixed investment trusts. These
reporting requirements provide for the dissemination of trust
tax information by the trustee to intermediaries who are
ultimately responsible for reporting the investor-specific
information through Form 1099 to the investors and the IRS.
Every trustee or intermediary that is required to file a
Form 1099 for a trust unitholder must furnish a written tax
information statement that is in support of the amounts as
reported on the applicable Form 1099 to the trust
unitholder. Any generic tax information provided by the trustee
of the trust is intended to be used only to assist trust
unitholders in the preparation of their federal and state income
tax returns.
Direct
Taxation of Trust Unitholders
Because the trust will be treated as a grantor trust for
U.S. federal income tax purposes, trust unitholders will be
treated for such purposes as owning a direct interest in the
assets of the trust, and each trust unitholder will be taxed
directly on his pro rata share of the income and gain
attributable to the assets of the trust and will be entitled to
claim his pro rata share of the deductions and expenses
attributable to the assets of the trust (subject to certain
limitations discussed below). Information returns will be filed
as required by the widely held fixed investment trust rules,
reporting to the trust unitholders all items of income, gain,
loss, deduction and credit, which will be allocated based on
record ownership on the quarterly record dates and must be
included in the tax returns of the trust unitholders. Income,
gain, loss, deduction and credits attributable to the assets of
the trust will be taken into account by trust unitholders
consistent with their method of accounting and without regard to
the taxable year or accounting method employed by the trust.
Following the end of each quarter, the trustee will determine
the amount of funds available as of the end of such quarter for
distribution to the trust unitholders and will make
distributions of available funds, if any, to the unitholders on
or about the 45th day following the end of the quarter to
the unitholders of record on the 30th day following the end
of such quarter. In certain circumstances, however, a trust
unitholder will not receive a distribution of cash attributable
to the income from a quarter. For example, if the trustee
establishes a reserve or borrows money to satisfy liabilities of
the trust, income associated with the cash used to establish
that reserve or to repay that loan must be reported by the trust
unitholder, even though that cash is not distributed to him.
As described above, the trust will allocate items of income,
gain, loss, deductions and credits to trust unitholders based on
record ownership on the quarterly record dates. It is possible
that the IRS could disagree with this allocation method and
could assert that income and deductions of the trust should be
determined and allocated on a daily or prorated basis, which
could require adjustments to the tax returns of the unitholders
affected by the issue and result in an increase in the
administrative expense of the trust in subsequent periods.
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
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long-term capital gains (generally, capital gains on certain
assets held for more than 12 months) 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. Moreover, these rates are subject
to change by new legislation at any time.
The recently enacted Health Care and Education Reconciliation
Act of 2010 will impose a 3.8% Medicare tax on certain
investment income earned by individuals and certain estates and
trusts for taxable years beginning after December 31, 2012.
For these purposes, investment income would generally include
interest income derived from investments such as the trust units
and gain realized by a trust unitholder from a sale of trust
units. In the case of an individual, the tax will be imposed on
the lesser of (i) the trust unitholders net income
from all investments, and (ii) the amount by which the
trust unitholders modified adjusted gross income exceeds
$250,000 (if the trust unitholder is married and filing jointly
or a surviving spouse) or $200,000 (if the trust unitholder is
not married). In the case of an estate or trust, the tax will be
imposed on the lesser of (1) undistributed net investment
income, or (2) the excess adjusted gross income over the
dollar amount at which the highest income tax bracket applicable
to an estate or trust begins.
Classification
of the Net Profits Interest
Based on representations made by VOC Sponsor regarding the
expected economic life of the Underlying Properties and the
expected duration of the Net Profits Interest, in the opinion of
Vinson & Elkins L.L.P., (i) the Net Profits Interest
should be treated as a production payment under
Section 636 of the Code or otherwise as a debt instrument
for U.S. federal income tax purposes and (ii) the Net
Profits Interest should therefore be treated as indebtedness
subject to the Treasury Regulations applicable to contingent
payment debt instruments (the CPDI regulations).
Thus, each trust unitholder should be treated as making a loan
on the Underlying Properties to VOC Sponsor in an aggregate
amount generally equal to the purchase price of the trust units
(less an amount equal to the distribution attributable to the
period from January 1, 2011 through June 30,
2011) and proceeds payable to the trust from the sale of
production from the burdened properties (after June 30,
2011) should be treated as payments of principal and
interest on a debt instrument issued by VOC Sponsor.
Based on such opinions, VOC Sponsor and the trust will treat the
Net Profits Interest as indebtedness subject to the CPDI
regulations, and by purchasing trust units, each trust
unitholder will agree to be bound by VOC Sponsors
application of the CPDI regulations, including its determination
of the rate at which interest will be deemed to accrue on the
Net Profits Interest (treated as a debt instrument for
U.S. federal income tax purposes). No assurance can be
given that the IRS will not assert that the Net Profits Interest
should be treated differently. Such different treatment could
affect the amount, timing and character of income, gain or loss
in respect of an investment in trust units and could require a
trust unitholder to accrue interest income at a rate different
than the comparable yield described below.
The portion of the purchase price of the trust units
attributable to the right to receive a distribution based on
production from the Underlying Properties for the period
commencing January 1, 2011 and ending on June 30, 2011
will be treated as a tax-free return of capital when such
distribution is received.
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TAX
CONSEQUENCES TO U.S. TRUST UNITHOLDERS
Tax
Treatment of Net Profits Interest
Under the CPDI regulations, a U.S. trust unitholder generally
will be required to accrue income on the Net Profits Interest in
the amounts described below, regardless of whether the
U.S. trust unitholder uses the cash or accrual method of
tax accounting.
The CPDI regulations provide that a U.S. trust unitholder
must accrue an amount of ordinary interest income for
U.S. federal income tax purposes, for each accrual period
prior to and including the maturity date of the debt instrument
that equals:
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the product of (i) the adjusted issue price (as defined
below) of the debt instrument represented by ownership of trust
units as of the beginning of the accrual period; and
(ii) the comparable yield to maturity (as defined below) of
such debt instrument, adjusted for the length of the accrual
period;
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divided by the number of days in the accrual period; and
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multiplied by the number of days during the accrual period that
the trust unitholder held the trust units.
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The issue price of the debt instrument held by the
trust is the first price at which a substantial amount of the
trust units is sold to the public excluding sales to bond
houses, brokers or similar persons or organizations acting in
the capacity of underwriters, placement agents or wholesalers.
The adjusted issue price of such a debt instrument
is its issue price increased by any interest income previously
accrued, determined without regard to any adjustments to
interest accruals described below, and decreased by the
projected amount of any payments scheduled to be made with
respect to the debt instrument at an earlier time.
Under the CPDI regulations, VOC Brazos is required to establish
the comparable yield for the debt instrument represented by
ownership of the trust units. The term comparable
yield means the annual yield VOC Brazos would be expected
to pay, as of the initial issue date, on a fixed rate debt
security with no contingent payments but with terms and
conditions otherwise comparable to those of the debt instrument
represented by ownership of trust units. Based on discussions
with the underwriters, VOC Brazos has determined that the
comparable yield for the Net Profits Interest (treated as a debt
instrument) held by the trust is an annual rate of 9%,
compounded semi-annually. The CPDI regulations require that the
trust provide to trust unitholders, solely for determining the
amount of interest accruals for U.S. federal income tax
purposes, a schedule of the projected amounts of payments, which
are referred to as projected payments, on the debt instrument
held by the trust. These payments set forth on the schedule must
produce a total return on such debt instrument equal to its
comparable yield. Amounts treated as interest under the CPDI
regulations are treated as original issue discount for all
purposes of the Code.
As required by the CPDI regulations, for U.S. federal
income tax purposes, each holder of trust units must use the
comparable yield and the schedule of projected payments as
described above in determining its interest accruals, and the
adjustments thereto described below, in respect of the debt
instrument held by the trust. You may obtain the projected
payment schedule by submitting a written request for such
information to VOC Brazos at 1700 Waterfront Parkway, Building
500, Wichita, Kansas 67206, Attention: Chief Financial Officer.
Our determinations of the comparable yield and the projected
payment schedule are not binding on the IRS and it could
challenge such determinations. If it did so, and if any such
108
challenge were successful, then the amount and timing of
interest income accruals of the trust unitholders would be
different from those reported by us or included on previously
filed tax returns by the trust unitholders.
The comparable yield and the schedule of projected payments are
not determined for any purpose other than for the determination
for U.S. federal income tax purposes of a trust
unitholders interest accruals and adjustments thereof in
respect of the debt instrument represented by ownership of trust
units and do not constitute a projection or representation
regarding the actual amounts payable on the trust units.
If, during any taxable year, the trust receives actual payments
with respect to the debt instrument held by the trust that in
the aggregate exceed the total amount of projected payments for
that taxable year, the trust will incur a net positive
adjustment under the CPDI regulations equal to the amount
of such excess. The trust will treat a net positive
adjustment as additional ordinary interest income for that
taxable year.
If the trust receives in a taxable year actual payments with
respect to the debt instrument held by the trust that in the
aggregate are less than the amount of projected payments for
that taxable year, the trust will incur a net negative
adjustment under the CPDI regulations equal to the amount
of such deficit. This adjustment will (a) first reduce the
trusts interest income on the debt instrument held by the
trust for that taxable year, and (b) to the extent of any
excess after the application of (a) give rise to an
ordinary loss to the extent of the trusts interest income
on such debt instrument during prior taxable years, reduced to
the extent such interest was offset by prior net negative
adjustments. Any negative adjustment in excess of the amount
described in (a) and (b) will be carried forward, as a
negative adjustment to offset future interest income in respect
of the debt instrument held by the trust or to reduce the amount
realized on a sale, exchange, conversion or retirement of such
debt instrument.
Neither the trust nor the trust unitholders are entitled to
claim depletion deductions with respect to the Net Profits
Interest.
If the Net Profits Interest is not treated as a debt instrument,
a trust unitholder would be allowed to recoup its basis in the
Net Profits Interest on a schedule that is in proportion to
expected production from the Net Profits Interest, with the
effect that a trust unitholder would be entitled to deductions
in respect of basis recovery on a schedule that is more
favorable compared to the trust unitholders entitlement to
treat a portion of its receipts as return of principal if the
Net Profits Interest is treated, in accordance with tax
counsels opinion, as a debt instrument. In that case,
however, the deductions so allowed may be itemized deductions,
the deductibility of which would be subject to limitations that
disallow itemized deductions that are less than 2% of a
taxpayers adjusted gross income, or reduce the amount of
itemized deductions that are otherwise allowable by the lesser
of (i) 3% of (A) adjusted gross income over
(B) $100,000 ($50,000 in the case of a separate return by a
married individual), subject to adjustment for inflation and
(ii) 80% of the amount of itemized deductions that are
otherwise allowable, or both. Although the matter is not free
from doubt, tax counsel believes that, if the issue became
relevant as a result of the classification of the Net Profits
Interest as other than a debt instrument, deductions in respect
of basis recovery should not be itemized deductions, as the
deductions should, under Section 62(a)(4) of the Code, be
considered deductions that are attributable to property held for
the production of royalty income.
Disposition
of Trust Units
For U.S. federal income tax purposes, a sale of trust units
will be treated as a sale by the U.S. trust unitholder of
his interest in the assets of the trust. Generally, a
U.S. trust unitholder
109
will recognize gain or loss on a sale or exchange of trust units
equal to the difference between the amount realized and the
U.S. trust unitholders adjusted tax basis for the
trust units sold. A U.S. trust unitholders adjusted
tax basis in his trust units will be equal to the
U.S. trust unitholders original purchase price for
the trust units, increased by any interest income previously
accrued by the U.S. trust unitholder (determined without
regard to any adjustments to interest accruals for positive or
negative adjustments as described above) and decreased by the
amount of any projected payments that have been previously
scheduled to be made in respect of the trust units (without
regard to the actual amount paid).
Under the CPDI regulations, gain recognized upon a sale or
exchange of a trust unit attributable to the Net Profits
Interest (the amount of which is reduced by any unused
adjustments as discussed above) will generally be treated as
ordinary interest income. Any loss will be ordinary loss to the
extent of interest previously included in income (reduced by any
negative adjustments thereto), and thereafter, capital loss
(which will be long-term if the trust unit is held for more than
one year). Net capital loss may offset no more than $3,000 of
ordinary income in the case of individuals and may only be used
to offset capital gain in the case of corporations.
Trust Administrative
Expenses
Expenses of the trust will include administrative expenses of
the trustee. As discussed above, certain miscellaneous itemized
deductions may generally be subject to limitations on
deductibility. Under these rules, administrative expenses
attributable to the trust units are miscellaneous itemized
deductions that generally will have to be aggregated with an
individual unitholders other miscellaneous itemized
deductions to determine the excess over 2% of adjusted gross
income. It is anticipated that the amount of such administrative
expenses will not be significant in relation to the trusts
income.
Backup
Withholding and Information Reporting
Payments of principal and interest on, and the proceeds of
dispositions of, the trust units, may be subject to information
reporting and U.S. federal backup withholding tax if the
trust unitholder thereof fails to supply an accurate taxpayer
identification number or otherwise fails to comply with
applicable U.S. information reporting or certification
requirements. Any amounts so withheld will be allowed as a
credit against the trust unitholders U.S. federal
income tax liability and may entitle the trust unitholder to a
refund, provided that the required information is timely
furnished to the IRS.
TAX
CONSEQUENCES TO
NON-U.S.
TRUST UNITHOLDERS
The following is a summary of certain material U.S. federal
income tax consequences that will apply to you if you are a
non-U.S. trust
unitholder.
Non-U.S. trust
unitholders should consult their own independent tax advisors to
determine the U.S. federal, state, local and foreign tax
consequences that may be relevant to them.
Payments
with Respect to the Trust Units
Interest paid with respect to the Net Profits Interest will be
treated as interest, the amount of which is
contingent on the earnings of VOC Sponsor from the
Underlying Properties, and thus will not qualify for the
portfolio interest exemption under Sections 871
and 881 of the Code. As a result, such interest will be subject
to U.S. federal withholding tax at a 30% rate unless the
non-U.S. trust
unitholder is eligible for a lower rate under an applicable
income tax treaty or the interest is effectively connected with
the
non-U.S. trust
unitholders conduct of a trade or
110
business in the United States, and in either case, the
non-U.S. trust
unitholder provides appropriate certification. A
non-U.S. trust
unitholder generally can meet the certification requirement by
providing an IRS
Form W-8BEN
(in the case of a claim of treaty benefits) or a
W-8 ECI
(with respect to the
non-U.S. trust
unitholders conduct of a U.S. trade or business).
If a
non-U.S. trust
unitholder is engaged in a trade or business in the United
States, and if payments on or gain realized on a sale or other
disposition of a trust unit are effectively connected with the
conduct of this trade or business, the
non-U.S. trust
unitholder, although exempt from U.S. withholding tax (if
the appropriate certification is furnished), will generally be
taxed in the same manner as a U.S. trust unitholder (see
Tax consequences to U.S. trust
unitholders above). Any such
non-U.S. trust
unitholder should consult its own tax advisers with respect to
other tax consequences of the ownership of the trust units,
including the possible imposition of a 30% branch profits tax in
the case of a
non-U.S. trust
unitholder that is classified for federal income tax purposes as
a corporation.
Sale
or Exchange of Trust Units
The Net Profits Interest will be treated as United States
real property interests for U.S. federal income tax
purposes. However, as long as the trust units are regularly
traded on an established securities market, gain realized by a
non-U.S. trust
unitholder on a sale of trust units will be subject to federal
income tax only if:
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the gain is, or is treated as, effectively connected with
business conducted by the
non-U.S. trust
unitholder in the United States, and in the case of an
applicable tax treaty, is attributable to a U.S. permanent
establishment maintained by the
non-U.S. trust
unitholder;
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the
non-U.S. trust
unitholder is an individual who is present in the United States
for at least 183 days in the year of the sale; or
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the
non-U.S. trust
unitholder owns currently or owned at certain earlier times
directly or by applying certain attribution rules, more than 5%
of the trusts units.
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A
non-U.S. trust
unitholder will be subject to U.S. federal income tax on
any gain allocable to the
non-U.S. trust
unitholder upon the sale by the trust of all or any part of the
Net Profits Interest, and distributions to the
non-U.S. trust
unitholder will be subject to withholding of U.S. tax
(currently at the rate of 35%) to the extent the distributions
are attributable to such gains.
Backup
Withholding Tax and Information Reporting
Payments to
non-U.S. trust
unitholders of interest, and amounts withheld from such
payments, if any, generally will be required to be reported to
the IRS and to the
non-U.S. trust
unitholder.
A
non-U.S. trust
unitholder may be subject to backup withholding tax, currently
at a rate of 28%, with respect to payments from the trust and
the proceeds from dispositions of trust units, unless such
non-U.S. trust
unitholder complies with certain certification requirements
(usually satisfied by providing a duly completed IRS
Form W-8BEN)
or otherwise establishes an exemption. Backup withholding is not
an additional tax. Any amounts withheld under the backup
withholding rules will be allowed as a refund or a credit
against a
non-U.S. trust
unitholders U.S. federal income tax liability,
provided certain required information is provided to the IRS.
111
Payments of the proceeds of a sale of a trust unit effected by
the U.S. office of a U.S. or foreign broker will be
subject to information reporting requirements and backup
withholding unless the
non-U.S. trust
unitholder properly certifies under penalties of perjury as to
its foreign status and certain other conditions are met or the
non-U.S. trust
unitholder otherwise establishes an exemption. Information
reporting requirements and backup withholding generally will not
apply to any payment of the proceeds of the sale of a trust unit
effected outside of the United States by a foreign office of a
broker. However, unless such a broker has documentary evidence
in its records that the holder is a
non-U.S. trust
unitholder and certain other conditions are met, or the
non-U.S. trust
unitholder otherwise establishes an exemption, information
reporting will apply to a payment of the proceeds of the sale of
a trust unit effected outside the United States by such a broker
if it:
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is a United States person;
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derives 50% or more of its gross income for certain periods from
the conduct of a trade or business in the United States;
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is a controlled foreign corporation for U.S. federal income
tax purposes; or
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is a foreign partnership that, at any time during its taxable
year, has more than 50% of its income or capital interests owned
by United States persons or is engaged in the conduct of a
U.S. trade or business.
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Any amount withheld under the backup withholding rules may be
credited against the
non-U.S. trust
unitholders U.S. federal income tax liability and any
excess may be refundable if the proper information is provided
to the IRS.
CONSEQUENCES
TO TAX EXEMPT ORGANIZATIONS
Employee benefit plans and most other organizations exempt from
U.S. federal income tax including IRAs and other retirement
plans are subject to U.S. federal income tax on unrelated
business taxable income. Because the trusts income is not
expected to be unrelated business taxable income, such a
tax-exempt organization is not expected to be taxed on income
generated by ownership of trust units so long as neither the
property held by the trust nor the trust units are treated as
debt-financed property within the meaning of Section 514(b)
of the Code. In general, trust property would be debt-financed
if the trust incurs debt to acquire the property or otherwise
incurs or maintains a debt that would not have been incurred or
maintained if the property had not been acquired and a trust
unit would be debt-financed if the trust unitholder incurs debt
to acquire the trust unit or otherwise incurs or maintains a
debt that would not have been incurred or maintained if the
trust unit had not been acquired.
PROSPECTIVE INVESTORS IN TRUST UNITS ARE STRONGLY
ENCOURAGED TO CONSULT THEIR OWN TAX ADVISORS WITH RESPECT TO THE
TAX CONSEQUENCES TO THEM OF THE PURCHASE, OWNERSHIP AND
DISPOSITION OF THE TRUST UNITS IN LIGHT OF THEIR OWN
PARTICULAR CIRCUMSTANCES, INCLUDING THE TAX CONSEQUENCES UNDER
STATE, LOCAL, FOREIGN AND OTHER TAX LAWS AND THE POSSIBLE
EFFECTS OF CHANGES IN UNITED STATES FEDERAL OR OTHER TAX LAWS.
112
STATE TAX
CONSIDERATIONS
The following is intended as a brief summary of certain
information regarding state income taxes and other state tax
matters affecting individuals who are trust unitholders. No
opinion of counsel has been requested or received with respect
to the state tax consequences of an investment in trust units.
Unitholders are urged to consult their own legal and tax
advisors with respect to these matters.
Prospective investors should consider state and local tax
consequences of an investment in the trust units. The trust will
own the Net Profits Interest burdening specified oil and natural
gas properties located in the states of Kansas and Texas. Kansas
currently imposes a personal income tax on individuals, but
Texas currently does not.
Kansas income tax law generally conforms to the federal income
tax laws, meaning that for Kansas income tax purposes, the trust
should be treated as a grantor trust, a trust unitholder should
be considered to own and receive his or her share of the
trusts assets and income, and the Net Profits Interest
should be treated as a debt instrument. If treated as owning a
debt instrument through a grantor trust, an individual trust
unitholder who is a nonresident of Kansas generally will not be
subject to Kansas income tax on his share of the trusts
income, except to the extent the trust units are employed by
such trust unitholder in a trade, business, profession or
occupation carried on in Kansas. In general, an individual trust
unitholder will not be deemed to carry on a trade, business,
profession or occupation in Kansas solely by reason of the
purchase and sale of trust units for such nonresidents own
account as an investor. An individual trust unitholder who is a
resident of Kansas will be subject to Kansas income tax on his
share of the trusts income. The trust should not be
required to withhold Kansas income tax from distributions made
to an individual resident or nonresident trust unitholder as
long as the trust is taxed as a grantor trust, and the Net
Profits Interest is treated as a debt instrument, for federal
income tax purposes.
The trust units may constitute real property or an interest in
real property under the inheritance, estate and probate laws of
Texas and Kansas.
113
ERISA
CONSIDERATIONS
The Employee Retirement Income Security Act of 1974, as amended,
regulates pension, profit-sharing and other employee benefit
plans to which it applies. ERISA also contains standards for
persons who are fiduciaries of those plans. In addition, the
Internal Revenue Code provides similar requirements and
standards which are applicable to qualified plans, which include
these types of plans, and to individual retirement accounts,
whether or not subject to ERISA.
A fiduciary of an employee benefit plan should carefully
consider fiduciary standards under ERISA regarding the
plans particular circumstances before authorizing an
investment in trust units. A fiduciary should consider:
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whether the investment satisfies the prudence requirements of
Section 404(a)(1)(B) of ERISA;
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whether the investment satisfies the diversification
requirements of Section 404(a)(1)(C) of ERISA; and
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whether the investment is in accordance with the documents and
instruments governing the plan as required by
Section 404(a)(1)(D) of ERISA.
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A fiduciary should also consider whether an investment in trust
units might result in direct or indirect nonexempt prohibited
transactions under Section 406 of ERISA and Internal
Revenue Code Section 4975. In deciding whether an
investment involves a prohibited transaction, a fiduciary must
determine whether there are plan assets in the transaction. The
Department of Labor has published final regulations concerning
whether or not an employee benefit plans assets would be
deemed to include an interest in the underlying assets of an
entity for purposes of the reporting, disclosure and fiduciary
responsibility provisions of ERISA and analogous provisions of
the Internal Revenue Code. These regulations provide that the
underlying assets of an entity will not be considered plan
assets if the equity interests in the entity are a
publicly offered security. VOC Sponsor expects that at the time
of the sale of the trust units in this offering, they will be
publicly offered securities. Fiduciaries, however, will need to
determine whether the acquisition of trust units is a nonexempt
prohibited transaction under the general requirements of ERISA
Section 406 and Internal Revenue Code Section 4975.
The prohibited transaction rules are complex, and persons
involved in prohibited transactions are subject to penalties.
For that reason, potential employee benefit plan investors
should consult with their counsel to determine the consequences
under ERISA and the Internal Revenue Code of their acquisition
and ownership of trust units.
114
SELLING
TRUST UNITHOLDER
Immediately prior to the closing of the offering made hereby,
VOC Sponsor will convey to the trust the Net Profits Interest in
exchange for 16,540,000 trust units. Of those trust units,
10,785,000 are being offered hereby and 1,617,750 are subject to
purchase by the underwriters pursuant to their
30-day
option to purchase additional trust units. Further, VOC Sponsor
has agreed to sell to VOC Partners, LLC, an affiliate of
VOC Sponsor, all remaining trust units it holds
45 days following the closing of the offering made hereby.
VOC Sponsor and VOC Partners, LLC have agreed not to sell any of
such trust units for a period of 180 days after the date of
this prospectus without the prior written consent of Raymond
James & Associates, Inc., acting as representative of
the several underwriters. See Underwriting.
The following table provides information regarding the selling
trust unitholders ownership of the trust units.
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Ownership of Trust
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Number of
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Ownership of Trust
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Units Before Offering
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Trust Units
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Units After Offering (1)
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Selling Trust Unitholders
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Number
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Percentage
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Being Offered
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Number
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Percentage
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VOC Sponsor
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16,540,000
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100
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%
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12,402,750
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(2)
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(1)
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Gives effect to the sale of trust
units to VOC Partners, LLC 45 days following the closing of
the offering.
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(2)
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Includes 1,617,750 trust units
subject to purchase by the underwriters pursuant to their
30-day option to purchase additional trust units.
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Prior to this offering, there has been no public market for the
trust units. Therefore, if VOC Partners, LLC disposes all or a
portion of the trust units acquired from VOC Sponsor
45 days following the closing of this offering, the effect
of such disposal on future market prices, if any, of market
sales of such remaining trust units or the availability of trust
units for sale cannot be predicted. Nevertheless, sales of
substantial amounts of trust units in the public market could
adversely affect future market prices.
115
UNDERWRITING
Subject to the terms and conditions in an underwriting agreement
dated ,
2011, the underwriters named below, for whom Raymond
James & Associates, Inc. and Morgan Stanley & Co.
Incorporated are acting as representatives, have severally
agreed to purchase from VOC Sponsor the number of trust units
set forth opposite their names:
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Number of
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Underwriter
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Trust Units
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Raymond James & Associates, Inc.
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Morgan Stanley & Co. Incorporated
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Oppenheimer & Co. Inc.
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RBC Capital Markets, LLC
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Robert W. Baird & Co. Incorporated
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Janney Montgomery Scott LLC
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Morgan Keegan & Company, Inc.
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Wunderlich Securities, Inc.
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Total
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10,785,000
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The underwriting agreement provides that the obligations of the
underwriters to purchase and accept delivery of the trust units
offered by this prospectus are subject to approval by their
counsel of legal matters and to certain other customary
conditions set forth in the underwriting agreement, including:
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the accuracy of representations and warranties made by VOC
Sponsor and the trust to the underwriters;
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there having been no material adverse change in financial
markets or in the condition (financial or otherwise), business,
prospects, management or results of operations of VOC Sponsor or
the trust; and
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VOC Sponsors and the trusts delivery of customary
closing documents, and the delivery of legal opinions, to the
underwriters.
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The underwriters are obligated to purchase and accept delivery
of all of the trust units offered by this prospectus if any of
the units are purchased, other than those covered by the option
to purchase additional trust units described below.
The underwriters propose to offer the trust units directly to
the public at the public offering price indicated on the cover
page of this prospectus and to various dealers at that price
less a concession not in excess of
$ per unit. If all of the trust
units are not sold at the public offering price, the
underwriters may change the public offering price and other
selling terms. The trust units are offered by the underwriters
as stated in this prospectus, subject to receipt and acceptance
by them. The underwriters reserve the right to reject an order
for the purchase of the trust units in whole or in part.
OPTION TO
PURCHASE ADDITIONAL TRUST UNITS
VOC Sponsor has granted the underwriters an option, exercisable
for 30 days after the date of this prospectus, to purchase
from time to time up to an aggregate of 1,617,750 additional
trust units to cover over-allotments, if any, at the public
offering price less the underwriting discounts and commissions
set forth on the cover page of this prospectus. If the
underwriters exercise this option, each underwriter, subject to
certain conditions, will become obligated to purchase its pro
rata portion of these additional units based on the
underwriters percentage purchase
116
commitment in this offering as indicated in the table above. The
underwriters may exercise the option to purchase additional
trust units only to cover over-allotments made in connection
with the sale of the trust units offered in this offering.
DISCOUNTS
AND EXPENSES
The following table shows the amount per unit and total
underwriting discounts and commissions VOC Sponsor will pay to
the underwriters (dollars in thousands, except per unit). The
amounts are shown assuming both no exercise and full exercise of
the underwriters option to purchase additional trust units.
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Per Unit
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No Exercise
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Full Exercise
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Public offering price
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$
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$
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$
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Underwriting discounts and commissions
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Proceeds, before expenses, to VOC Sponsor
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VOC Sponsor will pay Raymond James & Associates, Inc.
a structuring fee of 0.5% of the gross proceeds of this offering
for evaluation, analysis and structuring of the trust.
The expenses of this offering that are payable by VOC Sponsor
are estimated to be $2.3 million (exclusive of underwriting
discounts, commissions and structuring fees). This offering is
being made in compliance with Rule 2310 of the Financial
Industry Regulatory Authority, Inc., or FINRA. In no
event will the maximum amount of compensation to be paid to
FINRA members in connection with this offering exceed 10% of the
offering proceeds.
INDEMNIFICATION
VOC Sponsor and the trust have agreed to indemnify the
underwriters and persons who control the underwriters against
certain liabilities that may arise in connection with this
offering, including liabilities under the Securities Act and
liabilities arising from breaches of representations and
warranties contained in the underwriting agreement.
LOCK-UP
AGREEMENTS
VOC Sponsor and certain of its affiliates, including VOC
Partners, LLC, have agreed with the underwriters, for a period
of 180 days after the date of this prospectus, without the
prior written consent of the representatives:
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not to offer, sell, contract to sell, announce the intention to
sell or pledge any of the trust units;
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not to grant or sell any option or contract to purchase any of
the trust units;
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not to enter into any swap or other agreement that transfers any
of the economic consequences of ownership of or otherwise
transfer or dispose of, directly or indirectly, any of the trust
units; and
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not to enter into any hedging, collar or other transaction or
arrangement that is designed or reasonably expected to lead to
or result in a transfer, in whole or in part, of any of the
economic consequences of ownership of the trust units, whether
or not such transfer would be for any consideration.
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These agreements also prohibit such persons from entering into
any of the foregoing transactions with respect to any securities
that are convertible into or exchangeable for the trust units.
The representatives may, in their discretion and at any time
without notice, release all or any portion of the securities
subject to these agreements. The representatives do not have any
present intent or any understanding to release all or any
portion of the securities subject to these agreements.
The 180-day
period described in the preceding paragraphs will be extended if:
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during the last 17 days of the
180-day
period, the trust issues a release concerning earnings or
announces material news or a material event relating to the
trust occurs; or
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prior to the expiration of the
180-day
period, the trust announces that it will release distributable
cash during the
16-day
period beginning on the last day of the
180-day
period, in which case the restrictions described in the
preceding paragraphs will continue to apply until the expiration
of the
18-day
period beginning on the issuance of the earnings release, the
announcement of the material news or the occurrence of the
material event.
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The restrictions described above do not apply to the sale of
trust units by VOC Sponsor to the underwriters pursuant to the
underwriting agreement and the sale of up to
1,617,750 trust units by VOC Sponsor to its affiliate, VOC
Partners, LLC, 45 days following the closing of this
offering.
STABILIZATION
Until this offering is completed, rules of the SEC may limit the
ability of the underwriters and various selling group members to
bid for and purchase the trust units. As an exception to these
rules and in accordance with Regulation M under the
Exchange Act, the underwriters may engage in activities that
stabilize, maintain or otherwise affect the price of the trust
units in order to facilitate this offering of trust units,
including:
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short sales;
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syndicate covering transactions;
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imposition of penalty bids; and
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purchases to cover positions created by short sales.
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Stabilizing transactions may include making short sales of trust
units, which involve the sale by the underwriter of a greater
number of trust units than it is required to purchase in this
offering and purchasing trust units from VOC Sponsor by
exercising the over-allotment option or in the open market to
cover positions created by short sales. Short sales may be
covered shorts, which are short positions in an
amount not greater than the underwriters option to
purchase additional trust units referred to above, or may be
naked shorts, which are short positions in excess of
that amount.
Each underwriter may close out any covered short position either
by exercising its option to purchase additional trust units, in
whole or in part, or by purchasing trust units in the open
market after the distribution has been completed. In making this
determination, each underwriter
118
will consider, among other things, the price of trust units
available for purchase in the open market compared to the price
at which the underwriter may purchase trust units pursuant to
the option to purchase additional trust units.
A naked short position is more likely to be created if the
underwriters are concerned that there may be downward pressure
on the price of the trust units in the open market after pricing
that could adversely affect investors who purchased in this
offering. To the extent that the underwriters create a naked
short position, they will purchase trust units in the open
market to cover the position after the pricing of this offering.
The underwriters also may impose a penalty bid on selling group
members. This means that if the underwriters purchase trust
units in the open market in stabilizing transactions or to cover
short sales, the underwriters can require the selling group
members that sold those trust units as part of this offering to
repay the selling concession received by them.
As a result of these activities, the price of the trust units
may be higher than the price that otherwise might exist in the
open market. If the underwriters commence these activities, they
may discontinue them without notice at any time. The
underwriters may carry out these transactions on the New York
Stock Exchange or otherwise.
DISCRETIONARY
ACCOUNTS
The underwriters may confirm sales of the trust units offered by
this prospectus to accounts over which they exercise
discretionary authority but do not expect those sales to exceed
5% of the total trust units offered by this prospectus.
LISTING
The trust units have been approved for listing on the New York
Stock Exchange under the symbol VOC, subject to
notice of official issuance. In connection with the listing of
the trust units on the New York Stock Exchange, the
underwriters will undertake to sell round lots of 100 units
or more to a minimum of 400 beneficial owners.
IPO
PRICING
Prior to this offering, there has been no public market for the
trust units. Consequently, the initial public offering price for
the trust units will be determined by negotiations among VOC
Sponsor and the underwriters. The primary factors to be
considered in determining the initial public offering price will
be:
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estimates of distributions to trust unitholders;
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overall quality of the oil and natural gas properties
attributable to the Underlying Properties;
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industry and market conditions prevalent in the energy industry;
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the information set forth in this prospectus and otherwise
available to the representatives; and
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the general conditions of the securities markets at the time of
this offering.
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119
ELECTRONIC
PROSPECTUS
A prospectus in electronic format may be available on the
Internet sites or through other online services maintained by
one or more of the underwriters and 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 underwriter or the selling group member,
prospective investors may be allowed to place orders online. The
underwriters may agree with VOC Sponsor to allocate a specific
number of trust 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, the information
on any underwriters or any selling group members
website and any information contained in any other website
maintained by the underwriters or any selling group member is
not part of this prospectus or the registration statement of
which this prospectus forms a part, has not been approved or
endorsed by VOC Sponsor or any underwriters or any selling group
member in its capacity as underwriter or selling group member
and should not be relied upon by investors.
CONFLICTS/AFFILIATES
The underwriters and their affiliates may provide in the future
investment banking, financial advisory or other financial
services for VOC Sponsor and its affiliates, for which they may
receive advisory or transaction fees, as applicable, plus
out-of-pocket
expenses, of the nature and in amounts customary in the industry
for these financial services.
DIRECTED
UNIT PROGRAM
At VOC Sponsors request, the underwriters have reserved up
to 5% of the units being offered by this prospectus for sale at
the initial offering price to VOC Sponsors limited
partners, executive management team (certain officers and
employees of Vess Oil on behalf of VOC Sponsors general
partner) and certain other persons associated with VOC Sponsor,
as designated by VOC Sponsor. The sales will be made by Raymond
James & Associates, Inc. through a directed unit
program. We do not know if these persons will choose to purchase
all or any portion of these reserved units, but any purchases
they do make will reduce the number of units available to the
general public. To the extent the allotted reserved units are
not purchased in the directed unit program, we will offer these
units to the general public on the same basis as all other units
offered by this prospectus. These persons must commit to
purchase no later than before the open of business on the day
following the date of this prospectus, but in any event, these
persons are not obligated to purchase units. Any members of VOC
Sponsors limited partners, executive management team or
other persons associated with VOC Sponsor purchasing reserved
units will be subject to a lock-up agreement for up to
180 days after the date of this prospectus. VOC Sponsor has
agreed to indemnify Raymond James & Associates, Inc.
against certain liabilities and expenses, including liabilities
under the Securities Act of 1933, as amended, in connection with
the sales of the reserved units.
FINRA
RULES
Because FINRA is expected to view the trust units offered hereby
as interests in a direct participation program, this offering is
being made in compliance with Rule 2310 of the FINRA
Conduct Rules. Investor suitability with respect to the trust
units should be judged similarly to the suitability with respect
to other securities that are listed for trading on a national
securities exchange.
120
LEGAL
MATTERS
Morris James LLP, as special Delaware counsel to the trust, will
give a legal opinion as to the validity of the trust units.
Vinson & Elkins L.L.P., Houston, Texas, will give
opinions as to certain other matters relating to the offering,
including the tax opinion described in the section of this
prospectus captioned Federal income tax
consequences. Certain legal matters in connection with the
trust units offered hereby will be passed upon for the
underwriters by Baker Botts L.L.P., Houston, Texas.
EXPERTS
Certain information appearing in this registration statement
regarding the December 31, 2010 estimated quantities of
reserves of the VOC Brazos and KEP and Net Profits Interest
owned by the trust, the future net revenues from those reserves
and their present value is based on estimates of the reserves
and present values prepared by or derived from estimates
prepared by Cawley, Gillespie & Associates, Inc.,
independent petroleum engineers.
The audited financial statements 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 accounting and auditing in giving said reports.
WHERE YOU
CAN FIND MORE INFORMATION
The trust and VOC Sponsor have filed with the SEC in
Washington, D.C. a registration statement, including all
amendments, under the Securities Act relating to the trust
units. As permitted by the rules and regulations of the SEC,
this prospectus does not contain all of the information
contained in the registration statement and the exhibits and
schedules to the registration statement. You may read and copy
the registration statement at the SECs public reference
room at 100 F Street, N.E., Washington, D.C.
20549. You may request copies of these documents, upon payment
of a duplicating fee, by writing to the SEC at the address in
the previous sentence. To obtain information on the operation of
the public reference rooms you may call the SEC at
(800) SEC-0330. You can also read the trust and VOC
Sponsors SEC filings, including the registration
statement, at the SECs website at www.sec.gov.
121
GLOSSARY
OF CERTAIN OIL AND NATURAL GAS TERMS
In this prospectus the following terms have the meanings
specified below.
Bbl One stock tank barrel, of 42
U.S. gallons liquid volume, used herein in reference to
crude oil and other liquid hydrocarbons.
Boe One stock tank barrel of oil equivalent,
computed on an approximate energy equivalent basis that one Bbl
of crude oil equals six Mcf of natural gas.
Boe/d One Boe per day.
Btu A British Thermal Unit, a common unit of
energy measurement.
Completion The installation of permanent
equipment for the production of oil or natural gas, or in the
case of a dry hole, the reporting of abandonment to the
appropriate agency.
Developed Acreage The number of acres that
are allocated or assignable to productive wells or wells capable
of production.
Development Well A well drilled into a proved
oil or natural gas reservoir to the depth of a stratigraphic
horizon known to be productive.
Differential The difference between a
benchmark price of oil and natural gas, such as the NYMEX crude
oil spot, and the wellhead price received.
Estimated future net revenues Also referred
to as estimated future net cash flows. The result of
applying current prices of oil and natural gas to estimated
future production from oil and natural gas proved reserves,
reduced by estimated future expenditures, based on current costs
to be incurred, in developing and producing the proved reserves,
excluding overhead.
Farm-in or farm-out agreement An agreement
under which the owner of a working interest in an oil or natural
gas lease is typically assigns the working interest or a portion
of the working interest to another party who desires to drill on
the leased acreage. Generally, the assignee is required to drill
one or more wells in order to earn its interest in the acreage.
The assignor usually retains a royalty or reversionary interest
in the lease. The interest received by an assignee is a
farm-in while the interest transferred by the
assignor is a farm-out.
Field An area consisting of either a single
reservoir or multiple reservoirs, all grouped on or related to
the same individual geological structural feature
and/or
stratigraphic condition.
Gross acres or gross wells The total
acres or wells, as the case may be, in which a working interest
is owned.
Horizontal well A well that starts off being
drilled vertically but which is eventually curved to become
horizontal (or near horizontal) in order to parallel a
particular geologic formation.
Kansas Underlying Properties The portion of
the Underlying Properties located in Kansas.
MBbl One thousand barrels of crude oil or
condensate.
MBoe One thousand barrels of oil equivalent.
122
Mcf One thousand cubic feet of natural gas.
MMBbls One million barrels of crude oil or
other liquid hydrocarbons.
MMBoe One million barrels of oil equivalent.
MMcf One million cubic feet of natural gas.
Net acres or net wells The sum of the
fractional working interests owned in gross acres or wells, as
the case may be.
Net profits interest A nonoperating interest
that creates a share in gross production from an operating or
working interest in oil and natural gas properties. The share is
measured by net profits from the sale of production after
deducting costs associated with that production.
Net revenue interest An interest in all oil
and natural gas produced and saved from, or attributable to, a
particular property, net of all royalties, overriding royalties,
Net Profits Interests, carried interests, reversionary interests
and any other burdens to which the persons interest is
subject.
Plugging and abandonment Activities to remove
production equipment and seal off a well at the end of a
wells economic life.
Production and development costs All lease
operating expenses, production and property taxes and
development expenses (including the cost of workovers and
recompletions, drilling costs and development costs, but subject
to certain limitations near the end of the term of the trust, as
described in Computation of net proceeds Net
profits interest).
Proved developed non-producing reserves
Proved developed reserves expected to be recovered from zones
behind casing in existing wells.
Proved developed producing reserves Proved
developed reserves that are expected to be recovered from
completion intervals currently open in existing wells and
capable of production to market.
Proved developed reserves Reserves that can
be expected to be recovered through existing wells with existing
equipment and operating methods.
Proved reserves Under SEC rules for fiscal
years ending on or after December 31, 2009, proved reserves
are defined as:
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
123
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
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.
Under SEC rules for fiscal years ending prior to
December 31, 2009, proved reserves are defined as:
The estimated quantities of crude oil and natural gas, which
geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions,
i.e., prices and costs as of the date the estimate is made.
Prices include consideration of changes in existing prices
provided only by contractual arrangements, but not on
escalations based upon future conditions. Reservoirs are
considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area
of a reservoir considered proved includes (A) that portion
delineated by drilling and defined by gas-oil
and/or
oil-water contacts, if any, and (B) the immediately
adjoining portions not yet drilled, but which can be reasonably
judged as economically productive on the basis of available
geological and engineering data. In the absence of information
on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application
of improved recovery techniques (such as fluid injection) are
included in the proved classification when successful testing by
a pilot project, or the operation of an installed program in the
reservoir, provides support for the engineering analysis on
which the project or program was based. Estimates of proved
reserves do not include the following: (A) Oil that may
become available from known reservoirs but is classified
separately as indicated additional reserves; (B) crude oil
and natural gas, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors; (C) crude oil and
natural gas, that may occur in undrilled prospects; and
(D) crude oil and natural gas, that may be recovered from
oil shales, coal, gilsonite and other such sources.
Proved undeveloped reserves Proved 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.
PV-10
The present value of estimated future net revenues using a
discount rate of 10% per annum.
124
Recompletion The completion for production of
an existing well bore in another formation from which that well
has been previously completed.
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 reservoirs.
Texas Underlying Properties The portion of
the Underlying Properties located in Texas.
Working interest The right granted to the
lessee of a property to explore for and to produce and own oil,
gas, or other minerals. The working interest owners bear the
exploration, development, and operating costs on either a cash,
penalty, or carried basis.
Workover Operations on a producing well to
restore or increase production.
125
INDEX TO
FINANCIAL STATEMENTS
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PREDECESSOR UNDERLYING PROPERTIES:
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F-2
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F-3
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F-4
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ACQUIRED UNDERLYING PROPERTIES:
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F-10
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F-11
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F-12
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UNAUDITED PRO FORMA UNDERLYING PROPERTIES:
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F-17
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F-18
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VOC ENERGY TRUST:
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F-19
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F-20
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F-21
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Unaudited Pro Forma Financial Information:
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F-24
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F-25
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F-26
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F-27
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The audited combined financial statements of Predecessor can be
found beginning on
page VOC F-1.
F-1
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of VOC Brazos Energy Partners, L.P.:
We have audited the accompanying combined statements of
historical revenues and direct operating expenses of the
Predecessor Underlying Properties, consisting of the Underlying
Properties of VOC Brazos Energy Partners, L.P. (VOC
Brazos) and the Underlying Properties of VOC Kansas Energy
Partners, L.L.C. under common control with VOC Brazos, for each
of the three years in the period ended December 31, 2010.
These statements are the responsibility of the management of VOC
Brazos. Our responsibility is to express an opinion on these
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. Predecessor Underlying Properties
is not required to have, nor were we engaged to perform, an
audit of Predecessor Underlying Properties 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 Predecessor Underlying Properties
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 presentation of the statements. We
believe that our audits provide a reasonable basis for our
opinion.
The accompanying combined statements were prepared for the
purpose of complying with the rules and regulations of the
Securities and Exchange Commission as described in Note B
to the statements and are not intended to be a complete
presentation of VOC Brazos interests in the Predecessor
Underlying Properties.
In our opinion, the combined statements referred to above
present fairly, in all material respects, the historical
revenues and direct operating expenses, described in
Note B, of the Predecessor Underlying Properties for each
of the three years in the period ended December 31, 2010,
in conformity with accounting principles generally accepted in
the United States of America.
Grant Thornton LLP
Wichita, Kansas
March 22, 2011
F-2
Predecessor
Underlying Properties
AND
DIRECT OPERATING EXPENSES
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Year Ended December 31,
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2008
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2009
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2010
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Revenues:
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Oil sales
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$
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36,632,381
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$
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22,757,639
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$
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36,914,333
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Natural gas sales
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3,349,695
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1,510,884
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2,396,637
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Hedge and other derivative income (expense)
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(7,784,517
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)
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1,477,248
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(707,371
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)
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Total
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32,197,559
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25,745,771
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38,603,599
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Bad debt expense (recovery)
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1,726,655
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(719,061
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)
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Direct operating expenses:
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Lease operating expenses
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7,667,332
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6,787,857
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7,325,042
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Production and property taxes
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2,531,660
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1,646,052
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2,720,313
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|
|
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|
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|
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Total
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10,198,992
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|
|
8,433,909
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|
10,045,355
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Excess of revenues over direct operating expenses
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|
$
|
20,271,912
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|
$
|
18,030,923
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|
|
$
|
28,558,244
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|
|
|
|
|
|
|
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|
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The accompanying notes are an
integral part of these combined statements.
F-3
Predecessor
Underlying Properties
AND
DIRECT OPERATING EXPENSES
For the years ended December 31, 2008, 2009 and 2010
NOTE A
PROPERTIES
The Predecessor Underlying Properties consist of working
interests in substantially all of the oil and natural gas
properties located in Kansas and Texas owned by VOC Brazos
Energy Partners, L.P. (VOC Brazos) and working
interests in substantially all of the oil and natural gas
properties owned by VOC Kansas Energy Partners, LLC
(KEP) under common control with VOC Brazos Energy
Partners, L.P. (the Common Control Properties). In
connection with the closing of the initial public offering of
trust units of VOC Energy Trust, pursuant to that certain
Contribution and Exchange Agreement dated August 30, 2010, VOC
Brazos will acquire all of the membership interests in KEP in
exchange for newly issued limited partner interests in VOC
Brazos, resulting in KEP becoming a wholly-owned subsidiary of
VOC Brazos. As the Common Control Properties are deemed to be
under common control with VOC Brazos, accounting rules specify
VOC Brazos and the Common Control Properties be combined from
the earliest date they came under common control. The financial
data and operations of such assets are referred to herein as
Predecessor.
NOTE B
BASIS OF PRESENTATION
The accompanying Combined Statements of Historical Revenues and
Direct Operating Expenses were derived from the historical
accounting records of Predecessor and reflect the historical
revenues and direct operating expenses directly attributable to
the Predecessor Underlying Properties for the periods described
herein. Such amounts may not be representative of future
operations. The statements do not include depreciation,
depletion and amortization, general and administrative expenses,
interest expense or other expenses of an indirect nature. The
amounts represent Predecessors net interest in the wells
related to the Predecessor Underlying Properties.
Historical financial statements representing financial position,
results of operations and cash flows required by generally
accepted accounting principles are not presented as such
information is not readily available on an individual property
basis and not meaningful to the underlying properties.
Accordingly, the statements of historical revenues and direct
operating expenses are presented in lieu of full financial
statements prepared under
Regulation S-X.
The accompanying Combined Statements of Historical Revenues and
Direct Operating Expenses included herein were prepared on an
accrual basis. Revenue from oil and natural gas is recognized
when sold. Direct operating expenses include lease operating
expenses and production and property taxes.
These combined statements of historical revenues and direct
operating expenses do not reflect the impact of any
administrative overhead costs. VOC Brazos incurred
administrative overhead costs of $269,139, $463,295 and $204,575
for the years ended December 31, 2008, 2009 and 2010,
respectively. KEP is an amalgamation of properties held by
24 owners. Prior to their consolidation in November 2009,
each owner conducted its own accounting for its respective
properties, and in most cases the owners did not allocate
overhead to the properties. One of the reasons the owners
decided to consolidate holdings into KEP was the efficiency in
sharing these overhead expenses. In the future, Vess Oil
Corporation will provide these overhead services to KEP.
Furthermore, trust administrative expenses are anticipated to
aggregate approximately $900,000 for 2011. Administrative
expenses for subsequent years could be greater or less
F-4
Predecessor
Underlying Properties
NOTES TO
COMBINED STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2008, 2009 and 2010
depending on future events that cannot be predicted. Included in
the $900,000 annual estimate is an annual administrative fee of
$150,000 for the trustee and an annual administrative fee of
$2,500 for the Delaware trustee as well as an annual
administrative fee payable to VOC Sponsor, which fee will total
$75,000 in 2011 and will increase by 4% each year beginning in
January 2012. See The trust. The trust will pay, out
of the first cash payment received by the trust, the
trustees and Delaware trustees legal expenses
incurred in forming the trust as well as the Delaware
trustees acceptance fee in the amount of $4,000. These
costs will be deducted by the trust before distributions are
made to trust unitholders beginning in January 2012.
Furthermore, the trust will incur incremental general and
administrative expenses associated with being a publicly traded
entity. As a result, historical overhead costs are not
indicative of the future overhead costs that will be borne by
VOC Energy Trust, which are expected to be approximately
$900,000 in 2011.
VOC Brazos has entered into certain swap agreements to mitigate
the effects of fluctuations in the prices of crude oil. These
agreements involve the exchange of amounts based on a
fluctuating oil price for amounts based on a fixed oil price
over the life of the agreement, without an exchange of the
notional amount upon which the payments are based. VOC Brazos
accounts for substantially all of the swap agreements as cash
flow hedges. The effective portion of the unrealized gain or
loss on the swap agreement is recorded as a component of the
accumulated other comprehensive income (loss) and reclassified
into earnings as the underlying hedged item affects earnings.
The unrealized gain or loss on the derivative instrument as well
as the swap agreements not qualifying as cash flow hedges are
reflected as hedge and other derivative activity in the
accompanying Combined Statements of Historical Revenues and
Direct Operating Expenses.
The process of preparing financial statements in conformity with
generally accepted accounting principles requires the use of
estimates and assumptions regarding certain types of revenues
and expenses. Such estimates primarily relate to unsettled
transactions and events as of the date of the financial
statements. Accordingly, upon settlement, actual results may
differ from estimated amounts.
NOTE C
DISCLOSURES ABOUT OIL AND GAS ACTIVITIES
(UNAUDITED)
In December 2009, Predecessor adopted revised oil and gas
reserve estimation and disclosure requirements. The primary
impact of the new disclosures is to conform the definition of
proved reserves to the SEC Modernization of Oil and Gas
Reporting rules, which were issued by the SEC at the end of
2008. The new rules revised the definition of proved oil and gas
reserves to require that the average,
first-day-of-the-month
price during the
12-month
period before the end of the year, rather than the year-end
price, be used when estimating whether reserve quantities are
economical to produce. This same
12-month
average price is also used in calculating the aggregate amount
of (and changes in) future cash inflows related to the
standardized measure of discounted future net cash flows. The
rules also allow for the use of reliable technology to estimate
proved oil and gas reserves if those technologies have been
demonstrated to result in reliable conclusions about reserve
volumes. The unaudited supplemental information on oil and gas
exploration and production activities for 2009 and 2010 has been
presented in accordance with the new reserve estimation and
disclosure rules, which may not be applied retrospectively.
F-5
Predecessor
Underlying Properties
NOTES TO
COMBINED STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2008, 2009 and 2010
The 2007 and 2008 data are presented in accordance with SEC oil
and gas disclosure requirements effective during those periods.
Estimates of the proved oil and gas reserves attributable to the
Predecessor Underlying Properties as of December 31, 2007,
2008, 2009 and 2010 are based on reports of Cawley,
Gillespie & Associates, Inc., independent petroleum
and geological engineers, and the contract property management
engineering staff of Predecessor who operate the underlying
properties, in accordance with SEC rules and regulations. Such
estimates give effect to the combination of (i) the estimates of
proved oil and gas reserves attributable to VOC Brazos,
based on the report of Cawley, Gillespie & Associates,
Inc., and (ii) the estimates of proved oil and gas reserves
attributable to the Common Control Properties, calculated by
adjusting the estimated reserves attributable to specified
working interest percentages held by KEP outlined in the Cawley,
Gillespie & Associates, Inc. reserve report to reflect
the working interest percentages held in the Common Control
Properties. Users of this information should be aware that the
process of estimating quantities of proved and
proved developed and proved undeveloped
crude oil and natural gas reserves is very complex, requiring
significant subjective decisions in the evaluation of all
available geological, engineering and economic data for each
reservoir. The data for a given reservoir may also change
substantially over time as a result of numerous factors,
including additional development activity, evolving production
history and continual reassessment of the viability of
production under varying economic conditions. Consequently,
material revisions to existing reserve estimates occur from time
to time.
The reserve data below represent estimates only and should not
be construed as being exact. Moreover, the discounted values
should not be construed as representative of the current market
value of the oil and gas properties. A market value
determination would include many additional factors including:
(i) anticipated future oil and gas prices; (ii) the
effect of federal income taxes, if any, on Predecessor
Underlying Properties; (iii) an allowance for return on
investment; (iv) the effect of governmental legislation;
(v) the value of additional potential reserves, not
considered proved at present, which may be recovered as a result
of further exploration and development activities; and
(vi) other business risks.
The following tables set forth (i) the estimated net
quantities of proved, proved developed and proved undeveloped
oil and natural gas reserves attributable to the oil and natural
gas properties, and (ii) the standardized measure of the
discounted future net profits interest income attributable to
the oil and gas properties and the nature of changes in such
standardized measure between years. These tables are prepared on
the accrual basis, which is the basis on which Predecessor
maintains its production records. The data presents the proved
reserves attributable to the Predecessor Underlying Properties
for the economic life of such properties and is not limited to
the term of the trust.
F-6
Predecessor
Underlying Properties
NOTES TO
COMBINED STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2008, 2009 and 2010
ESTIMATED
QUANTITIES OF OIL AND GAS RESERVES
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
(Bbls)
|
|
|
(Mcf)
|
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
7,454,506
|
|
|
|
4,374,316
|
|
Revisions of previous estimates
|
|
|
(790,795
|
)
|
|
|
(101,844
|
)
|
Purchase of minerals in place
|
|
|
221,536
|
|
|
|
377,887
|
|
Extensions and discoveries
|
|
|
170
|
|
|
|
|
|
Production
|
|
|
(389,268
|
)
|
|
|
(426,326
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
6,496,149
|
|
|
|
4,224,033
|
|
Revisions of previous estimates
|
|
|
1,790,387
|
|
|
|
634,099
|
|
Purchase of minerals in place
|
|
|
63,928
|
|
|
|
59,689
|
|
Extensions and discoveries
|
|
|
149,533
|
|
|
|
|
|
Production
|
|
|
(407,415
|
)
|
|
|
(414,730
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
8,092,582
|
|
|
|
4,503,091
|
|
Revisions of previous estimates
|
|
|
659,977
|
|
|
|
1,041,826
|
|
Production
|
|
|
(494,876
|
)
|
|
|
(446,979
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010
|
|
|
8,257,683
|
|
|
|
5,097,938
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
6,877,406
|
|
|
|
4,116,158
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
5,770,190
|
|
|
|
3,928,995
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
6,729,632
|
|
|
|
3,854,008
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
6,799,873
|
|
|
|
3,992,358
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
577,100
|
|
|
|
258,158
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
725,959
|
|
|
|
295,038
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
1,362,950
|
|
|
|
649,083
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
1,457,810
|
|
|
|
1,105,580
|
|
|
|
|
|
|
|
|
|
|
STANDARDIZED
MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
FROM PROVED OIL AND GAS RESERVES
Future oil and natural gas sales and production and development
costs have been estimated in accordance with the SEC
Modernization of Oil and Gas Reporting Rules for 2009 and 2010.
The standardized measure of discounted future net cash flows
(the Standardized Measure) represents the present
value of estimated future cash inflows from proved oil and
natural gas reserves, less future development, production and
plugging and abandonment costs, discounted at 10% per annum, or
PV-10 value, to reflect timing of future cash flows. Production
costs do not include depreciation, depletion and amortization of
capitalized acquisition, exploration and development costs.
Because Predecessor bears no federal income tax expense and
taxable income is passed through to the partners of Predecessor,
no provision for federal or state income taxes is included in
the reserve report or in the calculation of the Standardized
Measure.
Estimated proved reserves and related future net revenues and
Standardized Measure were determined using index prices for oil
and natural gas, without giving effect to derivative
F-7
Predecessor
Underlying Properties
NOTES TO
COMBINED STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2008, 2009 and 2010
transactions, and were held constant throughout the life of the
properties. The index prices were $44.60 per barrel for oil and
$5.62 per MMBtu for natural gas at December 31, 2008, and
the unweighted arithmetic average first-day of-the-month prices
for the prior 12 months were $61.18 per barrel for oil and
$3.83 per MMBtu for natural gas at December 31, 2009 and
$79.43 per barrel for oil and $4.37 per MMBtu for
natural gas at December 31, 2010. For purposes of comparing
natural gas prices per MMBtu and per Mcf, adjustments have been
made to reflect Btu content, shrink and compression and handling
charges as realized on an individual lease basis. The relevant
average realized prices, adjusting in the case of crude oil for
forecasted gravity, quality, transportation and marketing as
well as other factors affecting the price received at the
wellhead, were $39.49 per barrel for oil and $5.61 per Mcf for
natural gas at December 31, 2008, $55.82 per barrel for oil
and $4.58 per Mcf for natural gas at December 31, 2009 and
$74.22 per barrel for oil and $5.02 per Mcf for natural gas at
December 31, 2010. The impact of the adoption of the
authoritative guidance of the Financial Accounting Standard
Board (the FASB) on the SEC oil and gas reserve
estimation final rule on our financial statements is not
practicable to estimate due to the operation and technical
challenges associated with calculating a cumulative effect of
adoption by preparing reserve reports under both the old and new
rules.
Changes in the demand for oil and natural gas, inflation, and
other factors made such estimates inherently imprecise and
subject to substantial revision. This table should not be
construed to be an estimate of current market value of the
proved reserves attributable to Predecessors reserves.
The Standardized Measure relating to Predecessors proved
reserves at December 31, 2008, 2009 and 2010 is shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Future cash inflows
|
|
$
|
285,599,020
|
|
|
$
|
479,804,227
|
|
|
$
|
648,185,108
|
|
Future costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(152,898,120
|
)
|
|
|
(192,121,342
|
)
|
|
|
(223,916,334
|
)
|
Development
|
|
|
(12,501,184
|
)
|
|
|
(25,183,887
|
)
|
|
|
(25,384,253
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
120,199,716
|
|
|
|
262,498,998
|
|
|
|
398,884,521
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less 10% discount factor
|
|
|
(60,259,262
|
)
|
|
|
(142,117,093
|
)
|
|
|
(218,408,117
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
59,940,454
|
|
|
$
|
120,381,905
|
|
|
$
|
180,476,404
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-8
Predecessor
Underlying Properties
NOTES TO
COMBINED STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2008, 2009 and 2010
The following table sets forth the changes in the Standardized
Measure applicable to Predecessors proved oil and natural
gas reserves for the years ended December 31, 2008, 2009
and 2010:
CHANGES
IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED OIL AND GAS RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
Standardized measure at beginning of year
|
|
$
|
206,509,831
|
|
|
$
|
59,940,454
|
|
|
$
|
120,381,905
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(29,744,163
|
)
|
|
|
(15,788,110
|
)
|
|
|
(29,265,616
|
)
|
Net changes in price and production costs
|
|
|
(154,951,804
|
)
|
|
|
41,451,566
|
|
|
|
52,703,598
|
|
Extensions, discoveries and improved recovery, net of future
production and development costs
|
|
|
5,822
|
|
|
|
5,890,961
|
|
|
|
|
|
Changes in estimated future development costs
|
|
|
(2,726,749
|
)
|
|
|
(14,381,027
|
)
|
|
|
(14,568,030
|
)
|
Development costs incurred during the period which reduce future
development costs
|
|
|
52,800
|
|
|
|
2,700,100
|
|
|
|
7,599,939
|
|
Revisions of quantity estimates
|
|
|
(7,982,910
|
)
|
|
|
29,413,203
|
|
|
|
15,664,245
|
|
Accretion of discount
|
|
|
20,650,983
|
|
|
|
5,994,045
|
|
|
|
12,038,190
|
|
Purchase of reserves in place
|
|
|
4,831,610
|
|
|
|
1,567,625
|
|
|
|
|
|
Change in production rates, timing and other
|
|
|
23,295,034
|
|
|
|
3,593,088
|
|
|
|
15,922,173
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure at end of year
|
|
$
|
59,940,454
|
|
|
$
|
120,381,905
|
|
|
$
|
180,476,404
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-9
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Members of VOC Kansas Energy Partners, LLC:
We have audited the accompanying statements of historical
revenues and direct operating expenses of the Acquired
Underlying Properties, consisting of the Underlying Properties
of VOC Kansas Energy Partners, LLC (KEP) not under
common control with VOC Brazos Energy Partners, L.P., for each
of the three years in the period ended December 31, 2010.
These statements are the responsibility of management of KEP.
Our responsibility is to express an opinion on these 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. Acquired Underlying Properties is
not required to have, nor were we engaged to perform, an audit
of Acquired Underlying Properties 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 Acquired Underlying Properties
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 presentation of the statements. We
believe that our audits provide a reasonable basis for our
opinions.
The accompanying statements were prepared for the purpose of
complying with the rules and regulations of the Securities and
Exchange Commission as described in Note B to the
statements and are not intended to be a complete presentation of
KEPs interests in the Acquired Underlying Properties.
In our opinion, the statements referred to above present fairly,
in all material respects, the historical revenues and direct
operating expenses, described in Note B, of the Acquired
Underlying Properties for each of the three years in the period
ended December 31, 2010, in conformity with accounting
principles generally accepted in the United States of America.
Grant Thornton LLP
Wichita, Kansas
March 22, 2011
F-10
Acquired
Underlying Properties
AND
DIRECT OPERATING EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
29,297,334
|
|
|
$
|
17,602,148
|
|
|
$
|
23,272,803
|
|
Natural gas sales
|
|
|
2,248,210
|
|
|
|
780,880
|
|
|
|
842,035
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
31,545,544
|
|
|
|
18,383,028
|
|
|
|
24,114,838
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bad debt expense
|
|
|
2,165,663
|
|
|
|
|
|
|
|
|
|
Direct operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
6,046,131
|
|
|
|
5,969,209
|
|
|
|
6,401,987
|
|
Production and property taxes
|
|
|
1,613,900
|
|
|
|
1,169,798
|
|
|
|
1,416,534
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
7,660,031
|
|
|
|
7,139,007
|
|
|
|
7,818,521
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
$
|
21,719,850
|
|
|
$
|
11,244,021
|
|
|
$
|
16,296,317
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these statements.
F-11
Acquired
Underlying Properties
AND
DIRECT OPERATING EXPENSES
For the years ended December 31, 2008, 2009 and 2010
NOTE A
PROPERTIES
The Acquired Underlying Properties consist of working interests
in substantially all oil and natural gas properties located in
Kansas owned by VOC Kansas Energy Partners, LLC
(KEP) which are not under common control with VOC
Brazos Energy Partners, L.P. (VOC Brazos). In
connection with the closing of the initial public offering of
trust units of VOC Energy Trust, pursuant to that certain
Contribution and Exchange Agreement dated August 30, 2010,
VOC Brazos will acquire all of the membership interests in KEP
in exchange for newly-issued limited partner interests in VOC
Brazos.
NOTE B
BASIS OF PRESENTATION
The accompanying Statements of Historical Revenues and Direct
Operating Expenses were derived from the historical accounting
records of KEP and reflect the historical revenues and direct
operating expenses directly attributable to the Acquired
Underlying Properties for the periods described herein. Such
amounts may not be representative of future operations. The
statements do not include depreciation, depletion and
amortization, general and administrative expenses, interest
expense or other expenses of an indirect nature. The amounts
represent KEPs net interest in the wells relating to the
Acquired Underlying Properties.
Historical financial statements representing financial position,
results of operations and cash flows required by generally
accepted accounting principles are not presented as such
information is not readily available on an individual property
basis and not meaningful to the underlying properties.
Accordingly, the statements of historical revenues and direct
operating expenses are presented in lieu of financial statements
prepared under
Rule 3-05
of
Regulation S-X.
The accompanying Statements of Historical Revenues and Direct
Operating Expenses included herein were prepared on an accrual
basis. Revenue from oil and natural gas sales is recognized when
sold. Direct operating expenses include lease operating expenses
and production and property taxes.
These Statements of Historical Revenues and Direct Operating
Expenses do not reflect the impact of any administrative
overhead costs. KEP is an amalgamation of properties held by
24 owners. Prior to their consolidation in November 2009,
each owner conducted its own accounting for its respective
properties, and in most cases the owners did not allocate
overhead to the properties. One of the reasons the owners
decided to consolidate holdings into KEP was the efficiency in
sharing these overhead expenses. In the future, Vess Oil
Corporation will provide these overhead services to KEP.
Furthermore, trust administrative expenses are anticipated to
aggregate approximately $900,000 for 2011. Administrative
expenses for subsequent years could be greater or less depending
on future events that cannot be predicted. Included in the
$900,000 annual estimate is an annual administrative fee of
$150,000 for the trustee and an annual administrative fee of
$2,500 for the Delaware trustee as well as an annual
administrative fee payable to VOC Sponsor, which fee will total
$75,000 in 2011 and will increase by 4% each year beginning in
January 2012. See The trust. The trust will pay, out
of the first cash payment received by the trust, the
trustees and Delaware trustees legal expenses
incurred in forming the trust as well as the Delaware
trustees acceptance fee in the amount of $4,000. These
costs will be deducted by the trust before distributions are
made to trust
F-12
Acquired
Underlying Properties
NOTES TO
STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2008, 2009 and 2010
unitholders beginning in January 2012. Furthermore, the
trust will incur incremental general and administrative expenses
associated with being a publicly traded entity. As a result,
historical overhead costs are not indicative of the future
overhead costs that will be borne by VOC Energy Trust, which are
expected to be approximately $900,000 in 2011.
The process of preparing financial statements in conformity with
generally accepted accounting principles requires the use of
estimates and assumptions regarding certain types of revenues
and expenses. Such estimates primarily relate to unsettled
transactions and events as of the date of the financial
statements. Accordingly, upon settlement, actual results may
differ from estimated amounts.
NOTE C
DISCLOSURES ABOUT OIL AND GAS ACTIVITIES
(UNAUDITED)
In December 2009, KEP adopted revised oil and gas reserve
estimation and disclosure requirements. The primary impact of
the new disclosures is to conform the definition of proved
reserves to the SEC Modernization of Oil and Gas Reporting
rules, which were issued by the SEC at the end of 2008. The new
rules revised the definition of proved oil and gas reserves to
require that the average,
first-day-of-the-month
price during the
12-month
period before the end of the year, rather than the year-end
price, be used when estimating whether reserve quantities are
economical to produce. This same
12-month
average price is also used in calculating the aggregate amount
of (and changes in) future cash inflows related to the
standardized measure of discounted future net cash flows. The
rules also allow for the use of reliable technology to estimate
proved oil and gas reserves if those technologies have been
demonstrated to result in reliable conclusions about reserve
volumes. The unaudited supplemental information on oil and gas
exploration and production activities for 2009 and 2010 has been
presented in accordance with the new reserve estimation and
disclosure rules, which may not be applied retrospectively. The
2007 and 2008 data are presented in accordance with SEC oil and
gas disclosure requirements effective during those periods.
Estimates of the proved oil and gas reserves attributable to the
Acquired Underlying Properties as of December 31, 2007,
2008, 2009 and 2010 are based on the report of Cawley,
Gillespie & Associates, Inc., independent petroleum
and geological engineers, and the contract property management
engineering staff of KEP who operate the underlying properties,
in accordance with SEC rules and regulations. Such estimates are
calculated by adjusting the estimated reserves attributable to
specified working interest percentages held by KEP outlined in
the Cawley, Gillespie & Associates, Inc. reserve
report to reflect the working interest percentages held in the
Acquired Underlying Properties. Users of this information should
be aware that the process of estimating quantities of
proved and proved developed and
proved undeveloped crude oil and natural gas
reserves is very complex, requiring significant subjective
decisions in the evaluation of all available geological,
engineering and economic data for each reservoir. The data for a
given reservoir may also change substantially over time as a
result of numerous factors, including additional development
activity, evolving production history and continual reassessment
of the viability of production under varying economic
conditions. Consequently, material revisions to existing reserve
estimates occur from time to time.
The reserve data below represent estimates only and should not
be construed as being exact. Moreover, the discounted values
should not be construed as representative of the current market
F-13
Acquired
Underlying Properties
NOTES TO
STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2008, 2009 and 2010
value of the oil and gas properties. A market value
determination would include many additional factors including:
(i) anticipated future oil and natural gas prices;
(ii) the effect of federal income taxes, if any, on the
Acquired Underlying Properties; (iii) an allowance for
return on investment; (iv) the effect of governmental
legislation; (v) the value of additional potential
reserves, not considered proved at present, which may be
recovered as a result of further exploration and development
activities; and (vi) other business risks.
The following tables set forth (i) the estimated net
quantities of proved, proved developed and proved undeveloped
oil, and natural gas reserves attributable to the oil and gas
properties, and (ii) the standardized measure of the
discounted future net profits interest income attributable to
the oil and gas properties and the nature of changes in such
standardized measure between years. These tables are prepared on
the accrual basis, which is the basis on which KEP maintains its
production records. The data presents the proved reserves
attributable to the Acquired Underlying Properties for the
economic life of such properties and is not limited to the term
of the trust.
ESTIMATED
QUANTITIES OF OIL AND GAS RESERVES
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
(Bbls)
|
|
|
(Mcf)
|
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
4,538,607
|
|
|
|
3,005,629
|
|
Revisions of previous estimates
|
|
|
(1,042,884
|
)
|
|
|
(48,799
|
)
|
Extensions and discoveries
|
|
|
1,063
|
|
|
|
|
|
Production
|
|
|
(314,620
|
)
|
|
|
(323,964
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
3,182,166
|
|
|
|
2,632,866
|
|
Revisions of previous estimates
|
|
|
849,297
|
|
|
|
(461,342
|
)
|
Purchase of minerals in places
|
|
|
64,733
|
|
|
|
65,972
|
|
Extensions and discoveries
|
|
|
65,804
|
|
|
|
|
|
Production
|
|
|
(324,329
|
)
|
|
|
(278,022
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
3,837,671
|
|
|
|
1,959,474
|
|
Revisions of previous estimates
|
|
|
767,948
|
|
|
|
124,153
|
|
Production
|
|
|
(321,661
|
)
|
|
|
(232,254
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010
|
|
|
4,283,958
|
|
|
|
1,851,373
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
4,538,607
|
|
|
|
3,005,629
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
3,182,166
|
|
|
|
2,632,866
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
3,837,671
|
|
|
|
1,959,474
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
4,171,465
|
|
|
|
1,851,373
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
112,493
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-14
Acquired
Underlying Properties
NOTES TO
STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2008, 2009 and 2010
STANDARDIZED
MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
FROM PROVED OIL AND GAS RESERVES
Future oil and natural gas sales and production and development
costs for 2009 and 2010 have been estimated in accordance with
the SEC Modernization of Oil and Gas Reporting Rules.
The standardized measure of discounted future net cash flows
(the Standardized Measure) represents the present
value of estimated future cash inflows from proved oil and
natural gas reserves, less future development, production and
plugging and abandonment costs, discounted at 10% per
annum, or
PV-10 value,
to reflect timing of future cash flows. Production costs do not
include depreciation, depletion and amortization of capitalized
acquisition, exploration and development costs. Because KEP
bears no federal income tax expense and taxable income is passed
through to the members of KEP, no provision for federal or state
income taxes is included in the reserve report or in the
calculation of the Standardized Measure.
Estimated proved reserves and related future net revenues and
Standardized Measure were determined using index prices for oil
and natural gas, without giving effect to derivative
transactions, and were held constant throughout the life of the
properties. The index prices were $44.60 per barrel for oil and
$5.62 per MMBtu for natural gas at December 31, 2008, and
the unweighted arithmetic average first-day of-the-month prices
for the prior 12 months were $61.18 per barrel for oil and
$3.83 per MMBtu for natural gas at December 31, 2009 and
$79.43 per barrel for oil and $4.37 per MMBtu for
natural gas at December 31, 2010. The relevant average
realized prices, adjusting in the case of crude oil for
forecasted gravity, quality, transportation and marketing as
well as other factors affecting the price received at the
wellhead, were $39.49 per barrel for oil and $5.61 per Mcf for
natural gas at December 31, 2008, $55.82 per barrel for oil
and $4.58 per Mcf for natural gas at December 31, 2009, and
$74.22 per barrel for oil and $5.02 per Mcf for natural gas at
December 31, 2010. The impact of the adoption of the
authoritative guidance of the Financial Accounting Standard
Board (the FASB) on the SEC oil and gas reserve
estimation final rule on our financial statements is not
practicable to estimate due to the operation and technical
challenges associated with calculating a cumulative effect of
adoption by preparing reserve reports under both the old and new
rules.
Changes in the demand for oil and natural gas, inflation, and
other factors make such estimates inherently imprecise and
subject to substantial revision. This table should not be
construed to be an estimate of current market value of the
proved reserves attributable to the reserves of the Acquired
Underlying Properties.
F-15
Acquired
Underlying Properties
NOTES TO
STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2008, 2009 and 2010
The Standardized Measure relating to the proved reserves of the
Acquired Underlying Properties at December 31, 2008, 2009
and 2010 is shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Future cash inflows
|
|
$
|
130,045,214
|
|
|
$
|
212,587,116
|
|
|
$
|
319,037,861
|
|
Future costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(68,863,533
|
)
|
|
|
(103,484,949
|
)
|
|
|
(146,343,958
|
)
|
Development
|
|
|
|
|
|
|
(133,055
|
)
|
|
|
(1,749,143
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
61,181,681
|
|
|
|
108,969,112
|
|
|
|
170,944,760
|
|
Less 10% discount factor
|
|
|
(26,506,431
|
)
|
|
|
(50,661,158
|
)
|
|
|
(83,138,265
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
34,675,250
|
|
|
$
|
58,307,954
|
|
|
$
|
87,806,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth the changes in the Standardized
Measure applicable to the proved oil and natural gas reserves of
the Acquired Underlying Properties for the years ended
December 31, 2008, 2009 and 2010:
CHANGES
IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED OIL AND GAS RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
Standardized measure at beginning of year
|
|
$
|
133,461,982
|
|
|
$
|
34,675,250
|
|
|
$
|
58,307,954
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(23,885,512
|
)
|
|
|
(11,244,020
|
)
|
|
|
(16,296,317
|
)
|
Net changes in price and production costs
|
|
|
(104,323,038
|
)
|
|
|
13,629,634
|
|
|
|
21,385,452
|
|
Extensions, discoveries and improved recovery, net of future
production and development costs
|
|
|
36,385
|
|
|
|
2,700,702
|
|
|
|
|
|
Changes in estimated future development costs
|
|
|
|
|
|
|
(123,046
|
)
|
|
|
(1,545,676
|
)
|
Development costs incurred during the period which reduce future
development costs
|
|
|
|
|
|
|
|
|
|
|
133,055
|
|
Revisions of quantity estimates
|
|
|
(10,894,366
|
)
|
|
|
13,536,403
|
|
|
|
16,130,251
|
|
Accretion of discount
|
|
|
13,346,198
|
|
|
|
3,467,525
|
|
|
|
5,830,796
|
|
Purchase of reserves in place
|
|
|
|
|
|
|
1,582,671
|
|
|
|
|
|
Change in production rates, timing and other
|
|
|
26,933,601
|
|
|
|
82,835
|
|
|
|
3,860,980
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure at end of year
|
|
$
|
34,675,250
|
|
|
$
|
58,307,954
|
|
|
$
|
87,806,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-16
UNAUDITED
PRO FORMA STATEMENTS OF HISTORICAL REVENUES AND
DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES
Introduction
The following unaudited pro forma statements of historical
revenues and direct operating expenses are of the Predecessor
Underlying Properties, as adjusted to give effect to the
acquisition of the Acquired Underlying Properties as if the
acquisition had occurred on January 1, 2010. As certain of
the Underlying Properties held by KEP (the Common Control
Properties) are deemed to be under common control with VOC
Brazos, accounting rules specify that VOC Brazos and the Common
Control Properties be combined from the earliest date they came
under common control. The financial data and operations of such
assets are referred to herein as the Predecessor
Underlying Properties and are described in more detail in
VOC Sponsor Managements discussion and
analysis of financial condition and results of operations.
The Underlying Properties of KEP not deemed to be under common
control with the assets of VOC Brazos are referred to herein as
the Acquired Underlying Properties.
The unaudited pro forma statements of historical revenues and
direct operating expenses are for informational purposes only.
They do not purport to present the results of the combined
historical revenues and direct operating expenses of the
Underlying Properties that would have actually occurred had the
acquisition of the Acquired Underlying Properties occurred on
January 1, 2010.
The unaudited pro forma statements of historical revenues and
direct operating expenses should be read in conjunction with
The Underlying Properties Discussion and
analysis of historical results of the Underlying
Properties, the audited combined statements of historical
revenues and direct operating expenses of Predecessor Underlying
Properties and the audited statements of historical revenues and
direct operating expenses of the Acquired Underlying Properties
included in this prospectus.
F-17
UNAUDITED
PRO FORMA STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES OF THE UNDERLYING
PROPERTIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2010
|
|
|
|
Historical
|
|
|
Adjustments
|
|
|
Pro Forma
|
|
|
|
|
|
|
(a)
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
36,914,333
|
|
|
$
|
23,272,803
|
|
|
$
|
60,187,136
|
|
Natural gas sales
|
|
|
2,396,637
|
|
|
|
842,035
|
|
|
|
3,238,672
|
|
Hedge activity
|
|
|
(707,371
|
)
|
|
|
|
|
|
|
(707,371
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
38,603,599
|
|
|
|
24,114,838
|
|
|
|
62,718,437
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
7,325,042
|
|
|
|
6,401,987
|
|
|
|
13,727,029
|
|
Production and property taxes
|
|
|
2,720,313
|
|
|
|
1,416,534
|
|
|
|
4,136,847
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
10,045,355
|
|
|
|
7,818,521
|
|
|
|
17,863,876
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
$
|
28,558,244
|
|
|
$
|
16,296,317
|
|
|
$
|
44,854,561
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Pro forma adjustment to give effect
to the acquisition of the Acquired Properties as if the
acquisition had occurred on January 1, 2010.
|
F-18
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Unitholders of VOC Energy Trust:
We have audited the accompanying statement of assets and trust
corpus of VOC Energy Trust (the Trust) as of
December 31, 2010. This financial statement is the
responsibility of the management of VOC Brazos Energy Partners,
L.P. 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 statement of assets and
trust corpus is free of material misstatement. The Trust 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 Trusts
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 statement of assets and trust corpus, assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall statement of
assets and trust corpus presentation. We believe that our audit
provides a reasonable basis for our opinion.
As described in Note B to the statement of assets and trust
corpus, this statement has been prepared on a modified cash
basis of accounting, which is a comprehensive basis of
accounting other than accounting principles generally accepted
in the United States of America.
In our opinion, the statement of assets and trust corpus
referred to above presents fairly, in all material respects, the
financial position of the Trust as of December 31, 2010, on
the basis of accounting described in Note B.
Grant Thornton LLP
Wichita, Kansas
March 22, 2011
F-19
VOC
ENERGY TRUST
|
|
|
|
|
|
|
December 31,
|
|
|
2010
|
|
ASSETS
|
|
|
|
|
Cash
|
|
$
|
1,000
|
|
|
|
|
|
|
TRUST CORPUS
|
|
|
|
|
Trust Corpus
|
|
$
|
1,000
|
|
|
|
|
|
|
The accompanying notes are an
integral part of this financial statement.
F-20
VOC
Energy Trust
NOTE A
ORGANIZATION OF THE TRUST
VOC Energy Trust (the Trust) is a statutory trust
formed on November 3, 2010 (capitalized on
December 17, 2010), under the Delaware Statutory
Trust Act pursuant to a Trust Agreement (the
Trust Agreement) among VOC Brazos Energy
Partners, L.P. (VOC Brazos), as trustor, The Bank of
New York Mellon Trust Company, N.A., as Trustee (the
Trustee), and Wilmington Trust Company, as
Delaware Trustee (the Delaware Trustee).
The Trust was created to acquire and hold a term net profits
interest (the Net Profits Interest) for the benefit
of the Trust unitholders. In connection with the closing of the
initial public offering of trust units of the Trust, VOC Brazos
will convey the Net Profits Interest to the Trust. The Net
Profits Interest is an interest during the term of the trust in
underlying properties consisting of working interests in
substantially all of its oil and natural gas properties in the
states of Kansas and Texas held by VOC Brazos and VOC Kansas
Energy Partners, L.L.C. as of the date of the conveyance of the
Net Profits Interest to the Trust (the Underlying
Properties).
The Net Profits Interest is passive in nature and the Trustee
will have no management control over and no responsibility
relating to the operation of the Underlying Properties. The Net
Profits Interest entitles the Trust to receive 80% of the net
proceeds attributable to the net profits interest during the
term of the Trust. The Net Profits Interest will terminate on
the later to occur of (1) December 31, 2030 or
(2) the time from and after January 1, 2011 when
10.6 million barrels of oil equivalent have been produced
from the Underlying Properties and sold, and the Trust will soon
thereafter wind up its affairs and terminate.
The Trustee can authorize the Trust to borrow money to pay trust
administrative or incidental expenses that exceed cash held by
the Trust. The Trustee may authorize the Trust to borrow from
the Trustee or the Delaware Trustee as a lender provided the
terms of the loan are similar to the terms it would grant to a
similarly situated commercial customer with whom it did not have
a fiduciary relationship. The Trustee may also deposit funds
awaiting distribution in an account with itself and make other
short term investments with the funds distributed to the Trust.
NOTE B
TRUST ACCOUNTING POLICIES
A summary of the significant accounting policies of the Trust
follows.
1. Basis
of accounting
The Trust uses the modified cash basis of accounting to report
Trust receipts of the Net Profits Interest and payments of
expenses incurred. The Net Profits Interest represents the right
to receive revenues (oil and natural gas sales), less direct
operating expenses (lease operating expenses and production and
property taxes) and development expenses of the Underlying
Properties plus any payments made or net of payments received in
connection with the settlement of certain hedge contracts, times
80%. Cash distributions of the Trust will be made based on the
amount of cash received by the Trust pursuant to terms of the
conveyance creating the Net Profits Interest.
F-21
VOC
Energy Trust
NOTES TO
STATEMENT OF ASSETS AND
TRUST CORPUS (Continued)
The financial statements of the Trust, as prepared on a modified
cash basis, reflect the Trusts assets, liabilities, Trust
corpus, earnings and distributions as follows:
(a) Income from Net Profits Interest is recorded when
distributions are received by the Trust;
(b) Distributions to Trust unitholders are recorded when
paid by the Trust;
(c) Trust general and administrative expenses (which
includes the Trustees fees as well as accounting,
engineering, legal and other professional fees) are recorded
when paid;
(d) Cash reserves for Trust expenses may be established by
the Trustee for certain expenditures that would not be recorded
as contingent liabilities under generally accepted accounting
principles generally accepted in the United States of America
(U.S. GAAP);
(e) Amortization of the investment in Net Profits Interest
calculated on a
unit-of-production
basis is charged directly to trust corpus and does not affect
cash earnings; and
(f) The Trust evaluates its investment in the Net Profits
Interest periodically to determine whether its aggregate value
has been impaired below its total capitalized cost based on the
Underlying Properties. The Trust will provide a write-down to
its investment in the Net Profits Interest if and when that
total capitalized costs, less accumulated depreciation,
depletion and amortization, exceed undiscounted future net
revenues attributable to the Trusts interests in the
proved oil and gas reserves of the Underlying Properties.
While these statements differ from financial statements prepared
in accordance with U.S. GAAP, the modified cash basis of
reporting revenues and distributions is considered most
meaningful because quarterly distributions to the Trust
unitholders are based on net cash receipts.
This comprehensive basis of accounting other than U.S. GAAP
corresponds to the accounting permitted for royalty trusts by
the U.S. Securities and Exchange Commission as specified by
Staff Accounting Bulletin Topic 12:E, Financial Statements
of Royalty Trusts.
2. Use
of estimates
The preparation of the financial statements requires the Trust
to make estimates and assumptions that affect the reported
amount of assets and liabilities and the reported amounts of
revenues and expenses during the reporting period. Actual
results could differ from those estimates.
Tax counsel to the Trust advised the Trust at the time of
formation that, under then current tax laws, the Net Profits
Interest should be treated as a debt instrument for federal
income tax purposes, and the Trust should be required to treat a
portion of each payment it receives with respect to the Net
Profits Interest as interest income in accordance with the
noncontingent bond method under the original issue
discount rules contained in the Internal Revenue Code of 1986,
as amended, and the corresponding regulations. The Trust will be
treated as a grantor trust for federal income tax purposes.
Trust unitholders will be considered to own and receive the
trusts assets and income and will be directly taxable
thereon as if no trust were in existence.
F-22
VOC
Energy Trust
NOTES TO
STATEMENT OF ASSETS AND
TRUST CORPUS (Continued)
|
|
NOTE D
|
DISTRIBUTIONS
TO UNITHOLDERS
|
The Trustee determines for each quarter the amount available for
distribution to the Trust unitholders. This distribution is
expected to be made on or before the 45th day of the month
following the end of each quarter to the Trust unitholders of
record on the 30th day of the month following the end of
each quarter (or the next succeeding business day). Such amounts
will be equal to the excess, if any, of the cash received by the
Trust relating to the preceding quarter, over the expenses of
the Trust paid for such quarter, subject to adjustments for
changes made by the Trustee during such quarter in any cash
reserves established for future expenses of the Trust.
|
|
NOTE E
|
SUBSEQUENT
EVENTS
|
Management has reviewed activity through March 22, 2011, which
is considered the date through which these financial statements
are available to be issued for events requiring recognition or
disclosure.
F-23
VOC
Energy Trust
UNAUDITED
PRO FORMA FINANCIAL INFORMATION
Introduction
In connection with the closing of the initial public offering of
trust units of VOC Energy Trust, pursuant to that certain
Contribution and Exchange Agreement dated August 30, 2010,
VOC Brazos Energy Partners, L.P. (VOC Brazos) will
acquire the membership interests in VOC Kansas Energy Partners,
LLC (KEP) in exchange for newly issued limited
partnership interests in VOC Brazos, resulting in KEP becoming a
wholly-owned subsidiary of VOC Brazos (the KEP
Acquisition). As used herein, VOC Sponsor
refers to VOC Brazos after giving effect to the KEP Acquisition.
Concurrent with the closing of the initial public offering, VOC
Sponsor will convey to the Trust the Net Profits Interest
representing the right to receive 80% of the net proceeds from
production from substantially all of the interests in oil and
natural gas properties in the states of Kansas and Texas held by
VOC Sponsor as of the date of the conveyance of the Net Profits
Interest to the trust (the Underlying Properties).
The unaudited pro forma statement of assets and trust corpus
presents the beginning statement of assets and trust corpus of
the Trust as of December 31, 2010, as adjusted to give effect to
the conveyance of the Net Profits Interest to the Trust and the
issuance of trust units as if they occurred on December 31,
2010. The unaudited pro forma statements of distributable income
for the year ended December 31, 2010 give effect to the
conveyance of the Net Profits Interest to the Trust and the
issuance of trust units as if they occurred on January 1,
2010, reflecting only pro forma adjustments expected to have a
continuing impact on the combined results.
These unaudited pro forma financial statements are for
informational purposes only. They do not purport to present the
results that would have actually occurred had the Net Profits
Interest conveyance been completed on the assumed dates or for
the periods presented, or which may be realized in the future.
To produce the pro forma financial information, management of
VOC Sponsor made certain estimates. The accompanying unaudited
pro forma statement of assets and trust corpus assumes an
issuance of 16,540,000 trust units at an assumed public offering
price of $20.00 per unit. These estimates are based on the most
recently available information. To the extent there are
significant changes in these amounts, the assumptions and
estimates herein could change significantly.
The unaudited pro forma statement of assets and trust corpus and
unaudited pro forma statements of distributable income should be
read in conjunction with the accompanying notes to such
unaudited pro forma financial information and the audited
statement of assets and trust corpus of the Trust, including the
related notes, included in this prospectus and elsewhere in the
registration statement.
F-24
VOC
ENERGY TRUST
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
|
Historical
|
|
|
Adjustments
|
|
|
Pro Forma
|
|
|
|
(a)
|
|
|
|
|
|
|
|
|
ASSETS
|
Cash
|
|
$
|
1,000
|
|
|
$
|
|
|
|
$
|
1,000
|
|
Investment in Net Profits Interest (See Note E)
|
|
|
|
|
|
|
144,536,661
|
|
|
|
144,536,661
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,000
|
|
|
$
|
144,536,661
|
|
|
$
|
144,537,661
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TRUST CORPUS
|
|
|
|
|
|
|
|
|
|
|
|
|
16,540,000 trust units issued and outstanding
|
|
$
|
1,000
|
|
|
$
|
144,536,661
|
|
|
$
|
144,537,661
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
VOC Energy Trust was formed in
November, 2010 and capitalized on December 17, 2010.
|
The accompanying notes are an
integral part of the unaudited pro forma financial statement.
F-25
VOC
ENERGY TRUST
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31, 2010
|
|
|
Historical Results
|
|
|
|
|
Income from the Net Profits Interest (See Note D)
|
|
$
|
27,489,986
|
|
Pro Forma Adjustments
|
|
|
|
|
Less trust general and administrative expenses (See
Note E(a))
|
|
|
900,000
|
|
|
|
|
|
|
Distributable income
|
|
$
|
26,589,986
|
|
|
|
|
|
|
Distributable income per unit
|
|
$
|
1.61
|
|
|
|
|
|
|
The accompanying notes are an
integral part of the unaudited pro forma financial statements.
F-26
VOC
Energy Trust
NOTE A
BASIS OF PRESENTATION
In connection with the closing of the initial public offering of
trust units of VOC Energy Trust (the Trust),
pursuant to that Certain Contribution and Exchange Agreement
dated August 30, 2010, VOC Brazos Energy Partners, L.P.
(VOC Brazos) will acquire the membership interests
in VOC Kansas Energy Partners, LLC (KEP) in exchange
for newly issued limited partnership interests in VOC Brazos,
resulting in KEP becoming a wholly-owned subsidiary of VOC
Brazos (the KEP Acquisition). As used herein,
VOC Sponsor refers to VOC Brazos after giving effect
to the KEP Acquisition. Concurrent with the closing of the
initial public offering, VOC Sponsor will convey to the Trust a
term net profits interest (the Net Profits Interest)
representing the right to receive 80% of the net proceeds from
production from substantially all of the interests in oil and
natural gas properties in the states of Kansas and Texas held by
VOC Sponsor as of the date of the conveyance of the Net Profits
Interest to the Trust (the Underlying Properties).
The unaudited pro forma statement of assets and trust corpus
presents the statement of assets and trust corpus of the Trust
as of December 31, 2010, as adjusted to give effect to the
conveyance of the Net Profits Interest to the Trust and the
issuance of trust units as if they occurred on December 31,
2010. The unaudited pro forma statements of distributable income
for the year ended December 31, 2010 give effect to the
conveyance of the Net Profits Interest to the Trust and the
issuance of trust units as if they occurred on January 1,
2010, reflecting only pro forma adjustments expected to have a
continuing impact on the combined results.
The Trust was formed on November 3, 2010 under Delaware law
to acquire and hold the Net Profits Interest for the benefit of
the holders of the trust units. The Net Profits Interest is
passive in nature and The Bank of New York Mellon Trust Company,
N.A., as trustee (the Trustee), will have no
management control over and no responsibility relating to the
operation of the Underlying Properties.
NOTE B
TRUST ACCOUNTING POLICIES
These Unaudited Pro Forma Statements were prepared using the
accrual basis information from the historical revenue and direct
operating expenses of the underlying properties. The Trust uses
the modified cash basis of accounting to report Trust receipts
of the term Net Profits Interest and payments of expenses
incurred. Actual cash receipts may vary due to timing delays of
actual cash receipts from the property operators or purchasers
and due to wellhead and pipeline volume balancing agreements or
practices. The actual cash distributions of the Trust will be
made based on the terms of the conveyance creating the
Trusts Net Profits Interest which is on a modified cash
basis of accounting. An adjustment is made for development
expenses which will reduce the cash distributions but are not
shown as expenses on the accrual basis historical data.
Investment in the Net Profits Interest is recorded initially at
the historic cost of VOC Sponsor and periodically assessed to
determine whether its aggregate value has been impaired below
its total capitalized cost based on the underlying properties.
The Trust will provide a write-down to its investment in the Net
Profits Interest to the extent that total capitalized costs,
less accumulated depreciation, depletion and amortization,
exceed undiscounted future net revenues attributable to the
proved oil and gas reserves of the underlying properties.
VOC Sponsor believes that the assumptions used provide a
reasonable basis for presenting the significant effects directly
attributable to this transaction.
F-27
This unaudited pro forma financial information should be read in
conjunction with the Statement of Historical Revenues and Direct
Operating Costs for Underlying Properties and related notes for
the periods presented.
NOTE C
INCOME TAXES
The Trust is a Delaware statutory trust and is not required to
pay federal or state income taxes. Accordingly, no provision for
Federal or state income taxes has been made.
NOTE D
INCOME FROM NET PROFITS INTEREST
The table below outlines the calculation of Trust income from
Net Profits Interest derived from the excess of revenues over
direct operating expenses of the Underlying Properties for the
year ended December 31, 2010:
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31, 2010
|
|
|
Excess of revenues over direct operating expenses of Underlying
Properties
|
|
$
|
44,854,562
|
|
Development expenses (1)
|
|
|
10,492,080
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses and
development expenses
|
|
|
34,362,482
|
|
Times Net Profits Interest over the term of the Trust
|
|
|
80
|
%
|
|
|
|
|
|
Trust Income from Net Profits Interest
|
|
$
|
27,489,986
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Per terms of the Net Profits
Interest development costs are to be deducted when calculating
the distributable income to the Trust.
|
NOTE E
PRO FORMA ADJUSTMENTS
The Net Profits Interest is recorded at the historical cost of
VOC Sponsor and is calculated as follows as of December 31,
2010:
|
|
|
|
|
Oil and gas properties consisting of the Underlying Properties
|
|
$
|
210,789,946
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(28,174,233
|
)
|
|
|
|
|
|
Net Property Value
|
|
|
182,615,713
|
|
Plus hedge asset
|
|
|
182,817
|
|
Less asset retirement obligation (1)
|
|
|
(4,242,466
|
)
|
|
|
|
|
|
Net property to be conveyed
|
|
|
178,556,064
|
|
|
|
|
|
|
Times 80% Net Profits Interest to Trust with the asset
retirement obligation limited to the life of the Trust
|
|
$
|
144,536,661
|
|
|
|
|
|
|
|
|
|
(1)
|
|
See Note F below for a
description of asset retirement obligation.
|
(a) These Trust administrative expenses are anticipated to
aggregate approximately $900,000 for 2011. Administrative
expenses for subsequent years could be greater or less depending
on future events that cannot be predicted. Included in the
$900,000 annual estimate is an annual administrative fee of
$150,000 for the Trustee and an annual administrative fee of
$2,500 for the Delaware trustee as well as an annual
administrative fee payable to VOC Sponsor, which fee will total
$75,000 in 2011 and will increase by 4% each year beginning in
January 2012. See The trust. The Trust will pay, out
of the first cash payment received by the trust, the
trustees and Delaware trustees legal expenses
incurred in forming the trust as well as the Delaware
trustees
F-28
acceptance fee in the amount of $4,000. These costs will be
deducted by the trust before distributions are made to trust
unitholders.
NOTE
F ASSET RETIREMENT OBLIGATIONS
Accounting guidance requires that the fair value of a liability
for an asset retirement obligation be recognized in the period
in which the liability is incurred. The liability is measured at
fair value and is adjusted to its present value in subsequent
periods as accretion expense is recorded. Such accretion expense
is included in depreciation, depletion, amortization and
accretion in statements of earnings. The corresponding asset
retirement costs are capitalized as part of the carrying amount
of the related long-lived asset and amortized over the
assets useful life. If the fair value of the estimated
retirement obligation changes, an adjustment is recorded for
both the asset retirement obligation and the asset retirement
cost. VOC Sponsors asset retirement obligations are
primarily associated with the plugging and abandoning of oil and
gas properties.
The estimated plug and abandon dates change routinely based upon
additional engineering data and changes in the price of oil
impacting the date when the well is no longer economically
feasible to operate. The asset retirement obligation is measured
on an annual basis based upon the then current plug and abandon
dates of the wells using the original measurement date rates.
Asset retirement obligations on new wells drilled are calculated
on their initial measurement date based upon the then current
interest rate environment.
F-29
BUSINESS
AND PROPERTIES OF VOC SPONSOR
In connection with the closing of the initial public offering of
trust units of VOC Energy Trust, pursuant to that certain
Contribution and Exchange Agreement dated August 30, 2010, VOC
Brazos Energy Partners, L.P. (VOC Brazos) will
acquire all of the membership interests in VOC Kansas
Energy Partners, L.L.C. (KEP) in exchange for newly
issued limited partnership interests in VOC Brazos, resulting in
KEP becoming a wholly-owned subsidiary of VOC Brazos (the
KEP Acquisition). As used herein, VOC
Sponsor refers to VOC Brazos after giving effect to the
KEP Acquisition. VOC Brazos is a privately held limited
partnership engaged in the production and development of oil and
natural gas from properties located in Texas. VOC Brazos was
formed in May 2003. KEP was formed in November 2009 to develop
and produce oil and natural gas from properties primarily
located in Kansas along with a limited number of Texas
properties. Members of KEP acquired interests in the properties
owned by KEP through various acquisitions and drilling
activities that have occurred since 1979. See Prospectus
summary Formation transactions for a more
detailed discussion of the KEP Acquisition.
The Underlying Properties consist of substantially all of the
oil and natural gas properties of VOC Sponsor. Therefore, all
information set forth in the prospectus related to the reserves
and operations of the Underlying Properties is the same as the
information that would be set forth for VOC Sponsor.
As of December 31, 2010, VOC Sponsor held interests in
approximately 881 gross (545.7 net) producing wells, and
proved reserves of the Underlying Properties were approximately
13.7 MMBoe. As of December 31, 2010, approximately 98%
of the total proved reserves attributable to the Underlying
Properties, based on pre-tax present value of estimated future
net revenue using a discount rate of ten percent per annum
(PV-10),
were operated, or operated on a contract operator basis, by Vess
Oil Corporation (which we refer to as Vess Oil), L.
D. Drilling Inc. or Davis Petroleum, Inc. (which we refer to
collectively with Vess Oil as the VOC Operators),
with Vess Oil operating approximately 91% of the total proved
reserves and L.D. Drilling Inc. and Davis Petroleum, Inc.
operating approximately 7% of the total proved reserves. Vess
Oil has operated oil and natural gas properties in Kansas for
more than 30 years and, according to statistics furnished
by the Kansas Geological Survey was the second largest operator
of oil properties in Kansas measured by production during 2010.
Vess Oil currently operates over 1,600 oil, natural gas and
service wells located primarily in Kansas, with growing
operations in Texas. As of December 31, 2010, Vess Oil
employed 19 full-time employees, three contract
professionals and 14 contract personnel in its Wichita office
and in five field and satellite offices.
The trust units do not represent interests in, or obligations
of, VOC Sponsor.
MANAGEMENT
OF VOC SPONSOR
VOC Sponsor does not currently have any executive officers,
directors or employees. Instead, VOC Sponsor is managed by its
general partner, Vess Texas Partners, LLC. The officers of Vess
Texas Partners LLC consist of employees of Vess Oil. None of the
members of the executive management team of Vess Oil who perform
management functions for VOC Sponsor receive any compensation
from the trust or from VOC Sponsor.
VOC-2
Set forth in the table below are the names, ages, and titles at
Vess Oil of the members of the executive management team of Vess
Oil who perform management functions on behalf of Vess Texas
Partners, LLC, VOC Sponsors general partner:
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Title
|
|
J. Michael Vess
|
|
|
59
|
|
|
President & Chief Executive Officer
|
William R. Horigan
|
|
|
61
|
|
|
Vice President of Operations
|
Brian Gaudreau
|
|
|
55
|
|
|
Vice President of Land
|
Barry Hill
|
|
|
35
|
|
|
Vice President and Chief Financial Officer
|
Alan Howarter
|
|
|
55
|
|
|
Vice President of Financial Reporting
|
Executive
Management from Vess Oil
J. Michael Vess is the President, Chief Executive
Officer and principal owner of Vess Oil. Mr. Vess
co-founded Vess Oil in 1979 and has continuously been
responsible for the coordination and supervision of exploration
and production and the acquisition of its oil and natural gas
reserves. Mr. Vess has continuously served as the President and
Chief Executive Officer and of Vess Oil since 1987.
Mr. Vess received a Bachelor of Business Administration
degree from Wichita State University in 1973 and subsequently
received his CPA certificate. Mr. Vess currently serves on
the Board of Directors and Executive Committees for the Kansas
Independent Oil and Gas Association (KIOGA) and is
the current Chairman of the KIOGA Committee on Electricity. In
addition, he is Past Chairman of the KIOGA Tax Committee and a
current member of the Interstate Oil and Gas Compact Commission
Outreach Committee.
William R. Horigan is the Vice President of Operations
for Vess Oil where he is responsible for the engineering,
enhancement and exploitation of its existing properties as well
as the engineering analysis and evaluation of its future reserve
acquisitions. Mr. Horigan has continuously served as the Vice
President of Operations for Vess Oil since August of 1998.
Mr. Horigan joined Vess Oil in 1988 as Operations Manager.
Prior to joining Vess Oil, Mr. Horigan served in various
petroleum engineering capacities for Amoco Production Company
beginning in 1975. Mr. Horigan later served as
Division Operations Manager for Slawson Oil Company.
Mr. Horigan graduated from the University of Kansas in 1974
with a Bachelor of Science degree in Chemical Engineering.
Mr. Horigan is a member of the Society of Petroleum
Engineers and has served on the Executive Board for the Wichita
Section. He is also a member of the Producers Advisory Board of
the KU Tertiary Oil Recovery Project of the Petroleum Technology
Transfer Council of the North Mid-Continent Region.
Brian Gaudreau is the Vice President of Land and
Acquisitions for Vess Oil where he is responsible for land,
contracts and acquisitions. Mr. Gaudreau has continuously
held the position of Vice President of Land and Acquisitions
since he joined Vess Oil in 2002. Prior to joining Vess Oil, he
held the title of Manager, Land and Acquisitions for Stelbar Oil
Corporation, Inc. beginning in 1989. Mr. Gaudreau graduated
from the University of Kansas in 1977 with a Bachelors degree in
Economics. Mr. Gaudreau belongs to the American Association
of Professional Landmen, is a Director and serves on the
Executive Committee of KIOGA, and belongs to the Dallas
Acquisitions, Divestitures, and Mergers Energy Forum.
Barry Hill is the Vice President and Chief Financial
Officer for Vess Oil responsible for planning, directing and
coordinating finance activities. Mr. Hill has continuously
served as the Vice President and Chief Financial Officer for
Vess Oil since he joined Vess Oil in February 2010.
Mr. Hill spent approximately ten years in the Energy
Investment Banking group of Raymond James & Associates,
Inc., completing numerous public equity offerings, advisory
engagements and private securities assignments for a wide
spectrum of energy industry clients, including many exploration
and production companies, until his departure in January 2010.
During the last five
VOC-3
years of his employment with Raymond James & Associates,
Inc., Mr. Hill held the positions of Senior Associate and Vice
President. Mr. Hill earned his A.B. in Economics with
honors from Harvard College in 1998 and an M.B.A. from the
Darden Graduate School of Business at the University of Virginia
in 2003.
Alan Howarter is the Vice President of Financial
Reporting for Vess Oil responsible for the financial reporting
aspects of Vess Oil and other related entities.
Mr. Howarter has continuously served as the Vice President
of Financial Reporting for Vess Oil since he joined Vess Oil in
May 2007. Prior to joining Vess Oil, Mr. Howarter was a
Manager at Regier Carr & Monroe, L.L.P. Mr. Howarter
continuously held the position of Manager since the time he
joined Regier Carr & Monroe, L.L.P. in January of 2005
through his departure in May of 2007. Previously,
Mr. Howarter was a Partner and head of the Audit Department
of the Wichita office of Grant Thornton, LLP. Mr. Howarter
received his Bachelor of Business Administration degree in
Accounting from Wichita State University in 1978. He is a
licensed CPA in Kansas. Mr. Howarter is currently a member
of the Accounting Advisory Board of Wichita State University,
the American Institute of Certified Public Accountants, the
Kansas Society of Certified Public Accountants and the Petroleum
Accountants Society of Kansas. He is also a past president and
treasurer of the Petroleum Accountants Society of Kansas.
LITIGATION
VOC Sponsor is involved in legal actions and claims arising in
the ordinary course of business. Management does not expect
these matters to have a material adverse effect on the results
of operations or financial condition of VOC Sponsor.
INDEMNIFICATION
Under the partnership agreement of VOC Sponsor and subject to
specified limitations, Vess Texas Partners, LLC is not liable,
responsible or accountable in damages or otherwise to
VOC Sponsor or its members for, and VOC Sponsor will
indemnify and hold harmless Vess Texas Partners from any costs,
expenses, losses or damages (including attorneys fees and
expenses, court costs, judgments and amounts paid in settlement)
incurred by reason of its being the general partner of VOC
Sponsor.
RELATED
PARTY TRANSACTIONS
As of December 31, 2010, the VOC Operators, which includes
Vess Oil, L.D. Drilling, Inc. and Davis Petroleum, Inc.,
operated or operated on a contract basis, approximately 98% of
the total proved reserves attributable to the Underlying
Properties based on PV-10 value, with Vess Oil operating
approximately 91% of the total proved reserves for which VOC
Sponsor is the designated operator and L.D. Drilling Inc.
and Davis Petroleum, Inc. operating approximately 7% of the
total proved reserves. Vess Oil is controlled by J. Michael
Vess, L.D. Drilling Inc. is controlled by L.D. Davis,
and Davis Petroleum, Inc., is controlled by both Mr. Vess
and Mr. Davis. Under the terms of the operating arrangement
among VOC Sponsor and Vess Oil, all expenses of
VOC-4
Vess Oil incurred on behalf of VOC Sponsor are paid by VOC
Sponsor at the cost incurred. Below is a summary of the
transactions that occurred between VOC Sponsor and the VOC
Operators:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Lease operating expenses incurred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Vess Oil Corporation
|
|
$
|
10,314
|
|
|
$
|
9,334
|
|
|
$
|
10,053
|
|
LD Drilling
|
|
|
768
|
|
|
|
685
|
|
|
|
605
|
|
Davis Petroleum
|
|
|
652
|
|
|
|
704
|
|
|
|
756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
11,734
|
|
|
$
|
10,723
|
|
|
$
|
11,414
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Overhead costs included in lease operating expenses incurred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Vess Oil Corporation
|
|
$
|
1,098
|
|
|
$
|
1,232
|
|
|
$
|
1,314
|
|
LD Drilling
|
|
|
91
|
|
|
|
97
|
|
|
|
100
|
|
Davis Petroleum
|
|
|
64
|
|
|
|
72
|
|
|
|
72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,253
|
|
|
$
|
1,401
|
|
|
$
|
1,486
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized lease equipment and producing leasehold costs
incurred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Vess Oil Corporation
|
|
$
|
1,402
|
|
|
$
|
1,937
|
|
|
$
|
3,246
|
|
LD Drilling
|
|
|
304
|
|
|
|
154
|
|
|
|
(8
|
)
|
Davis Petroleum
|
|
|
220
|
|
|
|
3
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,926
|
|
|
$
|
2,094
|
|
|
$
|
3,252
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment of well development costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Vess Oil Corporation
|
|
$
|
1,709
|
|
|
$
|
2,269
|
|
|
$
|
7,149
|
|
LD Drilling
|
|
|
509
|
|
|
|
137
|
|
|
|
|
|
Davis Petroleum
|
|
|
168
|
|
|
|
|
|
|
|
81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,386
|
|
|
$
|
2,406
|
|
|
$
|
7,230
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment of management fees:
|
|
|
|
|
|
|
|
|
|
|
|
|
Vess Oil Corporation
|
|
$
|
447
|
|
|
$
|
447
|
|
|
$
|
447
|
|
LD Drilling
|
|
|
|
|
|
|
|
|
|
|
|
|
Davis Petroleum
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
447
|
|
|
$
|
447
|
|
|
$
|
447
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
VOC Sponsor pays the VOC Operators an overhead fee based on a
monthly charge per active operated well to operate substantially
all of the Underlying Properties located in Kansas on behalf of
VOC Sponsor. The fee is adjusted annually and will increase or
decrease each year based on changes in the Overhead Adjustment
Index (OAI) published by the Council of Petroleum
Accountants Society for that year. The operating activities
include various maintenance, engineering, geological, accounting
and administrative functions. As reflected in the summary
reserve reports, in 2010, the aggregate overhead fee in Kansas
paid to the VOC Operators was approximately $1.5 million.
For the Underlying Properties located in Texas, VOC Sponsor
reimburses Vess Texas Partners, LLC (Vess
LLC) for certain corporate administrative and
accounting services arranged by Vess LLC. This reimbursement
amount is adjusted annually and will increase or decrease each
year
VOC-5
based on changes in the OAI for that year. Most of the services
for which Vess LLC is reimbursed are performed on behalf of Vess
LLC by Vess Oil. The fee is currently $37,250 per month.
Vess LLC pays a portion of this $37,250 as an overhead fee to
Vess Oil to operate substantially all of the Underlying
Properties located in Texas on behalf of VOC Sponsor. The
operating activities include various maintenance, engineering,
geological, accounting and administrative functions. The
overhead fee includes (1) a fixed monthly charge of $13,500
per month, (2) reimbursement for certain geological and
engineering services and (3) a monthly charge per active
well brought on production after September 2009, which is
adjusted annual and based on changes in the Overhead Adjustment
Index.
Vess Oil is not contractually obligated to provide the corporate
administrative and accounting services on behalf of VOC Sponsor
or Vess LLC other than with respect to the operation of the
Underlying Properties, and VOC Sponsor and Vess LLC may contract
for the provision of the corporate administrative and accounting
services from other parties at any time. None of the members of
the executive management team are contractually obligated to
continue performing services on behalf of VOC Sponsor, and Vess
Oil is not contractually obligated to make its employees
available to perform such services.
The fees described above are independent of the fees payable by
the Trust pursuant to the trust agreement and the Administrative
Services Agreement. See The trust and
Description of the trust agreement Fees and
expenses.
For the year ended December 31, 2010, VOC Sponsor sold
approximately 32% of the oil produced from the Underlying
Properties to MV Purchasing, LLC, an affiliate of VOC Sponsor. A
summary of sales and trade receivables with MV Purchasing
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2008
|
|
2009
|
|
2010
|
|
|
|
|
|
Sales
|
|
$
|
1,207,358
|
|
|
$
|
13,482,074
|
|
|
$
|
19,125,260
|
|
|
|
|
|
|
|
|
|
Trade Receivables
|
|
$
|
319,109
|
|
|
$
|
1,359,842
|
|
|
$
|
1,760,141
|
|
|
|
|
|
|
|
|
|
MV Purchasing began operations on August 1, 2008.
Forty-five days following the closing of the initial public
offering of trust units, VOC Partners, LLC will
(1) purchase, at the initial offering price, trust units
owned by VOC Sponsor and (2) issue a promissory note to VOC
Sponsor having a face amount equal to 90% of the purchase price
for the trust units and a cash payment equal to 10% of the
purchase price for the trust units. The note will have a term of
ten years with interest payable at 5% per year.
In connection with the closing of this offering, VOC Acquisition
Partners, LLC, an affiliate of VOC Sponsor, will acquire
60 days after the closing of this offering all of the
outstanding equity interests in VOC Sponsor held by Vess Holding
Corporation and by affiliates of Carson Private Capital through
CPC Brazos Energy, L.P. and CPC VEP, LLC for approximately
$63.4 million. Vess Holding Corporation is the sole
managing member of VOC Sponsors general partner. Before
giving effect to this transaction, the affiliates of Carson
Private Capital own approximately 19.86% of the equity interests
in VOC Sponsor.
VOC-6
SELECTED
HISTORICAL AND UNAUDITED PRO FORMA
FINANCIAL DATA OF VOC SPONSOR
The selected financial data presented below should be read in
conjunction with the accompanying financial statements and
related notes included elsewhere in this prospectus. In
connection with the closing of initial public offering of trust
units of VOC Energy Trust, pursuant to that certain Contribution
and Exchange Agreement dated August 30, 2010, VOC Brazos
will acquire all of the membership interests in KEP in exchange
for newly issued limited partnership interests in VOC Brazos,
resulting in KEP becoming a wholly-owned subsidiary of VOC
Brazos. As the Common Control Properties are deemed to be under
common control with VOC Brazos, accounting rules specify that
VOC Brazos and the Common Control Properties be combined
from the earliest date they came under common control. The
financial data and operations of such assets are referred to
herein as Predecessor, and are described in more
detail below in Managements discussion
and analysis of financial condition and results of
operations. Accordingly, in order to give full effect to
the acquisition by VOC Brazos of KEP, the following table
includes pro forma financial and operating data of Predecessor
giving effect to the acquisition of the Acquired Underlying
Properties. Since the historical assets and operations of
Predecessor will only represent a portion of the assets and
operations to be held by VOC Sponsor at the closing of this
offering, the future results of operations of VOC Sponsor will
not be comparable to the historical results of Predecessor.
The selected combined historical financial data of Predecessor
as of December 31, 2009 and 2010 and for each of the years
in the three-year period ended December 31, 2010 have been
derived from Predecessors audited financial statements.
The selected unaudited pro forma financial data for the year
ended December 31, 2010 set forth in the following table
have been derived from the unaudited pro forma financial
statements of Predecessor included in this prospectus beginning
on
page VOC F-24.
The pro forma adjustments have been prepared as if the
acquisition of the Acquired Underlying Properties and, with
respect to pro forma as adjusted information, the offer and sale
of the trust units and application of the net proceeds
therefrom, had taken place (i) on December 31, 2010,
in the case of the pro forma balance sheet information as of
December 31, 2010, and (ii) as of January 1,
VOC-7
2010, in the case of the pro forma statement of earnings
information for the year ended December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor Pro Forma as
|
|
|
|
|
Predecessor Pro Forma for the
|
|
Adjusted for the Offering
|
|
|
|
|
|
|
|
|
Acquisition of the Acquired
|
|
(including the conveyance
|
|
|
|
|
|
|
|
|
Underlying Properties
|
|
of the Net Profits Interests)
|
|
|
Predecessor
|
|
Year Ended
|
|
Year Ended
|
|
|
Year Ended December 31,
|
|
December 31,
|
|
December 31,
|
|
|
2008
|
|
2009
|
|
2010
|
|
2010
|
|
2010
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
(Unaudited)
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
32,198
|
|
|
$
|
25,746
|
|
|
$
|
38,603
|
|
|
$
|
62,718
|
|
|
$
|
12,543
|
|
Interest income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sales of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,423
|
|
Other
|
|
|
|
|
|
|
4
|
|
|
|
32
|
|
|
|
32
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
32,198
|
|
|
|
25,750
|
|
|
|
38,635
|
|
|
|
62,750
|
|
|
|
21,998
|
|
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
7,667
|
|
|
|
6,788
|
|
|
|
7,325
|
|
|
|
13,727
|
|
|
|
2,745
|
|
Production and property taxes
|
|
|
2,532
|
|
|
|
1,646
|
|
|
|
2,720
|
|
|
|
4,137
|
|
|
|
827
|
|
Depreciation, depletion, amortization and accretion
|
|
|
5,781
|
|
|
|
5,210
|
|
|
|
6,253
|
|
|
|
12,836
|
|
|
|
2,979
|
|
Bad debt expense (recovery)
|
|
|
1,727
|
|
|
|
(719
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
269
|
|
|
|
463
|
|
|
|
205
|
|
|
|
205
|
|
|
|
205
|
|
Interest
|
|
|
1,383
|
|
|
|
1,501
|
|
|
|
1,221
|
|
|
|
1,221
|
|
|
|
1,221
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
19,359
|
|
|
|
14,889
|
|
|
|
17,724
|
|
|
|
32,126
|
|
|
|
7,977
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
$
|
12,839
|
|
|
$
|
10,861
|
|
|
|
20,911
|
|
|
|
30,624
|
|
|
|
14,021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (at year end)
|
|
$
|
108,830
|
|
|
$
|
101,280
|
|
|
|
109,038
|
|
|
|
202,171
|
|
|
|
96,358
|
|
Long-term liabilities, excluding current maturities (at year end)
|
|
$
|
37,018
|
|
|
$
|
28,315
|
|
|
|
26,241
|
|
|
|
27,805
|
|
|
|
99,392
|
|
Partners capital/Common Control owners equity
(deficit)
|
|
$
|
67,865
|
|
|
$
|
67,512
|
|
|
|
70,936
|
|
|
|
159,559
|
|
|
|
(26,746
|
)
|
VOC-8
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS OF VOC SPONSOR
You should read the following discussion of the financial
condition and results of operations of VOC Sponsor in
conjunction with the historical combined financial statements
and notes included elsewhere in this prospectus.
For purposes of the following discussion in
Managements discussion and analysis of financial
condition and results of operations of VOC Sponsor, all
references herein to VOC Sponsor are intended to
mean the Predecessor and without giving effect to the
acquisition of the Acquired Underlying Properties. For more
information about the presentation of the Predecessor financial
statements, please see Note A to the combined financial
statements of Predecessor beginning on page
VOC F-1.
FACTORS
THAT SIGNIFICANTLY AFFECT VOC SPONSORS RESULTS
VOC Sponsors revenue, cash flow from operations and future
growth depend substantially on factors beyond its control, such
as economic, political and regulatory developments and
competition from producers of alternative sources of energy. Oil
and natural gas prices have historically been volatile and may
fluctuate widely in the future. Sustained periods of low prices
for oil or natural gas could materially and adversely affect its
financial position, its results of operations, the quantities of
oil and natural gas that it can economically produce and its
ability to access capital.
Like all businesses engaged in the exploration and production of
oil and natural gas, VOC Sponsor faces the challenge of
natural production declines. As initial reservoir pressures are
depleted, oil and natural gas production from a given well
decreases. Thus, an oil and gas exploration and production
company depletes part of its asset base with each unit of oil or
natural gas it produces. VOC Sponsor attempts to reduce this
natural decline by undertaking field development programs and by
implementing secondary recovery techniques. VOC Sponsor intends
to maintain its focus on costs necessary to produce its
reserves. VOC Sponsors ability to make development
expenditures to maintain production from its existing reserves
and to add reserves through development drilling is dependent on
its capital resources and can be limited by many factors.
VOC-9
RESULTS
OF OPERATIONS
Set forth in the table below is a summary of VOC
Predecessors financial data for the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
(In thousands)
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
32,198
|
|
|
$
|
25,746
|
|
|
$
|
38,603
|
|
Interest income
|
|
|
|
|
|
|
4
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
$
|
32,198
|
|
|
$
|
25,750
|
|
|
$
|
38,635
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
7,667
|
|
|
|
6,788
|
|
|
|
7,325
|
|
Production and property taxes
|
|
|
2,532
|
|
|
|
1,646
|
|
|
|
2,720
|
|
Depreciation, depletion, amortization and accretion
|
|
|
5,781
|
|
|
|
5,210
|
|
|
|
6,253
|
|
Bad debt expense (recovery)
|
|
|
1,727
|
|
|
|
(719
|
)
|
|
|
|
|
General and administrative
|
|
|
269
|
|
|
|
463
|
|
|
|
205
|
|
Interest
|
|
|
1,383
|
|
|
|
1,501
|
|
|
|
1,221
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
$
|
19,359
|
|
|
$
|
14,889
|
|
|
$
|
17,724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
$
|
12,839
|
|
|
$
|
10,861
|
|
|
$
|
20,911
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31, 2010 Compared To Year Ended
December 31, 2009
Revenues Revenues from oil and natural gas
sales increased $12.9 million between these periods. This
consists of an increase of $15.0 million of oil and natural
gas revenues and a $2.2 million increase in hedge expense.
The $15.0 million increase in revenues was primarily the
result of an increase in the average price received for the oil
sold from $55.86 per Bbl for the year ended December 31,
2009 to $74.59 per Bbl for the year ended December 31, 2010
and an 87.5 MBbl increase in oil volumes sold. The increase
in revenues was also the result of an increase in the average
price received for the natural gas sold from $3.64 per Mcf for
the year ended December 31, 2009 to $5.36 per Mcf for the
year ended December 31, 2010, and a 32.2 MMcf increase
in natural gas volumes sold.
Hedge Activity The increase in hedge and other
derivative activity expense of $2.2 million for the year
ended December 31, 2010 was due to an increase in realized
hedge losses and was partially offset by a small increase in
ineffectiveness of hedges then in place being recorded to the
income account for the period.
The increase in hedge and other derivative expense was due to
the higher average NYMEX price per Bbl of crude oil for the year
ended December 31, 2010 of $79.53 compared to $61.80 for
year ended December 31, 2009. The weighted average
settlement price of hedges for the year ended December 31,
2010 was $74.40 compared to $68.51 for the year ended
December 31, 2009.
In addition, at December 31, 2010, VOC Sponsor recorded a
$0.3 million income for ineffectiveness of hedges compared
to a $0.0 million expense at December 31, 2009. At
December 31, 2009, VOC Sponsor had open swap agreements
covering the next 24 months. At December 31, 2010, VOC
Sponsor had open swap agreements covering the next
12 months.
VOC-10
Hedge ineffectiveness of the swap agreements is the result of
various factors including changes in the average crude oil price
and changes in the basis differential between the NYMEX price
and the price actually received by VOC Sponsor.
Hedge ineffectiveness and actual hedge losses increased during
the period of rising oil prices as experienced from 2009 to 2010
when the average NYMEX price per barrel of crude oil went from
$41.92 to $89.23. Hedge ineffectiveness and hedge losses
typically decrease during periods of flat or declining oil
prices. Because commodity prices can fluctuate significantly,
past performance of VOC Sponsors hedges is not necessarily
indicative of their future performance.
Lease operating expenses Lease operating
expenses increased from $6.8 million for the year ended
December 31, 2009 to $7.3 million for the year ended
December 31, 2010. This increase was primarily a result of
an increase in general operating expenses and increased costs
due to additional wells being added which was partially offset
by the electronification of wells in the Texas properties. The
operator is replacing the inefficient gas pumping motors in the
Texas properties with electronic motors which can be shut-off
and restarted during the day as needed. This process reduces
wear on the moving parts of the well thereby reducing repairs
and maintenance costs.
Production and property taxes Production and
property taxes increased due to the increased price of oil and
gas on which the taxes are based.
Depreciation, depletion, amortization and
accretion Depreciation, depletion, amortization
and accretion increased from $5.2 million for the year
ended December 31, 2009 to $6.3 million for the year
ended December 31, 2010. Depreciation, depletion and
amortization are calculated based on units of production. The
increase comes from the addition of lease and well equipment for
the new wells drilled in 2010 and is partially offset by the
previously reduced asset base combined with an increase in the
total estimated reserves.
Bad debt expense (recovery) During the year
ended December 31, 2009, recovery was made of the
$1.4 million due for the Texas Properties. As a result of
the recovery, VOC Sponsor recorded bad debt recovery of
$0.7 million, which reverses the bad debt expense which was
recorded in 2008.
During the year ended December 31, 2010, there was no bad
debt expense or recovery.
General and administrative expenses General
and administrative expenses decreased from $0.5 million for
the year ended December 31, 2009 to $0.2 million for
the year ended December 31, 2010. This is a decrease
primarily due to the timing of expenses and a reduction of
general costs.
Interest expenses Interest expense decreased
from $1.5 million for the year ended December 31, 2009
to $1.2 million for the year ended December 31, 2010.
This is primarily a result of principal payments made on the
note during 2009 in addition to a reduction of interest rates.
During the year ended December 31, 2009, VOC Sponsors
outstanding debt balance decreased from $35.0 million to
$27.2 million, while during the year ended
December 31, 2010, its outstanding debt balance decreased
to $24.0 million.
Year
Ended December 31, 2009 Compared To The Year Ended
December 31, 2008
Revenues. Revenues from oil and natural gas
sales decreased $6.4 million between these periods. This
consists of a decrease of $15.7 million of oil and natural
gas revenues and was partially offset by a $9.3 million
decrease in hedge expense. The $15.7 million decrease in
VOC-11
revenues was primarily the result of a decrease in the average
price received for the oil sold from $94.11 per Bbl for the year
ended December 31, 2008 to $55.88 per Bbl for the year
ended December 31, 2009. The decrease in revenues was also
the result of a decrease in the average price received for the
natural gas sold from $7.86 per Mcf for the year ended
December 31, 2008 to $3.64 per Mcf for the year ended
December 31, 2009.
The decrease in hedge activity expense of $9.3 million for
the year ended December 31, 2009 was due primarily to the
lower average NYMEX settle price for the year ended
December 31, 2009 of $61.80 compared to $99.65 for the year
ended December 31, 2008. The weighted average hedge price
for 2009 was $68.51 compared to $70.03 for 2008.
Lease operating expenses. Lease operating
expenses decreased from $7.7 million for the year ended
December 31, 2008 to $6.8 million for the year ended
December 31, 2009. This decrease was primarily the result
of the electronification of wells in the Texas properties. The
operator started replacing the inefficient gas pumping motors in
the Texas properties with electronic motors which can be
shut-off and restarted during the day as needed. This process
also reduces wear on the moving parts of the well thereby
reducing repairs and maintenance costs.
Production and property taxes. Production and
property taxes decreased from $2.5 million for the year
ended December 31, 2008 to $1.6 million for the year
ended December 31, 2009. Production and property taxes
decreased primarily as a result of the decreases in the price of
crude oil and in revenues from oil and natural gas sales on
which these taxes are based.
Depreciation, depletion, amortization and
accretion. Depreciation, depletion, amortization
and accretion decreased from $5.8 million for the year
ended December 31, 2008 to $5.2 million for the year
ended December 31, 2009. Depreciation, depletion and
amortization are calculated based on units of production. The
decline comes from the previously reduced asset base combined
with an increase in the total estimated reserves.
Bad debt expense (recovery). During the year
ended December 31, 2008, as there was no assurance as to
the dollar amount, if any, that would be recovered or the timing
of such recovery, an allowance for doubtful accounts of
$0.7 million, or 50% of the total estimated amount owed
from Eaglwing, L.P. to Predecessor for the Texas Underlying
Properties, was established as of December 31, 2008. In
addition, an allowance was set up for the oil purchased from the
Kansas Underlying Properties in the amount of $1.0 million,
which represents approximately 87% of June 2008 sales made to
Eaglwing, L.P.
During the year ended December 31, 2009, recovery was made
of the $1.4 million due for the Texas Properties. As a
result of the recovery, VOC Sponsor recorded bad debt recovery
of $0.7 million, which reverses the bad debt expense which
was recorded in 2008.
General and administrative expenses. General
and administrative expenses increased from $0.3 million for
the year ended December 31, 2008 to $0.5 million for
the year ended December 31, 2009. This is an increase
primarily due to inflation in general costs.
Interest expense. Interest expense increased
from $1.4 million for the year ended December 31, 2008
to $1.5 million for the year ended December 31, 2009.
This is a result of borrowings of $1.1 million that took
place in April of 2008, $30.0 million that took place in
July of 2008 and $1.5 million that took place in August
2008 and carrying a balance through the entire year of 2009. The
interest expense was also affected by the decrease in interest
rates from the year ended December 31, 2008 to the year
ended December 31, 2009.
VOC-12
LIQUIDITY
AND CAPITAL RESOURCES
VOC Sponsors primary sources of capital and liquidity have
been proceeds from sales of partnership interests, borrowings
under its bank credit facility and cash flow from operations. To
date, its primary uses of capital have been to service its debt
requirements, for development of working interests in its oil
and natural gas properties located in Kansas and Texas and for
distributions. It continually monitors its capital resources
available to meet its future financial obligations and planned
development expenditures.
Cash
Flow from Operating Activities
Net cash provided by operating activities was $15.8 million
and $27.6 million for the years ended December 31,
2009 and 2010, respectively. The increase in net cash provided
by operating activities was due substantially to increases in
the price of oil and sales volumes.
VOC Sponsors cash flow from operations is subject to many
variables, the most significant of which are oil and natural gas
prices. Oil and natural gas prices are determined primarily by
prevailing market conditions, which are dependent on regional
and worldwide economic activity, weather and other factors
beyond its control. VOC Sponsors future cash flow from
operations will depend on its ability to maintain and increase
production through its development program, as well as the
prices of oil and natural gas.
VOC Sponsor has entered into certain hedge contracts related to
the oil production from the Underlying Properties for 2011, 2012
and 2013 that hedge approximately 66% expected oil production
for such years from the proved developed producing reserves
attributable to the Underlying Properties in the reserve
reports. The hedge contracts will not be pledged to the trust,
but any payments made by VOC Sponsor upon settlement of the
hedge contracts will be factored into the calculation of the net
proceeds from the Underlying Properties. Any proceeds received
by VOC Sponsor upon settlement of the hedge contracts will
separately be factored into the
VOC-13
calculation of payment due to the trust. From January 1,
2011 through December 31, 2013, VOC Sponsors crude
oil price risk management position in swap contracts is as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Swaps
|
|
|
|
|
Weighted
|
|
|
Volumes
|
|
Average Price
|
Month
|
|
(Bbls)
|
|
(Per Bbl)
|
|
January 2011
|
|
|
|
|
|
|
13,689
|
|
|
$
|
94.90
|
|
February 2011
|
|
|
|
|
|
|
13,621
|
|
|
$
|
94.90
|
|
March 2011
|
|
|
|
|
|
|
20,014
|
|
|
$
|
96.77
|
|
April 2011
|
|
|
|
|
|
|
43,407
|
|
|
$
|
99.99
|
|
May 2011
|
|
|
|
|
|
|
42,828
|
|
|
$
|
99.98
|
|
June 2011
|
|
|
|
|
|
|
42,285
|
|
|
$
|
99.98
|
|
July 2011
|
|
|
|
|
|
|
41,766
|
|
|
$
|
99.97
|
|
August 2011
|
|
|
|
|
|
|
41,271
|
|
|
$
|
99.96
|
|
September 2011
|
|
|
|
|
|
|
40,796
|
|
|
$
|
99.95
|
|
October 2011
|
|
|
|
|
|
|
40,337
|
|
|
$
|
99.94
|
|
November 2011
|
|
|
|
|
|
|
39,898
|
|
|
$
|
99.94
|
|
December 2011
|
|
|
|
|
|
|
39,476
|
|
|
$
|
99.93
|
|
January 2012
|
|
|
|
|
|
|
39,038
|
|
|
$
|
100.84
|
|
February 2012
|
|
|
|
|
|
|
38,631
|
|
|
$
|
100.84
|
|
March 2012
|
|
|
|
|
|
|
38,251
|
|
|
$
|
100.85
|
|
April 2012
|
|
|
|
|
|
|
37,882
|
|
|
$
|
100.85
|
|
May 2012
|
|
|
|
|
|
|
37,523
|
|
|
$
|
100.85
|
|
June 2012
|
|
|
|
|
|
|
37,176
|
|
|
$
|
100.85
|
|
July 2012
|
|
|
|
|
|
|
36,839
|
|
|
$
|
100.86
|
|
August 2012
|
|
|
|
|
|
|
36,513
|
|
|
$
|
100.86
|
|
September 2012
|
|
|
|
|
|
|
36,194
|
|
|
$
|
100.86
|
|
October 2012
|
|
|
|
|
|
|
35,883
|
|
|
$
|
100.86
|
|
November 2012
|
|
|
|
|
|
|
35,562
|
|
|
$
|
100.87
|
|
December 2012
|
|
|
|
|
|
|
35,268
|
|
|
$
|
100.87
|
|
January 2013
|
|
|
|
|
|
|
34,975
|
|
|
$
|
99.01
|
|
February 2013
|
|
|
|
|
|
|
34,686
|
|
|
$
|
99.01
|
|
March 2013
|
|
|
|
|
|
|
34,406
|
|
|
$
|
99.01
|
|
April 2013
|
|
|
|
|
|
|
34,166
|
|
|
$
|
99.01
|
|
May 2013
|
|
|
|
|
|
|
33,959
|
|
|
$
|
99.01
|
|
June 2013
|
|
|
|
|
|
|
33,727
|
|
|
$
|
99.01
|
|
July 2013
|
|
|
|
|
|
|
33,526
|
|
|
$
|
99.01
|
|
August 2013
|
|
|
|
|
|
|
33,317
|
|
|
$
|
99.01
|
|
September 2013
|
|
|
|
|
|
|
33,122
|
|
|
$
|
99.01
|
|
October 2013
|
|
|
|
|
|
|
32,929
|
|
|
$
|
99.01
|
|
November 2013
|
|
|
|
|
|
|
32,741
|
|
|
$
|
99.01
|
|
December 2013
|
|
|
|
|
|
|
32,554
|
|
|
$
|
99.01
|
|
By removing the price volatility from a significant portion of
its oil production, VOC Sponsor has mitigated, but not
eliminated, the potential effects of changing commodity prices
on its cash flow from operations for those periods. While
mitigating negative effects of falling crude oil prices, these
derivative contracts also limit the benefits VOC Sponsor would
receive from increases in crude oil prices. It is VOC
Sponsors policy to enter into derivative contracts only
with counterparties that are major, creditworthy financial
institutions deemed by management as competent and competitive
market makers.
Cash
Flows from Investing Activities
VOC Sponsors development expenditures were
$3.7 million in the year ended December 31, 2009 and
$10.0 million in the year ended December 31, 2010. The
total for 2009 includes the purchase of oil and natural gas
properties and the payment of well development costs.
VOC-14
VOC Sponsor currently anticipates that its development
budget, which predominantly consists of workover drilling,
secondary recovery projects and equipment, will be
$8.2 million for 2011. The amount and timing of its
development expenditures is largely discretionary and within its
control. VOC Sponsors routinely monitors and adjusts its
development expenditures in response to changes in oil and
natural gas prices, development costs, industry conditions and
internally generated cash flow. Future cash flows are subject to
a number of variables, including the level of production and
prices. There can be no assurance that operations and other
capital resources will provide cash in sufficient amounts to
maintain planned levels of development expenditures.
Financing
Activities
Credit
facility
On June 27, 2008, VOC Sponsor entered into a bank credit
facility with a group of bank lenders that provides for a
revolving line of credit, letters of credit and swing line
loans. The total amount that VOC Sponsor can borrow and have
outstanding at any one time is limited to the lesser of the
total commitment of $100 million or the borrowing base
established by the lenders. As of December 31, 2010, the
borrowing base under the bank credit facility was
$37.0 million. As of December 31, 2010, the principal
amount outstanding under the bank credit facility was
$24.0 million with no letters of credit or swing line loans
outstanding.
The bank credit facility allows VOC Sponsor to borrow, repay and
reborrow amounts available under the bank credit facility. The
amount of the borrowing base is based primarily upon the
estimated value of VOC Sponsors oil and natural gas
reserves. The borrowing base under the bank credit facility is
subject to re-determination at least semi-annually. The bank
credit facility matures on June 27, 2013, and borrowings
under the bank credit facility bear interest, payable quarterly,
at VOC Sponsors option, at (1) a rate (as defined and
further described in the bank credit facility) per annum equal
to a Eurodollar Rate (which is substantially the same as the
London Interbank Offered Rate) for one, two, three or six months
as offered by the lead bank under the bank credit facility or
(2) the higher of the Federal Funds Rate (as defined and
further described in the bank credit facility) plus
50 basis points or such banks Prime Rate.
VOC Sponsors bank credit facility bore interest at
2.13% per annum as of December 31, 2010. VOC Sponsor pays
quarterly commitment fees under the bank credit facility on the
unused portion of the available borrowing base at ranging from
25.0 to 50.0 basis points, dependent upon the percentage of
VOC Sponsors available borrowing base then utilized.
Borrowings under the bank credit facility are secured by a lien
on substantially all of VOC Sponsors assets and
properties in Texas. The bank credit facility also contains
restrictive covenants that may limit VOC Sponsors ability
to, among other things, pay dividends, incur additional
indebtedness, sell assets, make loans to others, make
investments, enter into mergers, incur liens and engage in
certain other transactions without the prior consent of the
lenders. The bank credit facility also requires VOC Sponsor to
maintain certain ratios as defined and further described in the
revolving credit facility, including a current ratio of not less
than 1.0 to 1.0, an interest coverage ratio not less than 2.5 to
1.0 and a maximum leverage ratio of no greater than 3.5 to 1.0.
The current ratio is defined to include the amount of the unused
borrowing base as a current asset and to exclude current
maturities of the credit facility as well as any current
liability resulting from any mark to market accounting under
accounting literature. In addition, VOC Sponsor was
required to enter into swap agreements covering 75% of estimated
production for the three years following December 31, 2008
based on proved reserves as of December 31, 2007, with a
fixed price per barrel. As of December 31, 2010, VOC
Sponsor was in compliance with all such covenants.
VOC-15
CONTRACTUAL
OBLIGATIONS
A summary of VOC Sponsors contractual obligations as of
December 31, 2010 is provided in the following table.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
Less Than
|
|
|
|
|
|
|
|
|
More Than
|
|
|
|
Total
|
|
|
1 Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
5 Years
|
|
|
|
(In thousands)
|
|
|
Long-term debt (1)
|
|
$
|
24,000
|
|
|
$
|
|
|
|
$
|
24,000
|
|
|
$
|
|
|
|
$
|
|
|
Asset retirement obligations
|
|
|
4,243
|
|
|
|
437
|
|
|
|
163
|
|
|
|
133
|
|
|
|
3,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
28,243
|
|
|
$
|
437
|
|
|
$
|
24,163
|
|
|
$
|
133
|
|
|
$
|
3,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The amounts included in the table
above represent principal maturities only. See
Managements discussion and analysis of financial
condition and results of operations of VOC Sponsor
Quantitative and qualitative disclosure about market
risk Interest rate risk for information
regarding interest payment obligations under long-term debt
obligations.
|
OFF-BALANCE
SHEET ARRANGEMENTS
As of December 31, 2010, VOC Sponsor had no off-balance
sheet arrangements and currently has no intention to establish
any off-balance sheet arrangements.
CRITICAL
ACCOUNTING POLICIES AND ESTIMATES
The discussion and analysis of VOC Sponsors historical
financial condition and results of operations is based upon its
consolidated financial statements, which have been prepared in
accordance with accounting principles generally accepted in the
United States. The preparation of these financial statements
requires it to make estimates and assumptions that affect the
reported amounts of assets, liabilities, revenues and expenses,
and related disclosure of contingent assets and liabilities.
Certain accounting policies involve judgments and uncertainties
to such an extent that there is reasonable likelihood that
materially different amounts could have been reported under
different conditions, or if different assumptions had been used.
VOC Sponsor evaluates its estimates and assumptions on a
regular basis. It bases its estimates on historical experience
and various other assumptions that are believed to be reasonable
under the circumstances, the results of which form the basis for
making judgments about the carrying values of assets and
liabilities that are not readily apparent from other sources.
Actual results may differ from these estimates and assumptions
used in preparation of its financial statements. VOC Sponsor has
provided below an expanded discussion of its more significant
accounting policies, estimates and judgments. It believes these
accounting policies reflect its more significant estimates and
assumptions used in the preparation of its financial statements.
Please read Note A of the Notes to the Financial Statements
of VOC Sponsor beginning on page VOC F-1 for a discussion of
additional accounting policies and estimates made by its
management.
Oil
and Natural Gas Properties
VOC Sponsor accounts for oil and natural gas properties by the
successful efforts method rather than the full cost method. The
most significant difference between the successful efforts
method of accounting and the full cost method is that, under the
successful efforts method, geological, geophysical and dry hole
costs on oil and natural gas properties relating to unsuccessful
wells are charged to expense and against earnings as incurred
and expenses associated with successfully locating new oil and
natural gas reserves are capitalized; whereas, under the full
cost method of accounting, such costs and expenses of
unsuccessful projects are
VOC-16
capitalized as assets, pooled with the costs of successful wells
and charged against the earnings of future periods as a
component of depletion expense.
Leasehold acquisition costs are capitalized. If proved reserves
are found on an undeveloped property, leasehold cost is
transferred to proved properties. Under this method of
accounting, costs relating to the development of proved areas
are capitalized when incurred.
Revenues from the sale of oil and gas production are recognized
as oil and gas is produced and sold.
Depreciation and depletion of producing oil and natural gas
properties is recorded based on units of production. Unit rates
are computed for unamortized drilling and development costs
using proved developed reserves and for unamortized leasehold
costs using all proved reserves. Financial Accounting Standards
Board (FASB) Accounting Standards Codification
(ASC) 932 Extractive
Industries Oil and Gas requires that acquisition
costs of proved properties be amortized on the basis of all
proved reserves, developed and undeveloped, and that capitalized
development costs (wells and related equipment and facilities)
be amortized on the basis of proved developed reserves. As more
fully described in Note K of the Notes to the Combined
Financial Statements, proved reserves are estimated by an
independent petroleum engineer, Cawley, Gillespie &
Associates, Inc., and are subject to future revisions based on
availability of additional information. As described in
Note G of the Notes to the Combined Financial Statements,
VOC Sponsor follows FASB ASC 410 Asset
Retirement and Environmental Obligations. Under FASB
ASC 410, estimated asset retirement costs are recognized
when the asset is placed in service and are amortized over
proved reserves using the units of production method. Asset
retirement costs are estimated by its engineers using existing
regulatory requirements and anticipated future inflation rates.
Property acquisition costs, if any, are capitalized when
incurred. Upon sale or retirement of complete fields of
depreciable or depleted property, the book value thereof, less
proceeds or salvage value, is credited to income. On sale or
retirement of an individual well, the proceeds are credited to
accumulated depreciation and depletion.
VOC Sponsor assesses its oil and natural gas properties for
possible impairment when facts and circumstances indicate that
their carrying value may not be recoverable. Such indicators
include changes in the companys business plans, changes in
commodity prices and, for crude oil and natural gas properties,
significant downward revisions of estimated proved-reserve
quantities. Unproven properties that are individually
significant are assessed for impairment and if considered
impaired are charged to expense when such impairment is deemed
to have occurred. VOC Sponsor assesses impairment of capitalized
costs of proved oil and natural gas properties by comparing net
capitalized costs to estimated undiscounted future net cash
flows using expected prices. If net capitalized costs exceed
estimated undiscounted future net cash flows, the measurement of
impairment is based on estimated fair value, which would
consider estimated future discounted cash flows. Determination
as to whether and how much an asset is impaired involves
management estimates on highly uncertain matters such as future
commodity prices, the effects of inflation and technology
improvements on operating expenses, production profiles, and the
outlook for global or regional market supply and demand
conditions for crude oil, natural gas, commodity chemicals and
refined products. However, the impairment reviews and
calculations are based on assumptions that are consistent with
VOC Sponsors business plans and long-term investment
decisions. As of December 31, 2008 and 2009, and
September 30, 2010, the estimated undiscounted future cash
flows for its proved oil and natural gas properties exceeded the
net capitalized costs, and no impairment was required to be
recognized.
VOC-17
Oil
and Natural Gas Reserve Quantities
VOC Sponsors estimate of proved reserves is based on the
quantities of oil and natural gas that engineering and
geological analyses demonstrate, with reasonable certainty, to
be recoverable from established reservoirs in the future under
current operating and economic parameters. Cawley,
Gillespie & Associates, Inc. prepares a reserve and
economic evaluation of all its properties on a
well-by-well
basis.
Reserves and their relation to estimated future net cash flows
impact VOC Sponsors depletion and impairment calculations.
As a result, adjustments to depletion and impairment are made
concurrently with changes to reserve estimates. VOC Sponsor
prepares its reserve estimates, and the projected cash flows
derived from these reserve estimates, in accordance with
SEC guidelines. The independent engineering firm described
above adheres to the same guidelines when preparing their
reserve reports. The accuracy of its 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 mandated economic assumptions and the judgments of the
individuals preparing the estimates.
VOC Sponsors proved reserve estimates are a function of
many assumptions, all of which could deviate significantly from
actual results. As such, reserve estimates may materially vary
from the ultimate quantities of oil and natural gas eventually
recovered.
Hedging
Activities
VOC Brazos periodically uses derivative financial instruments to
achieve a more predictable cash flow from its oil production by
reducing its exposure to fluctuations in the price of crude oil.
Currently, these transactions are swaps transactions. VOC Brazos
accounts for these activities pursuant to FASB
ASC 815 Derivatives and Hedging, which requires
that derivative instruments (including certain derivative
instruments embedded in other contracts) be recorded at fair
market value and included in the balance sheet as assets or
liabilities.
The accounting for changes in the fair market value of a
derivative instrument depends on the intended use of the
derivative instrument and the resulting designation, which is
established at the inception of a derivative instrument. FASB
ASC 815 requires that a company formally document, at the
inception of a hedge, the hedging relationship and the
entitys risk management objective and strategy for
undertaking the hedge, including identification of the hedging
instrument, the hedged item or transaction, the nature of the
risk being hedged, the method that will be used to assess
effectiveness and the method that will be used to measure hedge
ineffectiveness of derivative instruments that receive hedge
accounting treatment.
For derivative instruments designated as cash flow hedges,
changes in fair market value, to the extent the hedge is
effective, are recognized in other comprehensive income until
the hedged item is recognized in earnings. Hedge effectiveness
is assessed at least quarterly based on total changes in the
derivative instruments fair market value. Any ineffective
portion of the derivative instruments change in fair
market value is recognized immediately in earnings.
Asset
Retirement Obligations
ASC 410 Asset Retirement and Environmental
Obligations requires that the fair value of a liability for an
asset retirement obligation be recognized in the period in which
it is incurred. The liability is measured at fair value and is
adjusted to its present value in subsequent periods as accretion
expense is recorded. Such accretion expense is included in
depreciation, depletion and amortization in the accompanying
statements of earnings. The corresponding asset retirement
VOC-18
costs are capitalized as part of the carrying amount of the
related long-lived asset and amortized over the assets
useful life. VOC Sponsors asset retirement obligations are
primarily associated with the plugging of abandoned oil wells.
NEW
ACCOUNTING PRONOUNCEMENTS
In January 2010, the FASB issued ASU
2010-04,
Accounting for Various Topics Technical
Corrections to SEC Paragraphs ASU
2010-04
makes technical corrections to existing SEC guidance, including
the following topics: accounting for subsequent investments,
termination of an interest rate swap, issuance of financial
statements subsequent events, use of residential
method to value acquired assets other than goodwill, adjustments
in assets and liabilities for holding gains and losses, and
selections of discount rate used for measuring defined benefit
obligation. The adoption did not have a material impact on our
financial statements.
In January 2010, the FASB issued ASU
2010-06,
Improving Disclosures about Fair Value Measurements
(ASU
2010-06),
which provides amendments to ASC topic Fair Value
Measurements and Disclosures. This provides more robust
disclosures about (i) the different classes of assets and
liabilities measured at fair value, (ii) the valuation
techniques and inputs used, (iii) the activity in
Level 3 fair value measurements, and (iv) the
transfers between Levels 1, 2 and 3. ASU
2010-06 is
effective for fiscal years and interim periods beginning after
December 15, 2009. The adoption did not have a material
impact on our financial statements.
In February 2010, the FASB issued ASU
2010-09 (ASU
2010-09),
Subsequent Events (Topic 855). The amendments
remove the requirements for an SEC filer to disclose a date, in
both issued and revised financial statements, through which
subsequent events have been reviewed. Revised financial
statements include financial statements revised as a result of
either correction of an error or retrospective application of
U.S. GAAP. ASU
2010-09 is
effective for interim or annual financial periods ending after
June 15, 2010. The adoption of the provisions of ASU
2010-09 did
not have a material impact on our financial statements.
In April 2010, the FASB issued ASU
2010-14,
Accounting for Extractive Activities
Oil & Gas. ASU
2010-14
amends
paragraph 932-10-S99-1
due to SEC Release
No. 33-8995,
Modernization of Oil and Gas Reporting. The
amendments to the guidance on oil and gas accounting are
effective August 31, 2010. The adoption did not have a
material impact on our financial statements.
On August 2, 2010, the FASB issued ASU
2010-21,
Accounting for Technical Amendments to Various SEC Rules
and Schedules Amendments to SEC
Paragraphs Pursuant to Release
No. 33-9026:
Technical Amendments to Rules, Forms, Schedules and Codification
of Financial Reporting Policies. The ASU reflects changes
made by the SEC in Final Rulemaking
Release No. 33-9026,
which was issued in April 2009 and amended SEC requirements in
Regulation S-X
and
Regulation S-K
and made changes to financial reporting requirements in response
to the FASBs issuance of SFAS No. 141(R),
Business Combinations (FASB ASC 805), and
SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements an amendment of
ARB No. 51 ( FASB ASC 810). Adoption of ASU
2010-21 did
not have a material impact on our financial statements.
QUANTITATIVE
AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about
VOC Sponsors 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
VOC-19
losses, but rather indicators of reasonably possible losses.
This forward-looking information provides indicators of how VOC
Sponsor views and manages its ongoing market risk exposures. All
of its market risk sensitive instruments were entered into for
purposes other than speculative trading.
Commodity
Price Risk
VOC Sponsors major market risk exposure is in the pricing
applicable to its oil and natural gas production. Realized
pricing is primarily driven by the spot market prices applicable
to its oil production and the prevailing price for natural gas.
Pricing for oil production has been volatile and unpredictable
for several years, and VOC Sponsor expects this volatility to
continue in the future. The prices it receives for oil and
natural gas production depend on many factors outside of its
control.
VOC Sponsor has entered into hedging arrangements with respect
to a portion of its projected oil production through various
transactions that hedge the future prices received. These
transactions are typically price swaps whereby it will receive a
fixed price for its production and pay a variable market price
to the contract counterparty. These hedging activities are
intended to support oil prices at targeted levels and to manage
its exposure to oil price fluctuations.
Based on an oil price of $91.38 per Bbl as of December 31,
2010, the fair value of its hedge positions for 2011 was a
receivable of $0.6 million, which was due from the
counterparty. A 10% increase or decrease in the index oil
price above the 2010 price for oil would increase or decrease
the receivable by $1.4 million, respectively.
Interest
Rate Risks
At December 31, 2010, VOC Sponsor had debt outstanding
under its bank credit facility and other long-term debt of
$24.0 million. The weighted average annual interest rate
under the bank credit facility for the year ended
December 31, 2010 was 2.32%. If prevailing market interest
rates had been 1% higher as of December 31, 2010, and all
other factors affecting VOC Sponsors debt remained
the same interest expense on an annual basis would have been
$0.2 million higher.
VOC-20
DESCRIPTION
OF THE VOC BRAZOS PARTNERSHIP AGREEMENT
The following is a summary of the material provisions of the
Amended and Restated Partnership Agreement of VOC Brazos Energy
Partners, L.P. (VOC Brazos). A copy of the
Amended and Restated Partnership Agreement of VOC Brazos (the
Partnership Agreement), as well as the amendment
thereto, is included as an exhibit to the registration statement
to which this prospectus forms a part.
ORGANIZATION
AND DURATION
VOC Brazos was organized as a Texas limited partnership on
May 21, 2003 and will remain in existence until dissolved
in accordance with the Partnership Agreement. See
Dissolution.
BUSINESS
The Partnership Agreement limits the business of VOC Brazos to:
(i) holding, maintaining, renewing, acquiring, exploring,
drilling, developing and operating oil and natural gas
properties, leases and wells; (ii) producing, collecting,
storing, treating, delivering, marketing, selling or otherwise
disposing of oil, gas and related hydrocarbons and minerals;
(iii) farming-out, selling, abandoning and otherwise
disposing of assets of VOC Brazos; (iv) entering into
swaps, options, future contracts and other transactions to hedge
or to otherwise minimize the risk associated with the
fluctuation of prices to be received by VOC Brazos from the sale
of oil, gas and related hydrocarbons and minerals; and
(v) taking all such other actions incidental to any of the
foregoing as the general partner of VOC Brazos may determine to
be necessary or appropriate.
DISTRIBUTION
OF AVAILABLE CASH
On or about the tenth day of the month immediately preceding the
due date for a payment of estimated income tax by an individual,
VOC Brazos will distribute an amount of cash which the general
partner reasonably estimates equals the product of
(a) maximum marginal combined federal, state, and local
income tax rates applicable to a single individual residing in
Kansas, and (b) the net taxable income of VOC Brazos (to
the extent an estimated income tax payment is or would be due by
a partner, directly or indirectly for the applicable
distribution period), to the extent of cash available for such
distribution and provided that such distribution (i) is not
prohibited by the terms of the Partnership Agreement and
(ii) would not create a default under the Texas Revised
Limited Partnership Act (the Texas LP Act) or any
agreement with an unrelated third party to which VOC Brazos is
subject. In making this determination the general partner is
entitled to rely on the books and records, IRS Form 1065
and
Schedule K-1s,
and such other information and advice as is reasonable available
at the time of the distribution. Distributions, income, gain,
loss, deduction and credits are generally allocated to the
partners pro rata in proportion their partnership
interests, subject to certain requirements and regulations
required by the Internal Revenue Code. All cash funds of VOC
Brazos available for distribution to its members will be after
giving effect to the obligation of VOC Brazos to pay 80% of the
net proceeds to the trust pursuant to the Net Profits Interest.
For a more detailed description of the determination of
net proceeds, see Computation of net
proceeds.
MANAGEMENT
OF VOC BRAZOS AND FIDUCIARY DUTIES
The Partnership Agreement provides that the general partner of
VOC Brazos shall generally have complete and exclusive
discretion in managing and controlling the daily operations and
ordinary business of VOC Brazos in accordance with the
Partnership Agreement and to do or cause to be done any and all
acts deemed by the general partner to be necessary or
appropriate thereto.
VOC-21
The Partnership Agreement designates Vess Texas Partners, LLC as
the initial general partner. The Partnership Agreement further
provides that the general partner shall have no fiduciary duty
(including, but not limited to, any duty of loyalty or duty of
care) to VOC Brazos or any partner except (i) a duty to act
in good faith, (ii) a general obligation of fair dealing
with respect to VOC Brazos and the property of VOC Brazos,
(iii) any duty expressly set forth in the Partnership
Agreement, and (iv) any duty expressly set forth in other
written agreements of VOC Brazos. The general partner may
consult a professional staff and outside consultants. The
Partnership Agreement allows the general partner to possess
interests and engage in business activities in addition to those
relating to VOC Brazos, independently or with others, including
business interests and activities in direct competition with VOC
Brazos, and, subject to certain exceptions, neither
VOC Brazos nor the other partners have any right, title or
interest in or to such ventures.
The general partner is restricted from taking certain actions
without the approval or authorization of the holders of the
majority of the partnership interests, including (subject to
certain exceptions) the borrowing of money, mortgage or pledging
of property, selling, assigning, abandoning or otherwise
disposing of any lease of VOC Brazos, guaranteeing of
third-party payment or performance, making advance payments of
compensation or other consideration to the general partner or
the general partners affiliates, obligating the company
with respect to matters outside the scope of its business,
merging, consolidating or converting with or into any other
entity, loaning funds of VOC Brazos to the general partner or
the general partners affiliates, entering into hedging
transactions and amending or terminating any agreements or other
documents evidencing hedging transactions or waiving any of the
rights of VOC Brazos thereunder, making or approving well
expenditures or acquiring leases if the pro rata share to be
born by any indirect owner of a limited partner would exceed
$1 million, or compromising or settling any suit or dispute
for more than $100,000.
The general partner, partners, and any affiliates thereof are
restricted from retaining from or otherwise burdening the
interest in any lease of VOC Brazos with any overriding royalty
interest, net profits interest, carried interest, reversionary
interest, production payment or other burden in favor of itself,
its officers, directors and employees or any other person,
except in connection with an acquisition by the general partner,
member or such affiliate pursuant to a transaction where an
unrelated third party transferring the lease retains such an
interest or burden with respect to all of the lease being
acquired. Under no circumstances can the general partner,
limited partner or any affiliate acquire rights to any separate
horizon within or under a lease in which VOC Brazos has an
interest.
The general partner has the authority to cause VOC Brazos to
sell any oil or gas produced by or for the account of VOC Brazos
upon the best terms and conditions available, as determined in
good faith by the manager taking into account all relevant
circumstances, including but not limited to, price, quality of
production, access to markets, minimum purchase guarantees,
identity of purchaser, and length of commitment and, in any
event, on terms no less favorable to VOC Brazos than the general
partner or any affiliate thereof has recently obtained or is
obtaining for arms length sales, exchanges or dispositions
of the general partners or such affiliates
production of similar quantity and quality in the same
geographic area where VOC Brazos production is located.
The Partnership Agreement provides that Vess Oil Corporation
(Vess Oil) will serve as operator on behalf of
VOC Brazos in connection with operations on each lease held
by VOC Brazos included in the Underlying Properties that it is
operating as of the date of the Partnership Agreement unless a
third person is already designated as operator of that lease or
a third party that holds a controlling interest in that lease
will not consent to the designation of Vess Oil as operator. As
to those leases that Vess Oil is not designated as operator, the
general partner will take such actions and exercise such rights
and remedies that are reasonably available to it to
VOC-22
cause the actual operator to properly develop, maintain and
operate such leases. With respect to those leases for which Vess
Oil is designated as operator, Vess Oil, as the case may be,
shall be entitled to receive the compensation and reimbursement
to which the operator is entitled in accordance with the
provisions of the Partnership Agreement, which sets forth agreed
upon charges for certain direct expenses and material furnished
to, or transferred from or disposed of by the operator, or any
other operating agreement governing the operation of such lease.
Vess Oil may not substitute another party as operator or assign
its obligations with respect to any lease of VOC Brazos for
which it is designated as operator unless a majority of the
limited partners request, in connection with the removal of the
general partner, as such or the limited partners dissolve VOC
Brazos in accordance with the Partnership Agreement.
VOC Brazos pays an overhead fee to Vess Oil to drill, develop
and operate the underlying properties on behalf of VOC Brazos.
The overhead fee is based on a monthly charge for
administrative, supervision, officer services, overhead and
warehousing costs, including overhead costs incurred in the
construction and installation of fixed assets, the expansion of
fixed assets and other projects required for the development and
operation of the underlying properties of VOC Brazos that is
determined either (a) on the same terms and conditions as
Vess Oil charges unrelated parties, or (b) approved by
majority of its limited partners, with knowledge of the material
facts of the transaction and Vess Oils interest. The
overhead fee is adjusted annually and will increase or decrease
each year based on the Overhead Adjustment Index published by
the Council of Petroleum Accountants Society. VOC Brazos is
also directly responsible for all direct, third-party
out-of-pocket
expenses reasonably incurred on its behalf, including audit, tax
preparation and reserve report related expenses.
VOC Brazos has agreed to pay the general partner a monthly fee
of $37,250 for management-related services provided to VOC
Brazos.
LIMITED
LIABILITY
The limited partners of VOC Brazos are not liable for the debts,
liabilities, contracts or other obligations of VOC Brazos under
the Partnership Agreement. Moreover, VOC Brazos agrees to
indemnify and hold harmless the general partner, the limited
partners, their affiliates, and all of their officers,
directors, trustees, partners, principals, employees and agents
(the Indemnitees) from and against any and all
losses, claims, demands, costs, damages, liabilities, expenses,
judgments, fines, settlements and other amounts arising out of
or incidental to the business of VOC Brazos, if: (i) the
Indemnitee acted in good faith and in a manner he, she or it
reasonably believed to be in, or not opposed to, the interests
of VOC Brazos, and, with respect to any criminal proceeding, had
no reason to believe its, his, or her conduct was unlawful; and
(ii) the Indemnitees conduct did not constitute
actual fraud, gross negligence, embezzlement, or willful and
wanton misconduct. Any indemnification shall be satisfied solely
out of property of VOC Brazos, and the general partner and the
limited partners are not subject to personal liability by reason
of the indemnification provisions. The right to indemnification
shall include the right to be paid or reimbursed by VOC Brazos
the reasonable expenses incurred by the Indemnitee who was, is
or is threatened to be made a named defendant or respondent in a
proceeding in advance of the final disposition of the proceeding
and without any determination as to the Indemnitees
ultimate entitlement to indemnification.
CONTRACTS
WITH AFFILIATES
VOC Brazos may enter into various contracts and agreements with
the general partner and with affiliates of the limited partners
provided that either (a) the transaction is on the same
terms and conditions as similar transactions in the market with
non-affiliates or (b) the holders of a majority of the
limited partner interests, knowing the material facts of the
transaction and the
VOC-23
limited partners or general partners interest, as
applicable, authorize, approve or ratify the transaction.
RIGHTS OF
THE PARTNERS
The limited partners have the right to: (1) have the books
and records of VOC Sponsor kept at its principal office and at
all reasonable times to inspect and copy any of them;
(2) have on demand true and full information of all things
affecting VOC Brazos and a formal account of the affairs of VOC
Brazos whenever circumstances render it just and reasonable;
(3) cause the dissolution and winding up of VOC Brazos by a
vote of the holders of the majority of the limited partner
interests; and (4) exercise all of the rights of a member
under the Texas LP Act. In addition, the limited partners shall
be entitled to receive quarterly and annual unaudited financial
statements of VOC Brazos, promptly after becoming available and
without need for demand, at the expense of VOC Brazos. The
limited partners and their agents and representatives, from time
to time, have the right to receive from the general partner
certain monthly, quarterly, and annual reports as have been
delivered to the limited partners to date including, but not
limited to, reports containing: (1) an estimation of the
oil and gas reserves attributable to the interest of VOC Brazos
and of the limited partner therein; (2) a projection of the
rate of production of and net income from such reserves with
respect to each such interest; (3) a calculation of the
present worth of such net income discounted at a rate or rates
designated from time to time by the limited partner; and
(4) a schedule or complete description of all assumptions,
estimates and projections made or used in the preparation of
such report, including estimated future product prices, capital
expenditures, operating expenses and taxes.
The interest of a limited partner in VOC Brazos is transferable,
but no such transfer may be made if such transfer would:
(i) violate any applicable federal or state securities laws
or rules and regulations of the Securities and Exchange
Commission, any state securities commission or any other
governmental authority with jurisdiction over the transfer;
(ii) affect VOC Brazos qualification as a limited
partnership under the Texas LP Act, or would expose any limited
partner to personal liability for acts or omissions of VOC
Brazos; (iii) have the effect of separating the voting
rights from the economic rights of the interest; or
(iv) constitute an event of default under the terms of the
Partnership Agreement of VOC Brazos. VOC Brazos may, but is not
required to, recognize the assignment from the transferring
partner to the assignee on the books and records of VOC Brazos,
and may, but is not required to, recognize such assignment for
purposes of determining and making distributions, allocations,
or liquidations. No transfer of a limited partner interest of
VOC Brazos, other than a transfer to a permitted transferee
under the Partnership Agreement or upon the occurrence of
certain events may occur unless VOC Brazos right of first
refusal under the Partnership Agreement is first satisfied.
REMOVAL
OF GENERAL PARTNER
The limited partners may remove the general partner upon a vote
of the holders of a majority of the limited partner interests
(including, for this purpose, voting interests held by the
general partner), whether or not the general partner is proposed
to be removed for cause or not for cause.
AMENDMENT
OF THE PARTNERSHIP AGREEMENT
The Partnership Agreement may be amended only by an instrument
in writing duly approved by a vote of the holders of a majority
of the limited partner interests.
VOC-24
DISSOLUTION
VOC Brazos will continue as a limited partnership until
terminated under the Partnership Agreement. VOC Brazos will
dissolve upon: (1) the approval of the holders of a
majority of the limited partner interests to dissolve VOC
Brazos, provided such approval and dissolution would not
constitute an event of default under the terms of any agreement
of VOC Brazos; (2) the occurrence of an event which would
cause the dissolution of VOC Brazos under the Texas LP Act;
(3) the sole general partner resigns, is removed, withdraws
or suffers, except in the event of bankruptcy, death, divorce,
incapacity, transfer by gift, transfer upon foreclosure or other
enforcement of a security interest or lien, or termination of a
partner and one or more general partners are not admitted to VOC
Brazos within 90 days thereafter.
LIQUIDATION
AND TERMINATION
Upon dissolution of VOC Brazos, a liquidator or liquidating
committee (the Liquidator) approved by the general
partner, which such person or group may include the general
partner or any limited partner or officer, will wind up the
affairs and make final distribution. The Liquidator shall
continue to operate the properties of VOC Brazos with all of the
power and authority of the general partner necessary or
appropriate to liquidate the assets of VOC Brazos and apply the
proceeds of the liquidation as described in the Partnership
Agreement. Any assets distributed to the members upon
liquidation shall be subject to the partnership agreements then
in effect; provided, however, that if any lease is subject to an
operating agreement to which an unaffiliated third person is not
a party, such lease shall be subject to a standard form
operating agreement as shall be agreed upon by the limited
partners. Upon written request made by any limited partner, the
Liquidator shall sell VOC Brazos leases and other
properties and assets that otherwise would be distributable to
such limited partner at the best cash price available therefor
and distribute such cash (after deducting all expenses
reasonably relating to such sale) to such limited member.
VOC-25
INDEX TO
FINANCIAL STATEMENTS
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PREDECESSOR:
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VOC F-2
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VOC F-3
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VOC F-4
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VOC F-5
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VOC F-6
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VOC F-7
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Introduction
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VOC F-24
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VOC F-25
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VOC F-26
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VOC F-27
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VOC F-1
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
VOC Brazos Energy Partners, L.P.
We have audited the accompanying combined balance sheets of VOC
Brazos Energy Partners, L.P. (VOC Brazos), together
with interests in certain oil and natural gas properties of VOC
Kansas Energy Partners, LLC (KEP) under common
control with VOC Brazos (the Common Control
Properties), as of December 31, 2009 and 2010 and the
related combined statements of earnings, changes in
partners capital/common control owners equity and
cash flows for each of the three years in the period ended
December 31, 2010. When used herein,
Predecessor refers to combination of VOC Brazos and
the Common Control Properties. These combined financial
statements are the responsibility of Predecessors
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. Predecessor 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 Predecessors 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 combined 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 financial
position of Predecessor as of December 31, 2009 and 2010,
and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2010, in
conformity with accounting principles generally accepted in the
United States of America.
As discussed in note A4 to the combined financial
statements, the Predecessor adopted new oil and gas reserve
estimation and disclosure requirements as of December 31,
2009.
Grant Thornton LLP
Wichita, Kansas
March 22, 2011
VOC F-2
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December 31,
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2009
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2010
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ASSETS
|
CURRENT ASSETS
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Cash and cash equivalents
|
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$
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4,931,842
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|
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$
|
11,594,345
|
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Accounts receivable oil and gas sales
|
|
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1,090,371
|
|
|
|
1,091,745
|
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Accounts receivable oil and gas sales
related parties, net of allowance for doubtful accounts of
$1,007,594 in 2009 and $0 in 2010
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3,622,470
|
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3,645,127
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Oil swap agreements
|
|
|
|
|
|
|
182,817
|
|
Prepaid expenses
|
|
|
68,828
|
|
|
|
84,627
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
9,713,511
|
|
|
|
16,598,661
|
|
OIL AND GAS PROPERTIES
|
|
|
111,171,636
|
|
|
|
119,848,855
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
22,098,350
|
|
|
|
28,174,233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
89,073,286
|
|
|
|
91,674,622
|
|
OTHER ASSETS
|
|
|
|
|
|
|
|
|
Oil swap agreements
|
|
|
1,371,351
|
|
|
|
|
|
Deferred loan costs, net of accumulated amortization of $855,173
in 2009, and $1,403,726 in 2010
|
|
|
1,121,357
|
|
|
|
555,155
|
|
Deferred offering costs
|
|
|
|
|
|
|
209,272
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,492,708
|
|
|
|
764,427
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
101,279,505
|
|
|
$
|
109,037,710
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL/COMMON CONTROL
OWNERS EQUITY
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
46,517
|
|
|
$
|
68,854
|
|
Related parties
|
|
|
1,285,891
|
|
|
|
770,513
|
|
Accrued interest
|
|
|
146,839
|
|
|
|
63,742
|
|
Settlement payable on oil swap agreements
|
|
|
106,139
|
|
|
|
228,961
|
|
Distributions payable
|
|
|
|
|
|
|
9,995,900
|
|
Accrued ad valorem taxes
|
|
|
378,040
|
|
|
|
499,596
|
|
Other accrued liabilities
|
|
|
377,411
|
|
|
|
233,531
|
|
Current maturities of notes payable
|
|
|
1,531,276
|
|
|
|
|
|
Oil swap agreements
|
|
|
1,580,850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
5,452,963
|
|
|
|
11,861,097
|
|
LONG-TERM LIABILITIES, less current maturities
|
|
|
|
|
|
|
|
|
Notes payable
|
|
|
25,661,011
|
|
|
|
24,000,000
|
|
Asset retirement obligation
|
|
|
2,653,676
|
|
|
|
2,240,501
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28,314,687
|
|
|
|
26,240,501
|
|
COMMITMENTS AND CONTINGENCIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PARTNERS
CAPITAL/COMMON
CONTROL OWNERS EQUITY
|
|
|
|
|
|
|
|
|
General partner capital account
|
|
|
483,527
|
|
|
|
571,419
|
|
Limited partners capital account
|
|
|
48,246,417
|
|
|
|
51,213,862
|
|
Common control owners equity
|
|
|
18,991,410
|
|
|
|
19,228,511
|
|
Accumulated other comprehensive loss
|
|
|
(209,499
|
)
|
|
|
(77,680
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
67,511,855
|
|
|
|
70,936,112
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
101,279,505
|
|
|
$
|
109,037,710
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these combined statements.
VOC F-3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
32,197,559
|
|
|
$
|
25,745,771
|
|
|
$
|
38,603,599
|
|
Other
|
|
|
|
|
|
|
4,452
|
|
|
|
31,749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32,197,559
|
|
|
|
25,750,223
|
|
|
|
38,635,348
|
|
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
7,667,332
|
|
|
|
6,787,857
|
|
|
|
7,325,042
|
|
Production and property taxes
|
|
|
2,531,660
|
|
|
|
1,646,052
|
|
|
|
2,720,313
|
|
Depreciation, depletion, amortization and accretion
|
|
|
5,780,829
|
|
|
|
5,210,212
|
|
|
|
6,252,676
|
|
Interest expense
|
|
|
1,382,725
|
|
|
|
1,500,647
|
|
|
|
1,221,373
|
|
Bad debt expense (recovery)
|
|
|
1,726,655
|
|
|
|
(719,061
|
)
|
|
|
|
|
General and administrative
|
|
|
269,139
|
|
|
|
463,295
|
|
|
|
204,575
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
19,358,340
|
|
|
|
14,889,002
|
|
|
|
17,723,979
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
$
|
12,839,219
|
|
|
$
|
10,861,221
|
|
|
$
|
20,911,369
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these combined statements.
VOC F-4
Predecessor
For
the years ended December 31, 2008, 2009 and
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Redeemed
|
|
|
New
|
|
|
Common
|
|
|
Accumulated
|
|
|
|
|
|
|
General
|
|
|
Limited
|
|
|
Limited
|
|
|
Control
|
|
|
Other
|
|
|
|
|
|
|
Partner
|
|
|
Partner
|
|
|
Partners
|
|
|
Owners
|
|
|
Comprehensive
|
|
|
|
|
|
|
Capital
|
|
|
Capital
|
|
|
Capital
|
|
|
Equity
|
|
|
Income (Loss)
|
|
|
Total
|
|
|
Balance at January 1, 2008
|
|
$
|
269,208
|
|
|
$
|
26,651,545
|
|
|
$
|
|
|
|
$
|
11,176,005
|
|
|
$
|
(9,993,411
|
)
|
|
$
|
28,103,347
|
|
Partners capital contributions
|
|
|
|
|
|
|
|
|
|
|
40,000,000
|
|
|
|
|
|
|
|
|
|
|
|
40,000,000
|
|
Partners distributions
|
|
|
(33,350
|
)
|
|
|
(73,301,650
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(73,335,000
|
)
|
Common control owners contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,128,500
|
|
|
|
|
|
|
|
5,128,500
|
|
Common control owners distributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,169,277
|
)
|
|
|
|
|
|
|
(5,169,277
|
)
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings for the year
|
|
|
100,064
|
|
|
|
4,372,524
|
|
|
|
2,073,523
|
|
|
|
6,293,108
|
|
|
|
|
|
|
|
12,839,219
|
|
Reclassification adjustment for realized losses on swap
transactions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,939,518
|
|
|
|
5,939,518
|
|
Change in fair value of swap agreements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,081,071
|
|
|
|
12,081,071
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,859,808
|
|
Step-up in
basis of leasehold costs and lease equipment equal to the
limited partners liquidating distribution in excess of the
partners capital account
|
|
|
|
|
|
|
42,277,581
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,277,581
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
335,922
|
|
|
|
|
|
|
|
42,073,523
|
|
|
|
17,428,336
|
|
|
|
8,027,178
|
|
|
|
67,864,959
|
|
Common control owners contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
400,000
|
|
|
|
|
|
|
|
400,000
|
|
Common control owners distributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,377,648
|
)
|
|
|
|
|
|
|
(3,377,648
|
)
|
Comprehensive income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings for the year
|
|
|
147,605
|
|
|
|
|
|
|
|
6,172,894
|
|
|
|
4,540,722
|
|
|
|
|
|
|
|
10,861,221
|
|
Reclassification adjustment for realized gains on swap
transactions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,347,010
|
)
|
|
|
(1,347,010
|
)
|
Change in fair value of swap agreements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,889,667
|
)
|
|
|
(6,889,667
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,624,544
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
483,527
|
|
|
|
|
|
|
|
48,246,417
|
|
|
|
18,991,410
|
|
|
|
(209,499
|
)
|
|
|
67,511,855
|
|
Partners distributions
|
|
|
(186,500
|
)
|
|
|
|
|
|
|
(9,138,500
|
)
|
|
|
|
|
|
|
|
|
|
|
(9,325,000
|
)
|
Common control owners distributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,293,931
|
)
|
|
|
|
|
|
|
(8,293,931
|
)
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings for the year
|
|
|
274,392
|
|
|
|
|
|
|
|
12,105,945
|
|
|
|
8,531,032
|
|
|
|
|
|
|
|
20,911,369
|
|
Reclassification adjustment for realized losses on swap
transactions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,123,965
|
|
|
|
1,123,965
|
|
Change in fair value of swap agreements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(992,146
|
)
|
|
|
(992,146
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,043,188
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010
|
|
$
|
571,419
|
|
|
$
|
|
|
|
$
|
51,213,862
|
|
|
$
|
19,228,511
|
|
|
$
|
(77,680
|
)
|
|
$
|
70,936,112
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these combined statements.
VOC F-5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Cash flows from operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
$
|
12,839,219
|
|
|
$
|
10,861,221
|
|
|
$
|
20,911,369
|
|
Adjustments to reconcile net earnings to net cash provided by
operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and accretion
|
|
|
5,780,829
|
|
|
|
5,210,212
|
|
|
|
6,252,676
|
|
Amortization of deferred loan costs
|
|
|
285,154
|
|
|
|
565,909
|
|
|
|
566,202
|
|
Bad debt expense
|
|
|
1,726,655
|
|
|
|
|
|
|
|
|
|
Unrealized derivative (gain) loss
|
|
|
(3,581,995
|
)
|
|
|
333,695
|
|
|
|
(260,497
|
)
|
Settlements of asset retirement obligations
|
|
|
(25,143
|
)
|
|
|
(27,149
|
)
|
|
|
(245,649
|
)
|
Change in operating assets and liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(1,306,761
|
)
|
|
|
(1,208,820
|
)
|
|
|
(24,031
|
)
|
Settlement receivable on swap agreements
|
|
|
(513,751
|
)
|
|
|
513,751
|
|
|
|
|
|
Prepaid expenses
|
|
|
5,432
|
|
|
|
1,974
|
|
|
|
(15,799
|
)
|
Accounts payable
|
|
|
(132,958
|
)
|
|
|
(109,862
|
)
|
|
|
254,496
|
|
Accrued liabilities
|
|
|
228,828
|
|
|
|
(205,242
|
)
|
|
|
167,986
|
|
Accrued interest payable
|
|
|
382,102
|
|
|
|
(253,982
|
)
|
|
|
(83,097
|
)
|
Settlement payable on swap agreements
|
|
|
(713,268
|
)
|
|
|
106,139
|
|
|
|
122,822
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
14,974,343
|
|
|
|
15,787,846
|
|
|
|
27,646,478
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of oil and gas properties and equipment
|
|
|
(6,675,201
|
)
|
|
|
(2,151,315
|
)
|
|
|
(2,729,757
|
)
|
Well development cost
|
|
|
(1,245,986
|
)
|
|
|
(1,582,563
|
)
|
|
|
(7,229,628
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(7,921,187
|
)
|
|
|
(3,733,878
|
)
|
|
|
(9,959,385
|
)
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of notes payable
|
|
|
32,622,900
|
|
|
|
|
|
|
|
|
|
Payments on notes payable
|
|
|
(1,293,757
|
)
|
|
|
(7,824,980
|
)
|
|
|
(3,192,287
|
)
|
Payment of deferred loan costs
|
|
|
(1,958,881
|
)
|
|
|
(118
|
)
|
|
|
|
|
Payment of deferred offering costs
|
|
|
|
|
|
|
|
|
|
|
(209,272
|
)
|
Partners contributions
|
|
|
40,000,000
|
|
|
|
|
|
|
|
|
|
Partners distributions
|
|
|
(73,335,000
|
)
|
|
|
|
|
|
|
(325,000
|
)
|
Common control owners contributions
|
|
|
5,128,500
|
|
|
|
400,000
|
|
|
|
|
|
Common control owners distributions
|
|
|
(5,169,277
|
)
|
|
|
(3,377,648
|
)
|
|
|
(7,298,031
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities
|
|
|
(4,005,515
|
)
|
|
|
(10,802,746
|
)
|
|
|
(11,024,590
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
3,047,641
|
|
|
|
1,251,222
|
|
|
|
6,662,503
|
|
Cash and cash equivalents, beginning of period
|
|
|
632,979
|
|
|
|
3,680,620
|
|
|
|
4,931,842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
3,680,620
|
|
|
$
|
4,931,842
|
|
|
$
|
11,594,345
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental cash flow information
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the period for interest
|
|
$
|
715,469
|
|
|
$
|
1,188,720
|
|
|
|
738,268
|
|
Noncash investing and financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement costs and obligation recorded upon drilling of
new oil and gas wells
|
|
$
|
238,516
|
|
|
$
|
77,632
|
|
|
|
33,879
|
|
Increase (decrease) in asset retirement cost and obligation due
to changes in timing and estimated cash flows
|
|
$
|
1,067,315
|
|
|
$
|
(1,331,472
|
)
|
|
|
(553,292
|
)
|
Purchases of oil and gas properties and equipment and well
development costs included in accounts payable at year end
|
|
$
|
227,927
|
|
|
$
|
794,935
|
|
|
|
47,398
|
|
Step-up in
basis of oil and gas properties as a result of redemption of
limited partners interest
|
|
$
|
42,277,581
|
|
|
$
|
|
|
|
|
|
|
Partners and common control owners distributions
included in distributions payable at year end
|
|
$
|
|
|
|
$
|
|
|
|
$
|
9,995,900
|
|
The accompanying notes are an
integral part of these combined statements.
VOC F-6
Predecessor
For the years ended December 31, 2008, 2009 and 2010
NOTE A
SUMMARY OF ACCOUNTING POLICIES
A summary of the significant accounting policies consistently
applied in the preparation of the accompanying combined
financial statements follows.
1. Principles
of combination
In connection with the closing of the initial public offering of
trust units of VOC Energy Trust, pursuant to that certain
Contribution and Exchange Agreement dated August 30, 2010,
VOC Brazos Energy Partners, L.P. (VOC Brazos) will
acquire all of the membership interests in VOC Kansas Energy
Partners, LLC (KEP) in exchange for newly issued
limited partner interests in VOC Brazos, resulting in KEP
becoming a wholly-owned subsidiary of VOC Brazos. As certain
working interests owned by KEP (the Common Control
Properties) are deemed to be under common control with VOC
Brazos, accounting rules specify that VOC Brazos and the Common
Control Properties be combined from the earliest date they came
under common control. Per accounting guidance under FASB ASC 805
regarding business combinations, those assets and liabilities of
the Common Control Properties are to be recorded at their
historical costs in the records of KEP while those not under
common control are to be recorded at their fair values on the
date of combination.
Accordingly, these combined financial statements include the
accounts of VOC Brazos and certain oil and gas properties and
other related assets and liabilities of the Common Control
Properties for all periods presented. Together, these entities
are referred to as Predecessor.
2. History
and business activity
VOC Brazos was organized during 2003 between Vess Texas
Partners, LLC, the general partner and TIFD III-X, LLC, the
limited partner, to engage in acquisition, exploration,
development and production of oil and gas. VOC Brazos began
operations August 1, 2003 when the partners contributed
working interests in certain oil and gas properties in Texas
into the partnership as a contribution of capital.
The properties had been held in a similar partnership in which
TIFD III-X, LLC held a 99% limited partnership interest. Because
of the continuity of ownership, the properties were recorded on
the partnership books at the lesser of historical cost or fair
value. The partnership agreement of VOC Brazos provided
that 1% of the contributed properties were deemed to have been
contributed by the general partner.
Through June 27, 2008, revenues and costs of
VOC Brazos were generally allocated 99% to the limited
partner and 1% to the general partner.
On June 27, 2008, VOC Brazos entered into a master
transaction agreement to redeem all of TIFD III-X, LLCs
limited partner interest in the partnership for $70 million
which was obtained by issuance of a $30 million note
payable (See Note C) and receipt of $40 million
in capital contributions from two new limited partners, VAP-III,
LLC and Vess Texas Acquisition Group, LLC. After this
redemption, Vess Texas Partners, LLC has a 2% general partner
interest, VAP-III, LLC has a 56.53% limited partner interest and
Vess Texas Acquisition Group, LLC has a 41.47% limited partner
interest. The excess of the $70 million liquidating
distribution over TIFD III-X,
VOC F-7
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2008, 2009 and 2010
LLCs capital account or $42,277,581 was recorded as a
step-up in
basis to producing leaseholds and lease equipment.
The Common Control Properties consist of working interests in
certain oil and gas properties located in Kansas. Some of these
properties have been owned since 1979. The related assets and
liabilities include oil and gas receivables, oil swap agreements
and the related settlements receivable or payable, capitalized
loan fees, joint interest billing payables, ad valorem tax
accruals, asset retirement obligations and long-term debt
associated with the acquisition of certain oil and gas
properties. These combined financial statements do not reflect
any administrative overhead costs for the Common Control
Properties as prior to the KEP consolidation each of the 24
owners conducted its own accounting for its respective
properties and did not allocate administrative overhead costs to
the properties.
3. Oil
and gas properties
Predecessor follows the successful efforts method of accounting
for oil and gas property acquisition, exploration, development
and production activities.
Oil and gas property acquisition costs, exploration well costs
and development well costs are capitalized as incurred. Net
capitalized costs of unproven property and exploration well
costs are reclassified as proved property and well costs when
related proved reserves are found. If an exploration well is
unsuccessful in finding proved reserves, the capitalized well
costs are charged to exploration expense. Other exploration
costs, including geological and geophysical costs, and the costs
of carrying unproved property are charged to exploration expense
as incurred.
Producing leasehold costs are amortized by property using the
unit-of-production
method based upon total estimated proved reserves. Capitalized
exploration well costs and development costs and lease equipment
(plus estimated future equipment dismantlement, surface
restoration, and property abandonment costs, net of equipment
salvage values) are amortized by property using the
unit-of-production
method based on estimated proved developed reserves.
Predecessor reviews its long-lived assets, including its oil and
gas properties, for impairment whenever events or circumstances
indicate that the carrying amount of an asset may not be
recoverable. Predecessor determines whether an impairment has
occurred by estimating the undiscounted expected future net cash
flows of its oil and gas properties at a field level and
compares such cash flows to the carrying amount of the oil and
gas properties to determine if the carrying amount is
recoverable. For those oil and gas properties for which the
carrying amount exceeds the undiscounted estimated future cash
flows, an impairment is determined to exist. The carrying amount
of such properties is adjusted to their estimated net fair value
based on relevant market information or discounted cash flows.
In December 2009, Predecessor adopted new accounting guidance
for oil and gas reserve estimation and disclosure requirements.
This guidance revised the definition of proved oil and gas
reserves to require that the average,
first-day-of-the-month
price during the
12-month
period before the end of the year, rather than the year-end
price, be used when estimating whether reserve quantities are
economical to produce. The guidance also allows for the use of
reliable technology to estimate proved oil and gas reserves if
those technologies have been demonstrated to result in reliable
conclusions about reserve volumes.
VOC F-8
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2008, 2009 and 2010
Costs of retired, sold or abandoned properties that constitute a
part of an amortization base are charged or credited, net of
proceeds, to the accumulated depreciation, depletion and
amortization reserve. Gains or losses from the disposal of other
properties are recognized currently. Expenditures for
maintenance, repairs and minor renewals necessary to maintain
properties in operating condition are expensed as incurred.
Major replacements and renewals are capitalized. All properties
are stated at cost.
4. Revenue
recognition
Revenues from the sale of oil and gas production are recognized
as oil and gas is produced and sold.
5. Derivatives
Predecessor uses swap agreements to mitigate the effects of
fluctuations in the prices of crude oil. These agreements
involve the exchange of amounts based on a fluctuating oil price
for amounts based on a fixed oil price over the life of the
agreement, without an exchange of the notional amount upon which
the payments are based. The differential paid or received is
recognized as an adjustment of oil and gas revenue.
Predecessors derivatives consist entirely of oil swap
agreements, of which substantially all qualify as cash flow
hedges. As such, all of Predecessors swap agreements are
recorded on the balance sheet at fair value. For all derivatives
designated as cash flow hedges, the effective portion of the
unrealized gain or loss on the derivative instrument is recorded
as a component of accumulated other comprehensive income (loss)
and reclassified into earnings as the underlying hedged item
effects earnings. The ineffective portion of the derivative as
well as those not qualifying as cash flow hedges are recorded as
an adjustment to revenue in the statements of earnings.
6. Accounts
receivable
Predecessors trade accounts receivable from the properties
contributed at the inception of VOC Brazos are collected by a
revenue intermediary from an unrelated purchaser. The revenue
intermediary then disburses the revenue based upon the revenue
deck that they maintain. Predecessors trade accounts
receivable for the properties acquired subsequent to the
inception of VOC Brazos are remitted directly from the
purchaser. State law requires that receipts for the initial
production of oil or gas sales must be paid on or before
120 days after the end of the month of the first sale of
production from the well. Thereafter, state law requires that
crude oil sales are paid within 60 days following the
related production and receipts for natural gas sales are paid
within 90 days following the related production.
Predecessor considers the trade receivables to be fully
collectible and has historically not experienced any collection
issues, except for the trade receivable from the former revenue
intermediary/crude oil purchaser in 2008 (see Note E). If
additional amounts become uncollectible, they will be charged to
operations when that determination is made.
VOC F-9
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2008, 2009 and 2010
7. Cash
equivalents
For purposes of the statement of cash flows, Predecessor
considers all highly liquid investments purchased with an
original maturity of three months or less to be cash
equivalents. There were no cash equivalents at December 31,
2009 and 2010.
8. Deferred
loan costs
Deferred loan costs are being amortized over the term of the
related loan and are included in interest expense.
9. Deferred
offering costs
Deferred offering costs consist of legal, accounting,
engineering and other costs associated with the proposed sale of
a term net profits interest in the oil and natural gas
properties of Predecessor. If the sale is successful, these
costs will be netted against the offering proceeds. If the sale
is unsuccessful, these costs will be reclassified to operations.
10. Use
of estimates
In preparing financial statements in conformity with accounting
principles generally accepted in the United States of America
(U.S. GAAP), management is required 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 amount of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Significant estimates affecting these financial statements
include estimates for quantities of proved oil and gas reserves,
asset retirement obligations and allowance for doubtful accounts
and are subject to change.
11. Income
taxes
Federal income taxes are the liability of the individual
partners/owners; accordingly, the financial statements do not
include any provision for federal income taxes. The Texas
franchise tax is based on gross margin as defined by Texas law,
is paid by Predecessor and is recorded as a general and
administrative expense.
12. Asset
retirement obligations
Accounting guidance requires that the fair value of a liability
for an asset retirement obligation be recognized in the period
in which the liability is incurred. The liability is measured at
fair value and is adjusted to its present value in subsequent
periods as accretion expense is recorded. Such accretion expense
is included in depreciation, depletion, amortization and
accretion in the accompanying statements of earnings. The
corresponding asset retirement costs are capitalized as part of
the carrying amount of the related long-lived asset and
amortized over the assets useful life. If the fair value
of the estimated retirement obligation changes, an adjustment is
recorded for both the asset retirement obligation and the asset
retirement cost. The Predecessors asset retirement
obligations are primarily associated with the plugging and
abandoning of oil and gas properties.
VOC F-10
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2008, 2009 and 2010
The estimated plug and abandon dates change routinely based upon
additional engineering data and changes in the price of oil
impacting the date when the well is no longer economically
feasible to operate. The asset retirement obligation is measured
on an annual basis based upon the then current plug and abandon
dates of the wells using the original measurement date rates.
Asset retirement obligations on new wells drilled are calculated
on their initial measurement date based upon the then current
interest rate environment.
13. Recently
issued accounting standards
In January 2010, the FASB issued ASU
2010-04,
Accounting for Various Topics Technical
Corrections to SEC Paragraphs. ASU
2010-04
makes technical corrections to existing SEC guidance, including
the following topics: accounting for subsequent investments,
termination of an interest rate swap, issuance of financial
statements subsequent events, use of residential
method to value acquired assets other than goodwill, adjustments
in assets and liabilities for holding gains and losses, and
selections of discount rate used for measuring defined benefit
obligation. The adoption did not have a material impact on our
financial statements.
In January 2010, the FASB issued ASU
2010-06,
Improving Disclosures about Fair Value Measurements
(ASU
2010-06),
which provides amendments to ASC topic Fair Value
Measurements and Disclosures. This provides more robust
disclosures about (i) the different classes of assets and
liabilities measured at fair value, (ii) the valuation
techniques and inputs used, (iii) the activity in
Level 3 fair value measurements, and (iv) the
transfers between Levels 1, 2 and 3. ASU
2010-06 is
effective for fiscal years and interim periods beginning after
December 15, 2009. The adoption did not have a material
impact on our financial statements.
In February 2010, the FASB issued ASU
2010-09 (ASU
2010-09),
Subsequent Events (Topic 855). The amendments
remove the requirements for an SEC filer to disclose a date, in
both issued and revised financial statements, through which
subsequent events have been reviewed. Revised financial
statements include financial statements revised as a result of
either correction of an error or retrospective application of
U.S. GAAP. ASU
2010-09 is
effective for interim or annual financial periods ending after
June 15, 2010. The adoption did not have a material impact
on our financial statements.
In April 2010, the FASB issued ASU
2010-14,
Accounting for Extractive Activities
Oil & Gas. ASU
2010-14
amends
paragraph 932-10-S99-1
due to SEC Release
No. 33-8995,
Modernization of Oil and Gas Reporting. The
amendments to the guidance on oil and gas accounting are
effective August 31, 2010. The adoption did not have a
material impact on our financial statements.
On August 2, 2010, the FASB issued ASU
2010-21,
Accounting for Technical Amendments to Various SEC Rules
and Schedules Amendments to SEC
Paragraphs Pursuant to Release
No. 33-9026:
Technical Amendments to Rules, Forms, Schedules and Codification
of Financial Reporting Policies. The ASU reflects changes
made by the SEC in Final Rulemaking
Release No. 33-9026,
which was issued in April 2009 and amended SEC requirements in
Regulation S-X
and
Regulation S-K
and made changes to financial reporting requirements in response
to the FASBs issuance of SFAS No. 141(R),
Business Combinations (FASB ASC 805), and
SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements an
VOC F-11
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2008, 2009 and 2010
amendment of ARB No. 51 ( FASB ASC 810). The
adoption did not have a material impact on our financial
statements.
NOTE B
OIL AND GAS PROPERTIES
Oil and gas properties are carried at cost and consist of the
following at:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
Producing leaseholds
|
|
$
|
72,230,517
|
|
|
$
|
71,617,828
|
|
Lease equipment
|
|
|
23,820,846
|
|
|
|
26,344,965
|
|
Well development costs
|
|
|
15,120,273
|
|
|
|
21,886,062
|
|
|
|
|
|
|
|
|
|
|
|
|
|
111,171,636
|
|
|
|
119,848,855
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
22,098,350
|
|
|
|
28,174,233
|
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties
|
|
$
|
89,073,286
|
|
|
$
|
91,674,622
|
|
|
|
|
|
|
|
|
|
|
Predecessors oil and gas activities are conducted entirely
in the United States. Costs incurred in oil and gas producing
activities for the years indicated are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Property acquisition costs
|
|
$
|
6,913,717
|
|
|
$
|
2,228,947
|
|
|
$
|
2,446,059
|
|
Development costs
|
|
|
1,245,986
|
|
|
|
1,582,563
|
|
|
|
6,765,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
8,159,703
|
|
|
$
|
3,811,510
|
|
|
$
|
9,211,848
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The results of operations for oil and gas producing activities,
excluding corporate overhead and interest costs for each of the
three years ended December 31 2010 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
Revenues from oil and gas sales
|
|
$
|
32,197,559
|
|
|
$
|
25,745,771
|
|
|
$
|
38,603,599
|
|
|
|
|
|
|
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
7,667,332
|
|
|
|
6,787,857
|
|
|
|
7,325,042
|
|
|
|
|
|
|
|
|
|
Production and property taxes
|
|
|
2,531,660
|
|
|
|
1,646,052
|
|
|
|
2,720,313
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
5,780,829
|
|
|
|
5,210,212
|
|
|
|
6,252,676
|
|
|
|
|
|
|
|
|
|
Bad debt expense (recovery)
|
|
|
1,726,655
|
|
|
|
(719,061
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from oil and gas operations
|
|
$
|
14,491,083
|
|
|
$
|
12,820,711
|
|
|
$
|
22,305,568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses include those costs incurred to operate
and maintain productive wells and related equipment and include
costs such as labor, repairs and maintenance, materials,
supplies, fuel consumed and insurance.
VOC F-12
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2008, 2009 and 2010
NOTE C
NOTES PAYABLE
Notes payable consist of the following at:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
Credit facility see details below
|
|
$
|
24,000,000
|
|
|
$
|
24,000,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note payable to bank in monthly installments of $25,443
including interest at prime (prime was 3.25% at
December 31, 2009), with final payment due in May 2013,
collateralized by mortgages on oil and gas properties and
guaranteed by two members of the Common Control Properties. Note
was paid in full in November 2010
|
|
|
876,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note payable to bank in monthly installments of $23,000
including interest at prime (with a floor of 4.50% which was the
effective interest rate at December 31, 2009), with final
payment due in July 2011, collateralized by mortgages on oil and
gas properties and paid in full in August 2010
|
|
|
831,563
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note payable to bank in monthly installments of $89,329
including interest at prime (with a floor of 4.00% which was the
effective interest rate at December 31, 2009), with final
payment due August 2011, collateralized by mortgages on oil and
gas properties and paid in full in August 2010
|
|
|
1,483,760
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27,192,287
|
|
|
|
24,000,000
|
|
|
|
|
|
Less current maturities
|
|
|
1,531,276
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
25,661,011
|
|
|
$
|
24,000,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Credit
facility
On June 27, 2008, in connection with the redemption and
buy-out of the 99% limited partner, TIFD III-X, LLC, VOC Brazos
entered into a credit agreement with a bank with a maximum
commitment for Borrowing Base, Letters of Credit and Swing Line
Loans in the amount of $100,000,000. The Borrowing Base
Notes interest rate is adjusted periodically based on the
interest rate base (either Eurodollar Rate of one, two, three or
six month periods or the banks base rate) plus an
applicable margin based on a percentage of borrowing base usage.
The notes effective rate at December 31, 2009 and
2010 was 2.37875% and 2.12579%, respectively. Interest is paid
no less than quarterly depending on the interest rate base
selected. The note is collateralized by all assets of
Predecessor and matures on June 27, 2013. Below are further
details of Predecessors credit agreement with the bank.
Borrowing
Base loans:
Predecessors initial and current borrowing base is
$37 million and thereafter is determined periodically by
the lender. Predecessor pays a fee of 0.25% to 0.50% on the
unused portion of the borrowing base depending on the portion of
the borrowing base utilized by Predecessor.
VOC F-13
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2008, 2009 and 2010
Letters
of Credit:
The credit agreement with the bank provides for the issuance of
letters of credit. When the lender issues a letter of credit,
initial fees are charged and interest will be due based on the
Eurodollar rate plus an applicable margin of 1.50% to 2.25%
depending on the amount of Predecessors borrowing base
currently being used. At December 31, 2009 and 2010,
Predecessor did not have any outstanding letters of credit with
the lender.
Swing
Line Loan:
Predecessor has a revolving credit facility. This revolving
credit facility is completely discretionary by the lender. The
interest rate for swing line loans is based on the Banks
base rate. At December 31, 2009 and 2010, Predecessor did
not have an outstanding balance on the Swing Line Loan.
Predecessor is subject to certain financial covenants associated
with the borrowings including current ratio, interest coverage
ratio and maximum leverage ratio requirements. In addition,
Predecessor was required to enter into swap agreements to cover
at least 75% of the estimated annual production through 2011.
Predecessor is in compliance with the required debt covenants at
December 31, 2010.
The aggregate scheduled maturities of debt at December 31,
2010 are as follows
|
|
|
|
|
2011
|
|
$
|
|
|
2012
|
|
|
|
|
2013
|
|
|
24,000,000
|
|
|
|
|
|
|
|
|
$
|
24,000,000
|
|
|
|
|
|
|
NOTE D
FINANCIAL INSTRUMENTS
The Predecessor uses swap agreements to reduce the effects of
fluctuations in crude oil prices. At December 31, 2009 and
2010, Predecessors hedging activities included swap
agreements maturing in 2011. Under these arrangements,
Predecessor will effectively receive fixed prices for the oil
production hedged. The price source for the commodity type hedge
is the New York Mercantile Exchange for the monthly activity.
The agreements covered 279,603 barrels,
213,933 barrels and 198,571 barrels of crude oil
production in the years ended December 31, 2008, 2009 and
2010, respectively. Predecessor produced 389,268,
407,414 barrels and 494,876 barrels of crude oil in
2008, 2009 and 2010, respectively (unaudited).
Gains and losses on the hedging transactions are recognized when
the hedged production is sold. Net expense recorded by
Predecessor for swap agreements was $8,118,212 for the year
ended December 31, 2008, and net revenue recorded by
Predecessor for swap agreements was $1,477,248 for the year
ended December 31, 2009. Net expense recorded by
Predecessor for swap agreements was $967,869 for the year ended
December 31, 2010. Such amounts have been reflected as an
adjustment to oil and gas sales in the statements of earnings.
VOC F-14
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2008, 2009 and 2010
For those oil swap agreements that do not qualify as cash flow
hedges, Predecessor has also recorded the changes to fair value
as adjustments to oil and gas sales in the statement of earnings
as income of $333,695 for the year ended December 31, 2008.
The notional volume and fair market value of outstanding swap
agreements at December 31, 2009 and 2010 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
Year
|
|
|
Notional Volume
|
|
Fixed Price
|
|
|
Fair Value
|
|
|
|
|
|
|
|
2010
|
|
|
174,571 bbls
|
|
|
73.06
|
|
|
$
|
(1,580,850
|
)
|
|
|
|
|
|
2011
|
|
|
159,894 bbls
|
|
|
94.90
|
|
|
|
1,371,351
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(209,499
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
Year
|
|
|
Notional Volume
|
|
Fixed Price
|
|
|
Fair Value
|
|
|
|
|
|
|
|
2011
|
|
|
159,894 bbls
|
|
|
94.90
|
|
|
$
|
182,817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessors swap agreements expose it to market and
credit risks that may, at times, be concentrated with certain
counterparties or groups of counterparties. At December 31,
2010, Predecessors financial instruments were with one
major financial institution whose credit worthiness is subject
to continuing review, however, full performance is anticipated.
The estimated amount of unrealized loss relating to hedge
agreements at December 31, 2010 expected to be reclassified
into earnings in the next 12 months is $77,681. See
Note A5 for more discussion on derivatives.
NOTE E
RELATED PARTIES
Vess Texas Partners, LLC, the general partner of Predecessor,
has common ownership with Vess Oil Corporation. Vess Oil
Corporation serves as the primary operator of the oil and gas
wells of the Partnership. In addition, the primary owner of the
primary operator has a minority investment interest in the
parent of the revenue intermediary prior to July 22, 2008.
As a result of the bankruptcy discussed below, Vess Oil
Corporation became the new revenue intermediary on July 22,
2008.
VOC F-15
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2008, 2009 and 2010
Below is a summary of transactions that occurred between
Predecessor, its general partner, operator and revenue
intermediary:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
With operator/new revenue intermediary
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense incurred
|
|
$
|
6,705,544
|
|
|
$
|
5,770,203
|
|
|
$
|
6,066,454
|
|
Overhead costs included in lease operating expense
|
|
$
|
466,796
|
|
|
$
|
548,873
|
|
|
$
|
586,776
|
|
Reimbursement of overhead costs*
|
|
$
|
(355,235
|
)
|
|
$
|
(353,020
|
)
|
|
$
|
(345,485
|
)
|
Capitalized lease equipment and producing leaseholds costs
incurred
|
|
$
|
794,822
|
|
|
$
|
1,394,856
|
|
|
$
|
2,591,138
|
|
Payment of well development costs
|
|
$
|
1,004,078
|
|
|
$
|
1,953,828
|
|
|
$
|
6,765,790
|
|
Revenue receipts
|
|
$
|
7,447,596
|
|
|
$
|
8,151,559
|
|
|
$
|
18,087,204
|
|
With General Partner
|
|
|
|
|
|
|
|
|
|
|
|
|
Overhead costs incurred*
|
|
$
|
447,000
|
|
|
$
|
447,000
|
|
|
$
|
447,000
|
|
With former revenue intermediary
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue receipts
|
|
$
|
5,963,891
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
* |
|
Upon dissolution of the former partnership (see Note A2),
an agreement was reached between the former partners and
operator with Predecessor and new operator. The agreement
provided that the existing overhead agreement would continue to
apply to all working interest owners other than Predecessor.
Predecessor negotiated a new overhead arrangement with lower
rates with the new operator, which includes a reimbursement to
Predecessor for overhead amounts paid by the other working
interest owners. The overhead charges, net of the reimbursement
for the amounts paid by the other working interest owners, is
included in operating expenses in the statements of earnings. |
Following is a summary of balances due to/from related parties:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
|
|
|
|
|
|
|
Operator
|
|
|
Purchasers
|
|
|
Total
|
|
|
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
$
|
2,167,284
|
|
|
$
|
2,462,780
|
|
|
$
|
4,630,064
|
|
Accounts payable
|
|
$
|
1,285,891
|
|
|
$
|
|
|
|
$
|
1,285,891
|
|
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
$
|
2,878,164
|
|
|
$
|
766,963
|
|
|
$
|
3,645,127
|
|
Accounts payable
|
|
$
|
770,513
|
|
|
$
|
|
|
|
$
|
770,513
|
|
As publicly reported on July 22, 2008, the former revenue
intermediary/crude oil purchaser (Eaglwing L.P.) and its parent
(SemGroup, L.P.) filed voluntary petitions for reorganization
under Chapter 11 of the United States Bankruptcy Code.
During this process, the monies that had been transferred to the
revenue intermediary by certain of Predecessors oil and
gas purchasers for distribution to Predecessor and other working
interest, royalty interest and overriding royalty interest
owners was erroneously retained by the former revenue
intermediary. Vess Oil Corporation, as primary operator of
Predecessors oil and gas leases, filed suit to recover
these funds which were estimated to be $1,438,121 for
Predecessors ownership. In addition, Vess Oil Corporation
filed a proof of claim for a statutory lien claim with the
bankruptcy court on behalf of the working interest owners
(inclusive of Predecessor interests), overriding royalty owners
and royalty owners. In 2008, as there was no assurance as to the
dollar amount, if any, that would be
VOC F-16
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2008, 2009 and 2010
recovered or the timing of such recovery, an allowance for
doubtful accounts of $719,061 or 50% of the total estimated
amount owed from Eaglwing, L.P. to Predecessor was established
as of December 31, 2008. In addition, an allowance was set
up for the oil purchased from the Common Control Properties in
the amount of $1,007,594 which represents approximately 87% of
June 2008 sales made to Eaglwing, L.P.
In 2009, Predecessor was successful in its suit and received
$1,430,660 which resulted in a bad debt recovery of $719,061 as
reflected in the 2009 statement of earnings. In regards to
oil sales made to Eaglwing, L.P., Predecessor received 100% of
the sales made to Eaglwing, L.P. from July 2, 2008 through
July 22, 2008 in April 2010 and approximately 13% of the
sales made to Eaglwing from June 1, 2008 through
July 1, 2008 in October 2010.
A summary of sales and trade receivables with MV Purchasing,
LLC, an affiliate of VOC Sponsor, follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Sales
|
|
$
|
646,957
|
|
|
$
|
5,993,119
|
|
|
$
|
8,526,840
|
|
Trade Receivables
|
|
$
|
180,841
|
|
|
$
|
610,191
|
|
|
$
|
766,963
|
|
MV Purchasing began operations on August 1, 2008.
NOTE F
CONCENTRATION OF CREDIT RISK
Financial instruments, which potentially subject Predecessor to
credit risk, consist primarily of cash, cash equivalents, trade
receivables and swap agreements.
Predecessor maintains cash and cash equivalents with two
financial institutions. At times, such deposit amounts may
exceed the limits insured by the Federal Deposit Insurance
Corporation. Predecessor places its cash and cash equivalents
with high credit quality financial institutions and believes
that no significant concentration of credit risk exists with
respect to these cash investments.
Sales and trade receivables subject Predecessor to the potential
for credit risk with customers. Approximately 80% and 76% of
Predecessors trade receivables balance at
December 31, 2009 and 2010, respectively, was represented
by three and one customers and the revenue intermediaries,
respectively. Approximately 81%, 74% and 80% of sales for the
years ended December 31, 2008, 2009 and 2010, respectively,
were made to four, three and three customers respectively.
Management continually evaluates the credit worthiness of the
customers and believes net amount recorded will be received.
Predecessor has entered into certain swap agreements as
discussed in Note D.
VOC F-17
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2008, 2009 and 2010
NOTE G
ASSET RETIREMENT OBLIGATIONS
The Predecessors asset retirement obligations are
primarily associated with the plugging and abandoning of oil and
gas properties. The activity in the asset retirement obligation
during each of the three years ended December 31, 2010 is as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations beginning of year
|
|
$
|
2,641,033
|
|
|
$
|
4,075,952
|
|
|
$
|
3,019,115
|
|
Liabilities incurred during the year
|
|
|
238,516
|
|
|
|
77,632
|
|
|
|
33,879
|
|
Liabilities settled during the year
|
|
|
(25,143
|
)
|
|
|
(27,149
|
)
|
|
|
(245,649
|
)
|
Accretion expense
|
|
|
154,231
|
|
|
|
224,152
|
|
|
|
161,577
|
|
Increase (decrease) in asset retirement obligations due to
changes in timing and changes in estimated cash flows
|
|
|
1,067,315
|
|
|
|
(1,331,472
|
)
|
|
|
(553,292
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations end of year
|
|
|
4,075,952
|
|
|
|
3,019,115
|
|
|
|
2,415,630
|
|
Less current portion included in other accrued liabilities
|
|
|
272,037
|
|
|
|
365,439
|
|
|
|
175,129
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term portion
|
|
$
|
3,803,915
|
|
|
$
|
2,653,676
|
|
|
$
|
2,240,501
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE H
FAIR VALUE MEASUREMENTS
Effective January 1, 2008, the Predecessor adopted new
accounting guidance for its financial assets and liabilities
measured at fair value on a recurring basis. This guidance
establishes a framework for measuring fair value of assets and
liabilities and expands disclosures about fair value
measurements. It defines fair value as the amount that would be
received from the sale of an asset or paid for the transfer of a
liability in an orderly transaction between market participants,
i.e., an exit price. To estimate an exit price, a three-level
hierarchy is used. The fair value hierarchy prioritizes the
inputs, which refer broadly to assumptions market participants
would use in pricing an asset or a liability, into three levels.
Level 1 inputs are unadjusted quoted prices in active
markets for identical assets and liabilities and have the
highest priority. Level 2 inputs are inputs other than
quoted prices within Level 1 that are observable for the
asset or liability, either directly or indirectly. Level 3
inputs are unobservable inputs for the financial asset or
liability and have the lowest priority.
The carrying amount reported in the combined balance sheets for
cash and cash equivalents, accounts receivable and accounts
payable, accrued expenses and settlements receivable and payable
on oil swap agreements approximates fair value because of the
immediate or short-term maturity of these financial instruments.
The carrying amount reported in the combined balance sheets for
notes payable approximates fair value because the actual
interest rates do not significantly differ from current rates
offered for instruments with similar characteristics.
VOC F-18
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2008, 2009 and 2010
The following table provides fair value measurement information
for financial assets and liabilities measured at fair value on a
recurring basis as of December 31, 2009 and 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted Prices in
|
|
Significant Other
|
|
Unobservable
|
|
|
Active Markets
|
|
Observable Inputs
|
|
Inputs
|
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
Financial assets (liabilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 Hedge agreements, net
|
|
$
|
|
|
|
$
|
(209,499
|
)
|
|
$
|
|
|
2010 Hedge agreements, net
|
|
$
|
|
|
|
$
|
182,817
|
|
|
$
|
|
|
2009 asset retirement obligations incurred
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(77,632
|
)
|
2010 asset retirement obligations incurred
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(33,879
|
)
|
Level 1
Fair Value Measurements
None.
Level 2
Fair Value Measurements
Hedge agreements The fair value of hedge
agreements has been established utilizing established index
prices, oil future price curves and discount factors. These
estimates are compared to the counterparty values for
reasonableness. The hedge agreements are also subject to the
risk that the counterparty will be unable to meet its
obligations. Such non-performance risk is considered in the
valuation of the hedge agreements, but has not had a material
impact on the values of our hedge agreements.
Level 3
Fair Value Measurements
The initial measurement of asset retirement obligations
fair value is calculated using discounted cash flow techniques
and is based on internal estimates of future retirement costs
associated with oil and gas properties. Given the unobservable
nature of the inputs, including plugging costs and reserve
lives, the initial measurement of the ARO liability is deemed to
use Level 3 inputs. See Notes A12 and G for further
discussion.
NOTE I
COMMITMENTS AND CONTINGENCIES
The Predecessor is involved in legal actions and claims arising
in the ordinary course of business. After discussion with
counsel representing the Predecessor, it is the opinion of
management that these matters will not have a material adverse
effect on the Predecessors financial statements.
NOTE J
SUBSEQUENT EVENTS
Management has reviewed activity from December 31, 2010
through March 22, 2011 which is considered to be the date
through which these financial statements are available to be
issued for events requiring recognition or disclosure.
In 2011, Predecessor has entered into two drilling
authorizations for expenditures totaling $2,170,776.
VOC F-19
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2008, 2009 and 2010
On February 24, 2011 and on March 16, 2011, the
predecessor entered into additional oil swap agreements maturing
through 2013 with the same counterparty and similar terms as
discussed in Note D. The notional volumes and fixed prices
are as follows:
|
|
|
|
|
Year
|
|
Notional Volume
|
|
Fixed Price
|
|
2011
|
|
155,634 Bbls
|
|
$100.25 - $100.70
|
2012
|
|
315,889 Bbls
|
|
$ 99.10 - $100.00
|
2013
|
|
284,485 Bbls
|
|
$ 97.30 - $ 98.45
|
NOTE K
DISCLOSURES ABOUT OIL AND GAS ACTIVITIES
(UNAUDITED)
In December 2009, Predecessor adopted revised oil and gas
reserve estimation and disclosure requirements. The primary
impact of the new disclosures is to conform the definition of
proved reserves to the SEC Modernization of Oil and Gas
Reporting rules, which were issued by the SEC at the end of
2008. The new rules revised the definition of proved oil and gas
reserves to require that the average,
first-day-of-the-month
price during the
12-month
period before the end of the year, rather than the year-end
price, be used when estimating whether reserve quantities are
economical to produce. This same
12-month
average price is also used in calculating the aggregate amount
of (and changes in) future cash inflows related to the
standardized measure of discounted future net cash flows. The
rules also allow for the use of reliable technology to estimate
proved oil and gas reserves if those technologies have been
demonstrated to result in reliable conclusions about reserve
volumes. The unaudited supplemental information on oil and gas
exploration and production activities for 2009 and 2010 has been
presented in accordance with the new reserve estimation and
disclosure rules, which may not be applied retrospectively. The
2007 and 2008 data are presented in accordance with SEC oil and
gas disclosure requirements effective during those periods.
Estimates of the proved oil and gas reserves attributable to the
Predecessor as of December 31, 2007, 2008, 2009 and 2010
are based on reports of Cawley, Gillespie &
Associates, Inc., independent petroleum and geological
engineers, and the contract property management engineering
staff of Predecessor who operate the underlying properties, in
accordance with the provisions of SEC rules and regulations.
Users of this information should be aware that the process of
estimating quantities of proved and proved
developed and proved undeveloped crude oil and
natural gas reserves is very complex, requiring significant
subjective decisions in the evaluation of all available
geological, engineering and economic data for each reservoir.
The data for a given reservoir may also change substantially
over time as a result of numerous factors, including additional
development activity, evolving production history and continual
reassessment of the viability of production under varying
economic conditions. Consequently, material revisions to
existing reserve estimates occur from time to time.
The reserve data below represent estimates only and should not
be construed as being exact. Moreover, the discounted values
should not be construed as representative of the current market
value of the oil and gas properties. A market value
determination would include many additional factors including:
(i) anticipated future oil and gas prices; (ii) the
effect of federal income taxes, if any, on Predecessor;
(iii) an allowance for return on investment; (iv) the
effect of governmental legislation; (v) the value of
additional potential reserves, not considered proved at present,
which
VOC F-20
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2008, 2009 and 2010
may be recovered as a result of further exploration and
development activities; and (vi) other business risks.
The following tables set forth (i) the estimated net
quantities of proved, proved developed and proved undeveloped
oil and natural gas reserves attributable to the oil and gas
properties, and (ii) the standardized measure of the
discounted future Net Profits Interest income attributable to
the oil and gas properties and the nature of changes in such
standardized measure between years. These tables are prepared on
the accrual basis, which is the basis on which Predecessor
maintains its production records.
ESTIMATED
QUANTITIES OF OIL AND GAS RESERVES
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
(Bbls)
|
|
|
(Mcf)
|
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
7,454,506
|
|
|
|
4,374,316
|
|
Revisions of previous estimates
|
|
|
(790,795
|
)
|
|
|
(101,844
|
)
|
Purchase of minerals in place
|
|
|
221,536
|
|
|
|
377,887
|
|
Extensions and discoveries
|
|
|
170
|
|
|
|
|
|
Production
|
|
|
(389,268
|
)
|
|
|
(426,326
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
6,496,149
|
|
|
|
4,224,033
|
|
Revisions of previous estimates
|
|
|
1,790,387
|
|
|
|
634,099
|
|
Purchase of minerals in place
|
|
|
63,928
|
|
|
|
59,689
|
|
Extensions and discoveries
|
|
|
149,533
|
|
|
|
|
|
Production
|
|
|
(407,415
|
)
|
|
|
(414,730
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
8,092,582
|
|
|
|
4,503,091
|
|
Revisions of previous estimates
|
|
|
659,977
|
|
|
|
1,041,826
|
|
Production
|
|
|
(494,876
|
)
|
|
|
(446,979
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010
|
|
|
8,257,683
|
|
|
|
5,097,938
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
6,877,406
|
|
|
|
4,116,158
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
5,770,190
|
|
|
|
3,928,995
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
6,729,632
|
|
|
|
3,854,008
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
6,799,873
|
|
|
|
3,992,358
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
577,100
|
|
|
|
258,158
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
725,959
|
|
|
|
295,038
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
1,362,950
|
|
|
|
649,083
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
1,457,810
|
|
|
|
1,105,580
|
|
|
|
|
|
|
|
|
|
|
VOC F-21
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2008, 2009 and 2010
STANDARDIZED
MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
FROM PROVED OIL AND GAS RESERVES
Future oil and natural gas sales and production and development
costs have been estimated in accordance with the SEC
Modernization of Oil and Gas Reporting Rules for 2009 and 2010.
The standardized measure of discounted future net cash flows
(the Standardized Measure) represents the present
value of estimated future cash inflows from proved oil and
natural gas reserves, less future development, production and
plugging and abandonment costs, discounted at 10% per annum to
reflect timing of future cash flows. Production costs do not
include depreciation, depletion and amortization of capitalized
acquisition, exploration and development costs. Because
Predecessor bears no federal income tax expense and taxable
income is passed through to the partners of Predecessor, no
provision for federal or state income taxes is included in the
reserve report or in the calculation of the Standardized Measure.
Estimated proved reserves and related future net revenues and
Standardized Measure were determined using index prices for oil
and natural gas, without giving effect to derivative
transactions, and were held constant throughout the life of the
properties. The index prices were $44.60 per barrel for oil and
$5.62 per MMBtu for natural gas at December 31, 2008, and
the unweighted arithmetic average first-day of-the-month prices
for the prior 12 months were $61.18 per barrel for oil and
$3.83 per MMBtu for natural gas at December 31, 2009 and
$79.43 per barrel for oil and $4.37 per MMBtu for
natural gas at December 31, 2010. For purposes of comparing
natural gas prices per MMBtu and per Mcf, adjustments have been
made to reflect Btu content, shrink and compression and handling
charges as realized on an individual lease basis. The relevant
average realized prices, adjusting in the case of crude oil for
forecasted gravity, quality, transportation and marketing as
well as other factors affecting the price received at the
wellhead, were $39.49 per barrel for oil and $5.61 per Mcf for
natural gas at December 31, 2008, $55.82 per barrel for oil
and $4.58 per Mcf for natural gas at December 31, 2009 and
$74.22 per barrel for oil and $5.02 per Mcf for natural gas at
December 31, 2010. The impact of the adoption of the
authoritative guidance of the Financial Accounting Standard
Board (the FASB) on the SEC oil and gas reserve
estimation final rule on our financial statements is not
practicable to estimate due to the operation and technical
challenges associated with calculating a cumulative effect of
adoption by preparing reserve reports under both the old and new
rules.
Changes in the demand for oil and natural gas, inflation, and
other factors made such estimates inherently imprecise and
subject to substantial revision. This table should not be
construed to be an estimate of current market value of the
proved reserves attributable to Predecessors reserves.
VOC F-22
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2008, 2009 and 2010
The estimated Standardized Measure relating to
Predecessors proved reserves at December 31, 2008,
2009 and 2010 is shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Future cash inflows
|
|
$
|
285,599,020
|
|
|
$
|
479,804,227
|
|
|
$
|
648,185,108
|
|
Future costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(152,898,120
|
)
|
|
|
(192,121,342
|
)
|
|
|
(223,916,334
|
)
|
Development
|
|
|
(12,501,184
|
)
|
|
|
(25,183,887
|
)
|
|
|
(25,384,253
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
120,199,716
|
|
|
|
262,498,998
|
|
|
|
398,884,521
|
|
Less 10% discount factor
|
|
|
(60,259,262
|
)
|
|
|
(142,117,093
|
)
|
|
|
(218,408,117
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
59,940,454
|
|
|
$
|
120,381,905
|
|
|
$
|
180,476,404
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth the changes in the Standardized
Measure applicable to Predecessors proved oil and natural
gas reserves for the years ended December 31, 2008, 2009
and 2010:
CHANGES
IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED OIL AND GAS RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Standardized measure at beginning of year
|
|
$
|
206,509,831
|
|
|
$
|
59,940,454
|
|
|
$
|
120,381,905
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(29,744,163
|
)
|
|
|
(15,788,110
|
)
|
|
|
(29,265,616
|
)
|
Net changes in price and production costs
|
|
|
(154,951,804
|
)
|
|
|
41,451,566
|
|
|
|
52,703,598
|
|
Extensions, discoveries and improved recovery, net of future
production and development costs
|
|
|
5,822
|
|
|
|
5,890,961
|
|
|
|
|
|
Changes in estimated future development costs
|
|
|
(2,726,749
|
)
|
|
|
(14,381,027
|
)
|
|
|
(14,568,030
|
)
|
Development costs incurred during the period which reduce future
development costs
|
|
|
52,800
|
|
|
|
2,700,100
|
|
|
|
7,599,939
|
|
Revisions of quantity estimates
|
|
|
(7,982,910
|
)
|
|
|
29,413,203
|
|
|
|
15,664,245
|
|
Accretion of discount
|
|
|
20,650,983
|
|
|
|
5,994,045
|
|
|
|
12,038,190
|
|
Purchase of reserves in place
|
|
|
4,831,610
|
|
|
|
1,567,625
|
|
|
|
|
|
Change in production rates, timing and other
|
|
|
23,295,034
|
|
|
|
3,593,088
|
|
|
|
15,922,173
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure at end of year
|
|
$
|
59,940,454
|
|
|
$
|
120,381,905
|
|
|
$
|
180,476,404
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
VOC F-23
Predecessor
The following unaudited pro forma financial statements have been
prepared to illustrate the acquisition of the Acquired
Properties and the conveyance of a Net Profits Interest in all
the Underlying Properties by VOC Sponsor to the Trust and
distribution by VOC Sponsor to its limited partners of the net
proceeds of this offering including the sale of trust units to
VOC Partners, LLC, an affiliate of VOC Sponsor, 45 days
after the closing of this offering. The unaudited pro forma
balance sheet is presented as of December 31, 2010, giving
effect to the acquisition of the Acquired Properties, the
issuance of 16,540,000 trust units at an assumed initial
offering price of $20.00 per unit, the Net Profits Interest
conveyance and the payment of VOC Sponsors distribution by
VOC Sponsor to its limited partners of the net proceeds of this
offering as if they occurred on December 31, 2010. The
unaudited pro forma statement of earnings present the historical
statements of earnings of VOC Sponsor for the year ended
December 31, 2010, giving effect to the acquisition of the
Acquired Properties and to the Net Profits Interest conveyance
and the distribution by VOC Sponsor to its limited partners as
if they occurred as of January 1, 2010 reflecting only pro
forma adjustments expected to have a continuing impact on the
combined results.
These unaudited pro forma financial statements are for
informational purposes only. They do not purport to present the
results that would have actually occurred had the unit offering,
Net Profits Interest conveyance and the distribution by VOC
Sponsor to its limited partners of the net proceeds of this
offering been completed on the assumed dates or for the periods
presented. Moreover, they do not purport to project VOC
Sponsors financial position or results of operations for
any future date or period.
To produce the pro forma financial information, management made
certain estimates. These estimates are based on the most
recently available information. To the extent there are
significant changes in these amounts, the assumptions and
estimates herein could change significantly. The unaudited pro
forma financial statements should be read in conjunction with
the accompanying notes to such unaudited pro forma financial
statements, Managements Discussion and Analysis of
Financial Condition and Results of Operations of VOC
Sponsor and the audited historical financial statements of
Predecessor included in this prospectus and elsewhere in the
registration statement.
VOC F-24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
Pro Forma
|
|
|
|
Historical
|
|
|
Adjustments (a)
|
|
|
Pro Forma
|
|
|
Adjustments
|
|
|
as Adjusted
|
|
|
Cash and cash equivalents
|
|
$
|
11,594,345
|
|
|
$
|
|
|
|
$
|
11,594,345
|
|
|
$
|
|
(b)
|
|
$
|
11,594,345
|
|
Accounts receivable oil and gas sales
|
|
|
1,091,745
|
|
|
|
1,198,682
|
|
|
|
2,290,427
|
|
|
|
|
|
|
|
2,290,427
|
|
Accounts receivable oil and gas sales
related parties
|
|
|
3,645,127
|
|
|
|
993,178
|
|
|
|
4,638,305
|
|
|
|
|
|
|
|
4,638,305
|
|
Receivable from Trust
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
349,674
|
(d)
|
|
|
349,674
|
|
Note receivable related parties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38,786,916
|
(c)
|
|
|
38,786,916
|
|
Oil Swap agreements
|
|
|
182,817
|
|
|
|
|
|
|
|
182,817
|
|
|
|
|
|
|
|
182,817
|
|
Prepaid expenses
|
|
|
84,627
|
|
|
|
|
|
|
|
84,627
|
|
|
|
|
|
|
|
84,627
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
16,598,661
|
|
|
|
2,191,860
|
|
|
|
18,790,521
|
|
|
|
39,136,590
|
|
|
|
57,927,111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OIL AND GAS PROPERTIES
|
|
|
119,848,855
|
|
|
|
90,941,091
|
|
|
|
210,789,946
|
|
|
|
(168,631,957
|
)(d)
|
|
|
42,157,989
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
28,174,233
|
|
|
|
|
|
|
|
28,174,233
|
|
|
|
(22,539,386
|
) (d)
|
|
|
5,634,847
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91,674,622
|
|
|
|
90,941,091
|
|
|
|
182,615,713
|
|
|
|
(146,092,571
|
) (d)
|
|
|
36,523,142
|
|
OTHER ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivable from Trust
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,352,490
|
(d)
|
|
|
1,352,490
|
|
Deferred loan costs, net of accumulated amortization of
$1,403,726
|
|
|
555,155
|
|
|
|
|
|
|
|
555,155
|
|
|
|
|
|
|
|
555,155
|
|
Deferred offering costs
|
|
|
209,272
|
|
|
|
|
|
|
|
209,272
|
|
|
|
(209,272
|
) (e)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
764,427
|
|
|
|
|
|
|
|
764,427
|
|
|
|
1,143,218
|
|
|
|
1,907,645
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
109,037,710
|
|
|
$
|
93,132,951
|
|
|
$
|
202,170,661
|
|
|
$
|
(105,812,763
|
)
|
|
$
|
96,357,898
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL/COMMON CONTROL
OWNERS EQUITY (DEFICIT)
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
68,854
|
|
|
$
|
15,798
|
|
|
$
|
84,652
|
|
|
$
|
|
|
|
$
|
84,652
|
|
Related parties
|
|
|
770,513
|
|
|
|
626,830
|
|
|
|
1,397,343
|
|
|
|
|
|
|
|
1,397,343
|
|
Accrued interest
|
|
|
63,742
|
|
|
|
|
|
|
|
63,742
|
|
|
|
|
|
|
|
63,742
|
|
Settlement payable on oil swap agreements
|
|
|
228,961
|
|
|
|
|
|
|
|
228,961
|
|
|
|
|
|
|
|
228,961
|
|
Distributions payable
|
|
|
9,995,900
|
|
|
|
1,549,232
|
|
|
|
11,545,132
|
|
|
|
|
|
|
|
11,545,132
|
|
Accrued ad valorem taxes
|
|
|
499,596
|
|
|
|
491,392
|
|
|
|
990,988
|
|
|
|
|
|
|
|
990,988
|
|
Other accrued liabilities
|
|
|
233,531
|
|
|
|
261,964
|
|
|
|
495,495
|
|
|
|
|
|
|
|
495,495
|
|
Due to Trust
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
146,254
|
(d)
|
|
|
146,254
|
|
Deferred gain on sale
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,759,435
|
(e)
|
|
|
8,759,435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
11,861,097
|
|
|
|
2,945,216
|
|
|
|
14,806,313
|
|
|
|
8,905,689
|
|
|
|
23,712,002
|
|
LONG-TERM LIABILITIES, less current maturities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes payable
|
|
|
24,000,000
|
|
|
|
|
|
|
|
24,000,000
|
|
|
|
(24,000,000
|
) (b)
|
|
|
|
|
Deferred gain on sale
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
95,586,548
|
(e)
|
|
|
95,586,548
|
|
Asset retirement obligation
|
|
|
2,240,501
|
|
|
|
1,564,872
|
|
|
|
3,805,373
|
|
|
|
|
|
|
|
3,805,373
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,240,501
|
|
|
|
1,564,872
|
|
|
|
27,805,373
|
|
|
|
71,586,548
|
|
|
|
99,391,921
|
|
PARTNERS CAPITAL/COMMON CONTROL OWNERS EQUITY
(DEFICIT)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner capital account
|
|
|
571,419
|
|
|
|
|
|
|
|
571,419
|
|
|
|
(1,483,360
|
)(f)
|
|
|
(911,941
|
)
|
Limited partner capital account
|
|
|
51,213,862
|
|
|
|
|
|
|
|
51,213,862
|
|
|
|
(72,695,279
|
) (g)
|
|
|
(21,481,417
|
)
|
Common control owners equity
|
|
|
19,228,511
|
|
|
|
88,622,863
|
|
|
|
107,851,374
|
|
|
|
(112,126,361
|
) (h)
|
|
|
(4,274,987
|
)
|
Accumulated other comprehensive loss
|
|
|
(77,680
|
)
|
|
|
|
|
|
|
(77,680
|
)
|
|
|
|
|
|
|
(77,680
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
70,936,112
|
|
|
|
88,622,863
|
|
|
|
159,558,975
|
|
|
|
(186,305,000
|
)
|
|
|
(26,746,025
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
109,037,710
|
|
|
$
|
93,132,951
|
|
|
$
|
202,170,661
|
|
|
$
|
(105,812,763
|
)
|
|
$
|
96,357,898
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these unaudited pro forma financial statements.
VOC F-25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro
|
|
|
|
|
|
|
(a)
|
|
|
Pro
|
|
|
Additional
|
|
|
Forma as
|
|
|
|
Historical
|
|
|
Adjustments
|
|
|
Forma
|
|
|
Adjustments
|
|
|
Adjusted
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
38,603,599
|
|
|
$
|
24,114,838
|
|
|
$
|
62,718,437
|
|
|
$
|
(50,174,750
|
)(i)
|
|
$
|
12,543,687
|
|
Gain on sale of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,423,003
|
(j)
|
|
|
9,423,003
|
|
Other
|
|
|
31,749
|
|
|
|
|
|
|
|
31,749
|
|
|
|
|
|
|
|
31,749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38,635,348
|
|
|
|
24,114,838
|
|
|
|
62,750,186
|
|
|
|
(40,751,747
|
)
|
|
|
21,998,439
|
|
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
7,325,042
|
|
|
|
6,401,986
|
|
|
|
13,727,028
|
|
|
|
(10,981,622
|
)(k)
|
|
|
2,745,406
|
|
Production and property taxes
|
|
|
2,720,313
|
|
|
|
1,416,534
|
|
|
|
4,136,847
|
|
|
|
(3,309,478
|
)(l)
|
|
|
827,369
|
|
Depreciation, depletion, amortization and accretion
|
|
|
6,252,676
|
|
|
|
6,583,585
|
|
|
|
12,836,261
|
|
|
|
(9,856,928
|
)(m)
|
|
|
2,979,333
|
|
Interest expense
|
|
|
1,221,373
|
|
|
|
|
|
|
|
1,221,373
|
|
|
|
|
|
|
|
1,221,373
|
|
General and administrative
|
|
|
204,575
|
|
|
|
|
|
|
|
204,575
|
|
|
|
|
|
|
|
204,575
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
17,723,979
|
|
|
|
14,402,105
|
|
|
|
32,126,084
|
|
|
|
(24,148,028
|
)
|
|
|
7,978,056
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
$
|
20,911,369
|
|
|
$
|
9,712,733
|
|
|
$
|
30,624,102
|
|
|
$
|
(16,603,719
|
)
|
|
$
|
14,020,383
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these unaudited pro forma financial statements.
VOC F-26
Predecessor
NOTE A
BASIS OF PRESENTATION
VOC Sponsor will convey the Net Profits Interest in oil and
natural gas producing properties located in the States of Kansas
and Texas to the VOC Energy Trust (the Trust). The
Net Profits Interest entitles the Trust to receive 80% of the
net proceeds attributable to VOC Sponsors interest from
the sale of production from the underlying properties. The Net
Profits Interest will terminate and the underlying properties
will revert back to VOC Sponsor on the later to occur of
(1) December 31, 2030, or (2) the time from and
after January 1, 2011 when 10.6 MMBoe have been
produced from the underlying properties and sold.
The net proceeds of the offering will be used to (i) repay
approximately $24.0 million of outstanding borrowings under
its credit facility and (ii) distribute $187.1 million to
the partners of VOC Sponsor.
The unaudited pro forma balance sheet assumes the issuance of
16,540,000 trust units at $20.00 per unit and estimated
direct transaction costs to be incurred by VOC Sponsor of
approximately $17.1 million (comprised of underwriter,
legal, accounting and other fees). As of December 31, 2010,
VOC Sponsor had incurred $1.0 million of these direct
transaction costs.
VOC Sponsor will sell 10,785,000 of the trust units to the
public for cash of $215.7 million and recognize a deferred
gain of $107.9 million. The deferred gain will be
recognized in income over the life of the Net Profits Interest
based on production. Forty-five days after the closing of this
offering, VOC Sponsor will also sell 5,755,000 of the trust
units to VOC Partners, LLC, an affiliate of VOC Sponsor, in
exchange for $11.5 million in cash and notes receivable for
$38.8 million in the aggregate. The notes will be paid off
in forty (40) quarterly payments beginning July 2011,
including interest at 5.0%. The notes will be collateralized by
each partners ownership interest in VOC Partners. In
accordance with accounting rules for transactions among related
parties, the notes receivable were recorded at the historical
carrying value of the trust units sold to the members and no
gain on sale has been reflected. The excess of payments over the
historical carrying value will be recorded as capital
contributions by the members.
VOC Sponsor has entered into hedge arrangements with
institutional third parties with respect to the volumes of oil
production for the periods covered by these pro forma statements
and the years following until 2013 such that VOC Sponsor would
be entitled to receive payments from the counterparties in the
event that reference prices for oil contracts traded on NYMEX
for the periods covered are less than the fixed prices specified
for the hedge and other derivatives. VOC Sponsor will also be
required to make payments to the counterparties in the event
that reference prices for oil contracts traded on NYMEX for the
periods covered are more than the fixed prices specified for the
hedge arrangements. Although these hedge and other derivative
arrangements will not be directly dedicated or pledged to the
Trust, VOC Sponsor expects that payments received or made
by it under these hedge arrangements will affect its financial
obligations to make payments to the Trust. The effects of these
hedge and other derivative arrangements, if any, are reflected
in these unaudited pro forma financial statements.
NOTE B
PRO FORMA ADJUSTMENTS
Pro forma adjustments are necessary to reflect the issuance of
the trust units, the conveyance of the Net Profits Interest, the
sale of trust units and the payment of VOC Sponsors
long-term
VOC F-27
obligations and distributions using proceeds from the offering.
The pro forma adjustments included in the unaudited pro forma
balance sheet are as follows:
|
|
(a) |
Pro forma adjustments necessary to record the acquisition of the
Acquired Properties oil and gas related assets at estimated fair
value (at December 31, 2010), liabilities, owners
equity and oil and gas revenues and related expenses.
|
Additional pro forma adjustments are necessary to reflect the
issuance of the trust units, the conveyance of the Net Profits
Interest, the sale of trust units and the payment of VOC
Sponsors long-term obligation and distributions using
proceeds from the offering. The pro forma adjustments included
in the unaudited pro forma balance sheet are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
(b)
|
|
Gross cash proceeds from the sale of the trust units
|
|
$
|
215,681,600
|
|
|
|
Cash down payment from VOC Sponsor on related party note
|
|
|
11,511,840
|
|
|
|
Repayment of outstanding borrowing on credit facility
|
|
|
(24,000,000
|
)
|
|
|
Payment of underwriting discount, structuring fee and other
offering expenses
|
|
|
16,888,440
|
(1)
|
|
|
Distribution to partners
|
|
|
(186,305,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
(c)
|
|
Receivable from VOC Sponsor for sale of 34.8% of trust units at
historical value
|
|
$
|
50,298,756
|
|
|
|
Cash down payment on receivable
|
|
|
11,511,840
|
|
|
|
|
|
|
|
|
|
|
Remaining receivable from VOC Sponsor for sale of 34.8% of trust
units
|
|
$
|
38,786,916
|
|
|
|
|
|
|
|
|
(d)
|
|
Current payable for conveyance of oil swap agreements to the
Trust
|
|
$
|
146,254
|
|
|
|
Long-term payable for conveyance of oil swap agreements to the
Trust
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
146,254
|
|
|
|
|
|
|
|
|
|
|
Reduction of oil and gas properties due to conveyance of Net
Profits Interest
|
|
$
|
(168,631,957
|
)
|
|
|
Reduction of associated accumulated depreciation, depletion, and
amortization
|
|
|
22,539,386
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(146,092,571
|
)
|
|
|
|
|
|
|
|
|
|
Current receivable from Trust for conveyance of asset retirement
obligations
|
|
$
|
349,674
|
|
|
|
Long-term receivable from Trust for conveyance of asset
retirement obligations
|
|
|
1,352,490
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,702,164
|
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties and equipment
|
|
$
|
182,615,713
|
|
|
|
Asset retirement obligation liability
|
|
|
(2,127,700
|
)
|
|
|
Oil swap agreements
|
|
|
182,817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
180,670,830
|
|
|
|
|
|
|
|
|
|
|
80% Net Profits Interest
|
|
$
|
144,536,664
|
|
|
|
|
|
|
|
|
(e)
|
|
Deferred gain on sale of Net Profits Interest is calculated as
follows:
|
|
|
|
|
|
|
Gross cash proceeds from the sale of the trust units
|
|
$
|
215,681,600
|
|
|
|
Less: Net book value of conveyed Net Profits Interests
|
|
|
(94,237,905
|
)
|
|
|
Payment of underwriting discounts, structuring fees and other
offering expenses
|
|
|
(16,888,440
|
) (1)
|
|
|
Deferred transaction fees and costs incurred as of
December 31, 2010
|
|
|
(209,272
|
)
|
|
|
|
|
|
|
|
|
|
Deferred gain on sale
|
|
$
|
104,345,983
|
|
|
|
|
|
|
|
|
|
|
Current portion of deferred gain
|
|
$
|
8,759,435
|
|
|
|
Long-term portion of deferred gain
|
|
$
|
95,586,548
|
|
|
|
|
|
|
|
|
(f)
|
|
To record distribution of remaining cash to general partner
|
|
$
|
(1,483,360
|
)
|
|
|
|
|
|
|
|
(g)
|
|
To record distribution of remaining cash to limited partner
|
|
$
|
(72,695,279
|
)
|
|
|
|
|
|
|
|
(h)
|
|
To record distribution of remaining cash to common control owners
|
|
$
|
(112,126,361
|
)
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes offering expenses of $829,959 incurred by VOC Kansas
Energy Partners, LLC. |
VOC F-28
The pro forma adjustments included in the unaudited pro forma
statement of earnings are as follows:
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
December 31, 2010
|
|
|
(i)
|
|
Decrease in oil and gas sales attributable to Net Profits
Interest
|
|
$
|
(50,174,750
|
)
|
|
|
|
|
|
|
|
(j)
|
|
To record amortization of gain on sale of trust units over the
life of the trust
|
|
$
|
9,423,003
|
|
|
|
|
|
|
|
|
(k)
|
|
Decrease in lease operating expenses attributable to the Net
Profits Interest
|
|
$
|
(10,981,622
|
)
|
|
|
|
|
|
|
|
(l)
|
|
Decrease in production and property taxes attributable to the
Net Profits Interest
|
|
$
|
(3,309,478
|
)
|
|
|
|
|
|
|
|
(m)
|
|
Reduce depreciation on assets sold to Trust
|
|
$
|
(9,856,928
|
)
|
|
|
|
|
|
|
|
VOC F-29
December 28, 2010
Mr. Bill Horigan
VOC Brazos Energy Partners, L.P.
1700 Waterfront Pkwy, Bldg 500
Wichita, KS 67206
|
|
|
|
|
|
|
Re:
|
|
Evaluation Summary
VOC Brazos Energy Partners, L.P. Interests
Total Proved Reserves
As of December 31, 2010
|
|
|
|
|
|
|
|
|
|
Pursuant to the Guidelines of the
Securities and Exchange Commission for
Reporting Corporate Reserves and
Future Net Revenue
|
Dear Mr. Horigan:
As requested, this report was prepared on December 28, 2010
for VOC Brazos Energy Partners, L.P. interests
(Company) for the purpose of submitting our
estimates of total proved reserves and forecasts of economics
attributable to Company interests. We evaluated 100% of the
Company reserves, which are made up of various oil and gas
properties in Brazos and Smith Counties, Texas. This evaluation
utilized an effective date of December 31, 2010, 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). The results of this evaluation are presented in the
accompanying tabulations, with a composite summary of the values
presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
Proved
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
|
Developed
|
|
|
Proved
|
|
|
Total
|
|
|
|
|
|
Producing
|
|
|
Non-Producing
|
|
|
Undeveloped
|
|
|
Proved
|
|
|
Net Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
Mbbl
|
|
|
3,879.6
|
|
|
|
258.8
|
|
|
|
1,338.0
|
|
|
|
5,479.4
|
|
Gas
|
|
MMcf
|
|
|
2,161.0
|
|
|
|
132.3
|
|
|
|
1,105.6
|
|
|
|
3,398.8
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
M$
|
|
|
291,669.2
|
|
|
|
19,410.2
|
|
|
|
102,474.8
|
|
|
|
413,554.3
|
|
Gas
|
|
M$
|
|
|
15,898.8
|
|
|
|
983.5
|
|
|
|
8,220.8
|
|
|
|
25,103.1
|
|
Severance Taxes
|
|
M$
|
|
|
13,754.6
|
|
|
|
966.6
|
|
|
|
5,330.4
|
|
|
|
20,051.6
|
|
AdValorem Taxes
|
|
M$
|
|
|
8,485.8
|
|
|
|
551.2
|
|
|
|
3,466.5
|
|
|
|
12,503.5
|
|
Operating Expenses
|
|
M$
|
|
|
84,055.8
|
|
|
|
4,156.3
|
|
|
|
6,465.3
|
|
|
|
94,677.3
|
|
Workover Expenses
|
|
M$
|
|
|
3,933.7
|
|
|
|
0.0
|
|
|
|
0.0
|
|
|
|
3,933.7
|
|
Other Deductions
|
|
M$
|
|
|
4,518.2
|
|
|
|
256.0
|
|
|
|
309.9
|
|
|
|
5,084.2
|
|
Investments
|
|
M$
|
|
|
0.0
|
|
|
|
1,467.4
|
|
|
|
22,505.6
|
|
|
|
23,973.0
|
|
Net Operating Income
|
|
M$
|
|
|
192,819.8
|
|
|
|
12,996.2
|
|
|
|
72,618.0
|
|
|
|
278,434.0
|
|
Discounted @ 10%
(Present Worth)
|
|
M$
|
|
|
81,812.5
|
|
|
|
7,293.0
|
|
|
|
31,050.2
|
|
|
|
120,155.6
|
|
Annex A-1
VOC
Brazos Energy Partners, L.P. Interests
December 28,
2010
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. 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 estimates are for proved reserves only and do 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.
Presentation
This report is divided into four main sections: Total Proved
(TP), Proved Developed Producing (PDP),
Proved Developed Non-Producing (PDNP) and Proved
Undeveloped (PUD). Within each reserve category
section are grand total Table Is, Summary Plots and Tables
II. The Table Is present composite reserve estimates and
economic forecasts for the particular reserve category. The
Summary Plots are composite rate-time history-forecast curves
for the corresponding Table I. Following the Summary Plots are
two Table II oneline summaries that present
estimates of ultimate recovery, gross and net reserves,
ownership, revenue, expenses, investments, net income and
discounted cash flow (DCF) for the individual
properties that make up the corresponding Table I. The first
Table II is sorted on DCF by property, and the second
Table II is sorted alphabetically by lease name.
For a more detailed description of the report layout, please
refer to the Table of Contents following this letter. The data
presented in each Table I is explained in page 1 of the
Appendix. The methods employed in estimating reserves are
described in page 2 of the Appendix.
Hydrocarbon
Pricing
The base SEC oil and gas prices calculated for December 31,
2010 were $79.43/bbl and $4.37/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
price is based upon WTI-Cushing spot prices (EIA) during 2010
and the base gas price is based upon Henry Hub spot prices (EIA)
during 2010.
The base prices 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 $75.406 per barrel for oil
and $7.386 per MCF for gas. All economic factors were held
constant in accordance with SEC guidelines.
Annex A-2
VOC
Brazos Energy Partners, L.P. Interests
December 28,
2010
Economic
Parameters
Ownership was accepted as furnished and has not been
independently confirmed. Oil and gas price differentials, lease
operating expenses (LOE), workover expenses, and investments
were calculated and prepared by you and were thoroughly reviewed
by us for accuracy and completeness. LOE (column 22) was
determined at the well level using averages determined from
historical lease operating statements. Workover Expenses (column
25) were applied to cover the annual costs for recurring
well work and wellbore abandonment. Other Deductions (column
27) represents the net overhead charges as per the JOA. All
economic parameters, including expenses and investments, were
held constant (not escalated) throughout the life of these
properties.
Severance taxes were determined by applying standard Texas
severance tax rates of 4.6% of oil revenue and 7.5% of gas
revenue. Ad valorem tax rates were forecast as provided by your
office.
SEC
Conformance and Regulations
The reserve classifications and the economic considerations used
herein conform to the criteria of the SEC as defined in pages 3
and 4 of the Appendix. The reserves and economics are predicated
on regulatory agency classifications, rules, policies, laws,
taxes and royalties currently in effect except as noted herein.
The possible effects of changes in legislation or other Federal
or State restrictive actions which could affect the reserves and
economics have not been considered. 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 11 proved undeveloped locations
targeting the Woodbine reservoir in the Kurten Field. Each of
these drilling locations proposed as part of the Companys
development plan conforms to the proved undeveloped standards as
set forth by the SEC. In our opinion, the Company has indicated
they have every intent to complete this development plan within
the next five years. Furthermore, the Company 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 2 of the Appendix. 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. These methods provide
a relatively high degree of accuracy for predicting proved
developed non-producing and proved undeveloped reserves for the
Company 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 report.
Annex A-3
VOC
Brazos Energy Partners, L.P. Interests
December 28,
2010
General
Discussion
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.
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. 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 been
included as part of the workover expenses described previously.
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 W. Todd Brooker, Vice President at Cawley,
Gillespie & Associates, Inc. and a State of Texas
Licensed Professional Engineer (License #83462). We do not
own an interest in the properties or VOC Brazos Energy Partners,
L.P. 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 report. Our work-papers and
related data utilized in the preparation of these estimates are
available in our office.
Yours very truly,
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Texas Registered Engineering Firm F-693
|
|
|
W. Todd Brooker, P. E.
Vice President
|
|
|
Annex A-4
APPENDIX
Explanatory
Comments for Summary Tables
HEADINGS
Table I
Description of Table Information
Identity of Interest Evaluated
Reserve Classification and Development Status
Property Description Location
Effective Date of Evaluation
FORECAST
|
|
|
|
|
|
(Columns)
|
|
|
|
|
(1)(11)(21)
|
|
|
Calendar or Fiscal years/months commencing on
effective date.
|
|
(2)(3)(4)
|
|
|
Gross Production (8/8th) for the years/months which are
economical. These are expressed as thousands of barrels (Mbbl)
and millions of cubic feet (MMcf) of gas at standard conditions.
Total future production, cumulative production to effective
date, and ultimate recovery at the effective date are shown
following the annual/monthly forecasts.
|
|
(5)(6)(7)
|
|
|
Net Production accruable to evaluated interest is
calculated by multiplying the revenue interest times the gross
production. These values take into account changes in interest
and gas shrinkage.
|
|
(8)
|
|
|
Average (volume weighted) gross liquid price per barrel
before deducting production-severance taxes.
|
|
(9)
|
|
|
Average (volume weighted) gross gas price per Mcf before
deducting production-severance taxes.
|
|
(10)
|
|
|
Average (volume weighted) gross NGL price per barrel
before deducting production-severance taxes.
|
|
(12)
|
|
|
Revenue derived from oil sales
column(5) times column(8).
|
|
(13)
|
|
|
Revenue derived from gas sales
column(6) times column(9).
|
|
(14)
|
|
|
Revenue derived from NGL sales
column(7) times column(10).
|
|
(15)
|
|
|
Revenue derived from hedge positions.
|
|
(16)
|
|
|
Revenue derived from other sources not included in
column (12) through column (15); may include revenue from
electrical sales, pipeline gas transportation,
3rd party
saltwater disposal, etc.
|
|
(17)
|
|
|
Total Revenue sum of column (12) through
column(16).
|
|
(18)
|
|
|
Production-Severance taxes deducted from gross oil, gas
and NGL revenue.
|
|
(19)
|
|
|
Ad Valorem taxes.
|
|
(20)
|
|
|
$/BOE6 is the total of column (22), column
(25), column (26), and column (27) divided by Barrels of
Oil Equivalent (BOE). BOE is net oil production
column(5) plus net gas production column(6) converted
to oil at six Mcf gas per one bbl oil plus net NGL production
column(7) converted to oil at one bbl NGL per 0.65 bbls of
oil.
|
|
(22)
|
|
|
Operating Expenses are direct operating expenses to the
evaluated working interest and may include combined fixed rate
administrative overhead charges for operated oil and gas
producers known as COPAS.
|
Appendix
|
|
|
|
|
|
Cawley,
Gillespie & Associates, Inc. |
Page 1
|
Annex A-5
|
|
|
|
|
|
(23)
|
|
|
Average gross wells.
|
|
(24)
|
|
|
Average net wells are gross wells times working interest.
|
|
(25)
|
|
|
Workover Expenses are non-direct operating expenses and
may include maintenance, well service, compressor, tubing, and
pump repair.
|
|
(26)
|
|
|
COPAS expenses are fixed rate administrative overhead
charges for company operated producing properties.
|
|
(27)
|
|
|
Other Deductions includes fixed rate overhead charges for
operated oil and gas producers as per the JOA.
|
|
(28)
|
|
|
Investments, if any, include re-completions, future
drilling costs, pumping units, etc. and may include either
tangible or intangible or both, and the costs for plugging and
the salvage value of equipment at abandonment may be shown as
negative investments at end of life.
|
|
(29)(30)
|
|
|
Future Net Cash Flow is column (18) less the total
of column (19), column (22), column (25), column (26), column
(27) and column (28). The data in column (29) are
accumulated in column (30). Federal income taxes have not been
considered.
|
|
(31)
|
|
|
Cumulative Discounted Cash Flow is calculated by
discounting monthly cash flows at the specified annual rates.
|
|
MISCELLANEOUS
|
|
|
|
|
|
|
DCF Profile
|
|
|
The cumulative cash flow discounted at
six different interest rates are shown at the bottom of columns
(30-31).
Interest has been compounded monthly. The DCFs for the
Without Hedge case may be shown to the left of the
main DCF profile.
|
|
Life
|
|
|
The economic life of the appraised
property is noted in the lower right-hand corner of the table.
|
|
Footnotes
|
|
|
Comments regarding the evaluation may be
shown in the lower left-hand footnotes.
|
|
Price Deck
|
|
|
A table of oil and gas prices, price
caps and escalation rates may be shown in the lower middle
footnotes.
|
|
Differentials
|
|
|
Total annual price adjustments may be
shown in gray font to the left of column(8), column(9) and
column(10).
|
Appendix
|
|
|
|
|
|
Cawley,
Gillespie & Associates, Inc. |
Page 2
|
Annex A-6
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
Appendix
|
|
|
|
|
|
Cawley,
Gillespie & Associates, Inc. |
Page 3
|
Annex A-7
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 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.
Appendix
|
|
|
|
|
|
Cawley,
Gillespie & Associates, Inc. |
Page 4
|
Annex A-8
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
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.
(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.
Appendix
|
|
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|
|
|
Cawley,
Gillespie & Associates, Inc. |
Page 5
|
Annex A-9
(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
(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).
Appendix
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Cawley,
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Page 6
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Annex A-10
(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. 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
Appendix
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Cawley,
Gillespie & Associates, Inc. |
Page 7
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Annex A-11
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).
Appendix
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Cawley,
Gillespie & Associates, Inc. |
Page 8
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Annex A-12
December 28, 2010
Mr. Bill Horigan
VOC Kansas Energy Partners, LLC
1700 Waterfront Pkwy, Bldg 500
Wichita, Kansas 67206
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Re:
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Evaluation Summary
VOC Kansas Energy Partners, LLC
Total Proved Reserves
As of December 31, 2010
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Pursuant to the Guidelines of the
Securities and Exchange Commission for
Reporting Corporate Reserves and
Future Net Revenue
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Dear Mr. Horigan:
As requested, this report was prepared on December 28, 2010
for VOC Kansas Energy Partners, LLC (Company)
for the purpose of submitting our estimates of total proved
reserves and forecasts of economics attributable to Company
interests, which is a composite of various working interest
groups. We evaluated 100% of the Company reserves, which are
made up of various oil and gas properties in Kansas and Texas.
This evaluation utilized an effective date of December 31,
2010, 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). The results of this evaluation are presented in the
accompanying tabulations, with a composite summary of the values
presented below:
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Proved
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Proved
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Developed
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Developed
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Proved
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Total
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Producing
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Non-Producing
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Undeveloped
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Proved
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Net Reserves
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Oil
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6,696.6
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136.3
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232.3
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7,065.3
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Gas
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3,550.5
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0.0
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0.0
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3,550.5
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Revenue
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Oil
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488,614.9
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9,862.5
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16,803.3
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515,280.6
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Gas
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13,285.0
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0.0
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0.0
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13,285.0
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Severance Taxes
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4,486.1
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0.0
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436.2
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4,922.3
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Ad Valorem Taxes
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16,339.7
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295.9
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504.1
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17,139.7
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Operating Expenses
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164,009.5
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133.3
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3,658.8
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167,801.7
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Workover Expenses
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12,159.0
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347.8
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0.0
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12,506.9
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COPAS
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31,639.5
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0.0
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0.0
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31,639.5
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Investments
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0.0
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716.6
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2,443.8
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3,160.4
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Net Operating Income
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273,266.1
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8,368.9
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9,760.3
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291,395.3
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Discounted @ 10%
(Present Worth)
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138,869.4
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4,163.6
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5,094.3
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148,127.3
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Annex B-1
VOC
Kansas Energy Partners, LLC
December 28,
2010
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. 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 estimates are for proved reserves only and do 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.
Presentation
This report is divided into four main sections: Summary
(TP), Proved Developed Producing (PDP),
Proved Developed Non-Producing (PDNP), and Proved
Undeveloped (PUD). Within each reserve category
section are grand total Table Is, Summary Plots and Tables
II. The Table Is present composite reserve estimates and
economic forecasts for the particular reserve category. The
Summary Plots are composite rate-time history-forecast curves
for the corresponding Table I. Following the Summary Plots are
two Table II oneline summaries that present
estimates of ultimate recovery, gross and net reserves,
ownership, revenue, expenses, investments, net income and
discounted cash flow (DCF) for the individual
properties that make up the corresponding Table I. The first
Table II is sorted on DCF by property, and the second
Table II is sorted alphabetically by lease name.
For a more detailed description of the report layout, please
refer to the Table of Contents following this letter. The data
presented in each Table I is explained in page 1 of the
Appendix. The methods employed in estimating reserves are
described in page 2 of the Appendix.
Hydrocarbon
Pricing
The base SEC oil and gas prices calculated for December 31,
2010 were $79.43/bbl and $4.37/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
price is based upon WTI-Cushing spot prices (EIA) during 2010
and the base gas price is based upon Henry Hub spot prices (EIA)
during 2010.
The base prices 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 $72.931 per barrel for oil
and $3.742 per MCF for gas. All economic factors were held
constant in accordance with SEC guidelines.
Annex B-2
VOC
Kansas Energy Partners, LLC
December 28,
2010
Economic
Parameters
Ownership was accepted as furnished and has not been
independently confirmed. Oil and gas price differentials, lease
operating expenses (LOE), workover expenses, overhead expenses
and investments were calculated and prepared by you and were
thoroughly reviewed by us for accuracy and completeness. LOE
(column 22) and overhead (COPAS, column 26) were
determined at the well level using averages determined from
historical lease operating statements. Workover Expenses (column
25) were applied to cover the annual costs for recurring
well work and wellbore abandonment. All economic parameters,
including expenses and investments, were held constant (not
escalated) throughout the life of these properties.
For Kansas properties, severance taxes were applied at
4.33 percent of revenue until exemption levels were
forecasted to be reached. The severance tax rate was dropped to
zero when a rate of 6 barrels/day per oil well was reached, or
when gross gas production value reached $87/day per gas well.
Severance taxes were forecasted at 4.6 percent of oil
revenue and 7.5 percent of gas revenue for properties in
Texas. Ad valorem taxes for Kansas properties were applied at
6 percent of revenue, but dropped to 1 percent as
properties qualified for the severance tax exemption. Kansas oil
and gas conservation taxes were included within the ad valorem
tax estimates. Ad valorem taxes were applied at 2% of revenue
for Texas 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 3
and 4 of the Appendix. The reserves and economics are predicated
on regulatory agency classifications, rules, policies, laws,
taxes and royalties currently in effect except as noted herein.
The possible effects of changes in legislation or other Federal
or State restrictive actions which could affect the reserves and
economics have not been considered. 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 13 proved undeveloped locations in
various fields in Kansas. Each of these drilling locations
proposed as part of the Companys development plan conforms
to the proved undeveloped standards as set forth by the SEC. In
our opinion, the Company has indicated they have every intent to
complete this development plan within the next five years.
Furthermore, the Company 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 2 of the Appendix. 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. These methods
Annex B-3
VOC
Kansas Energy Partners, LLC
December 28,
2010
provide a relatively high degree of accuracy for predicting
proved developed non-producing and proved undeveloped reserves
for the Company 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 report.
General
Discussion
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.
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. 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 been
included as part of the workover expenses described previously.
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 W. Todd Brooker, Vice President at Cawley,
Gillespie & Associates, Inc. and a State of Texas
Licensed Professional Engineer (License #83462). We do not
own an interest in the properties or VOC Kansas Energy Partners,
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 report. Our work-papers and
related data utilized in the preparation of these estimates are
available in our office.
Yours very truly,
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Texas Registered Engineering Firm F-693
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W. Todd Brooker, P. E.
Vice President
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Annex B-4
APPENDIX
Explanatory
Comments for Summary Tables
HEADINGS
Table I
Description of Table Information
Identity of Interest Evaluated
Reserve Classification and Development Status
Property Description Location
Effective Date of Evaluation
FORECAST
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(Columns)
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(1)(11)(21)
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Calendar or Fiscal years/months commencing on
effective date.
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(2)(3)(4)
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Gross Production (8/8th) for the years/months which are
economical. These are expressed as thousands of barrels (Mbbl)
and millions of cubic feet (MMcf) of gas at standard conditions.
Total future production, cumulative production to effective
date, and ultimate recovery at the effective date are shown
following the annual/monthly forecasts.
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(5)(6)(7)
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Net Production accruable to evaluated interest is
calculated by multiplying the revenue interest times the gross
production. These values take into account changes in interest
and gas shrinkage.
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(8)
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Average (volume weighted) gross liquid price per barrel
before deducting production-severance taxes.
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(9)
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Average (volume weighted) gross gas price per Mcf before
deducting production-severance taxes.
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(10)
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Average (volume weighted) gross NGL price per barrel
before deducting production-severance taxes.
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(12)
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Revenue derived from oil sales column
(5) times column (8).
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(13)
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Revenue derived from gas sales column
(6) times column (9).
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(14)
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Revenue derived from NGL sales column
(7) times column (10).
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(15)
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Revenue derived from hedge positions.
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(16)
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Revenue derived from other sources not included in
column (12) through column (15); may include revenue from
electrical sales, pipeline gas transportation,
3rd party
saltwater disposal, etc.
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(17)
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Total Revenue sum of column (12) through
column (16).
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(18)
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Production-Severance taxes deducted from gross oil, gas
and NGL revenue.
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(19)
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Ad Valorem taxes.
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(20)
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$/BOE6 is the total of column (22), column
(25), column (26), and column (27) divided by Barrels of
Oil Equivalent (BOE). BOE is net oil production
column (5) plus net gas production column
(6) converted to oil at six Mcf gas per one bbl oil plus
net NGL production column (7) converted to oil at one bbl
NGL per 0.65 bbls of oil.
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(22)
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Operating Expenses are direct operating expenses to the
evaluated working interest and may include combined fixed rate
administrative overhead charges for operated oil and gas
producers known as COPAS.
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Appendix
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Cawley,
Gillespie & Associates, Inc. |
Page 1
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Annex B-5
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(23)
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Average gross wells.
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(24)
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Average net wells are gross wells times working interest.
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(25)
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Workover Expenses are non-direct operating expenses and
may include maintenance, well service, compressor, tubing, and
pump repair.
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(26)
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COPAS expenses are fixed rate administrative overhead
charges for company operated producing properties.
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(27)
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Other Deductions includes fixed rate overhead charges for
operated oil and gas producers as per the JOA.
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(28)
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Investments, if any, include re-completions, future
drilling costs, pumping units, etc. and may include either
tangible or intangible or both, and the costs for plugging and
the salvage value of equipment at abandonment may be shown as
negative investments at end of life.
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(29)(30)
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Future Net Cash Flow is column (18) less the total
of column (19), column (22), column (25), column (26), column
(27) and column (28). The data in column (29) are
accumulated in column (30). Federal income taxes have not been
considered.
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(31)
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Cumulative Discounted Cash Flow is calculated by
discounting monthly cash flows at the specified annual rates.
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MISCELLANEOUS
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DCF Profile
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The cumulative cash flow discounted at
six different interest rates are shown at the bottom of columns
(30-31).
Interest has been compounded monthly. The DCFs for the
Without Hedge case may be shown to the left of the
main DCF profile.
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Life
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The economic life of the appraised
property is noted in the lower right-hand corner of the table.
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Footnotes
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Comments regarding the evaluation may be
shown in the lower left-hand footnotes.
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Price Deck
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A table of oil and gas prices, price
caps and escalation rates may be shown in the lower middle
footnotes.
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Differentials
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Total annual price adjustments may be
shown in gray font to the left of column (8), column
(9) and column (10).
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Appendix
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Cawley,
Gillespie & Associates, Inc. |
Page 2
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Annex B-6
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
Appendix
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Cawley,
Gillespie & Associates, Inc. |
Page 3
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Annex B-7
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 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.
Appendix
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Cawley,
Gillespie & Associates, Inc. |
Page 4
|
Annex B-8
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
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.
(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
Appendix
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Cawley,
Gillespie & Associates, Inc. |
Page 5
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Annex B-9
(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.
Appendix
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Gillespie & Associates, Inc. |
Page 6
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Annex B-10
(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. 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).
Appendix
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Cawley,
Gillespie & Associates, Inc. |
Page 7
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Annex B-11
March 9, 2011
Mr. Bill Horigan
VOC Brazos Energy Partners, L.P.
1700 Waterfront Pkwy, Bldg 500
Wichita, KS 67206
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Re:
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Evaluation Summary
VOC Energy Trust Net Profits Interests
Total Proved Reserves
Certain Oil and Gas Assets KS & TX
As of December 31, 2010
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Pursuant to the Guidelines of the
Securities and Exchange Commission for
Reporting Corporate Reserves and
Future Net Revenue
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Dear Mr. Horigan:
As requested, this report was prepared on March 2, 2011 for
VOC Energy Trust (Trust) for the purpose of
submitting our estimates of total proved reserves and forecasts
of economics attributable to the Trust term net profits
interests. We evaluated 100% of the Trust reserves, which are
made up of oil and gas properties in Kansas and Texas owned by
VOC Brazos Energy Partners, L.P. and VOC Kansas Energy Partners,
LLC (Companies). This evaluation utilized an
effective date of December 31, 2010, 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). A composite summary of the proved reserves is
presented below.
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Proved
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Proved
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Developed
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Developed
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Proved
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Total
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Producing
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Non-Producing
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Undeveloped
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Proved
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Net Reserves
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Oil
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MBBL
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7,924.5
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371.5
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1,343.6
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9,639.6
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Gas
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MMCF
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4,953.0
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132.3
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938.7
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6,024.0
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Revenue
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Oil
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M$
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583,748.3
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27,566.4
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102,017.1
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713,331.8
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Gas
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M$
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24,917.8
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983.5
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6,979.8
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32,881.1
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Severance Taxes
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M$
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13,472.1
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966.6
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4,904.0
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19,342.7
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Ad Valorem Taxes
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M$
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19,118.9
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795.8
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3,393.6
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23,308.3
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Operating Expenses
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M$
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157,288.9
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4,209.4
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5,923.2
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167,421.5
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Workover Expenses
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M$
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10,210.8
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347.8
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0.0
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10,558.6
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COPAS
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M$
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23,909.1
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256.0
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162.3
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24,327.4
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Investments
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M$
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0.0
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2,184.0
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24,949.4
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27,133.4
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80% NPI Net Operating
Income (BFIT)
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M$
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307,733.0
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15,832.1
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55,731.6
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379,296.6
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80% NPI Disc. @ 10%
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M$
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171,454.1
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9,079.3
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28,019.1
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208,552.5
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Annex C-1
VOC
Energy Trust Net Profits Interests
December 28,
2010
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. 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 estimates are for proved reserves only and do 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.
Net
Profits Calculations
The net profits interests entitle the Trust to receive 80% of
the net proceeds attributable to the Companies interests
from the sale of production from the underlying properties. The
net profits interests will terminate on the later to occur
(1) December 31, 2030, or (2) the time when
10.6 MMBOE (which is equivalent of 8.5 MMBOE in
respect of the net profits interest) have been produced from the
underlying properties and sold.
Hydrocarbon
Pricing
The base SEC oil and gas prices calculated for December 31,
2010 were $79.43/bbl and $4.37/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
price is based upon WTI-Cushing spot prices (EIA) during 2010
and the base gas price is based upon Henry Hub spot prices (EIA)
during 2010.
Oil price differentials were forecast at -$7.10 per BBL for all
VOC KEP properties and ranged from $2.20 to -$2.84
for the VOC Brazos properties. Gas price differentials varied by
property. The base price differentials 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 trust life
of the proved properties was estimated to be $73.97 per barrel
for oil and $5.458 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, lease
operating expenses (LOE), workover expenses, overhead expenses
and investments were calculated and prepared by you and were
thoroughly reviewed by us for accuracy and completeness. LOE
(column 22) and overhead (COPAS, column 26) were
determined at the well level using averages determined from
historical lease operating statements. Workover Expenses (column
25) were applied to cover the annual costs for recurring
well work and wellbore abandonment. All economic parameters,
including expenses and investments, were held constant (not
escalated) throughout the life of these properties.
Annex C-2
VOC
Energy Trust Net Profits Interests
December 28,
2010
For Kansas properties, severance taxes were applied at
4.33 percent of revenue until exemption levels were
forecasted to be reached. The severance tax rate was dropped to
zero when a rate of 6 barrels/day per oil well was reached,
or when gross gas production value reached $87/day per gas well.
Severance taxes were forecasted at 4.6 percent of oil
revenue and 7.5 percent of gas revenue for properties in
Texas. Ad valorem taxes for Kansas properties were applied at
6 percent of revenue, but dropped to 3 percent as
properties qualified for the tax exemption. Kansas oil and gas
conservation taxes were included within the ad valorem tax
estimates. Ad valorem taxes were applied at 2% of revenue for
Texas properties.
SEC
Conformance and Regulations
The reserve classifications and the economic considerations used
herein for the SEC pricing scenario conform to the criteria of
the SEC as defined in pages 3 and 4 of the Appendix. The
reserves and economics are predicated on regulatory agency
classifications, rules, policies, laws, taxes and royalties
currently in effect except as noted herein. The possible effects
of changes in legislation or other Federal or State restrictive
actions which could affect the reserves and economics have not
been considered. 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 24 proved undeveloped locations based
in various fields throughout Kansas and Texas. Each of these
drilling locations proposed as part of the Companies
development plan conforms to the proved undeveloped standards as
set forth by the SEC. In our opinion, the Companies have
indicated they have every intent to complete this development
plan within the next five years. Furthermore, the Companies have
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 2 of the Appendix. 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. These methods provide
a relatively high degree of accuracy for predicting proved
developed non-producing and proved undeveloped reserves for the
Companies 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 report.
General
Discussion
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
Annex C-3
VOC
Energy Trust Net Profits Interests
December 28,
2010
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.
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. 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 been included as
part of the workover expenses described previously.
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 W. Todd Brooker, Vice President at Cawley,
Gillespie & Associates, Inc. and a State of Texas
Licensed Professional Engineer (License #83462). We do not
own an interest in the properties or VOC Brazos Energy Partners,
L.P., VOC Kansas Energy Partners, LLC or VOC Energy Trust 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 report. Our work-papers and
related data utilized in the preparation of these estimates are
available in our office.
Yours very truly,
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Texas Registered Engineering Firm (F-693)
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W. Todd Brooker, P.E.
Vice President
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Annex C-4
APPENDIX
Explanatory
Comments for Summary Tables
HEADINGS
Table I
Description of Table Information
Identity of Interest Evaluated
Reserve Classification and Development Status
Property Description Location
Effective Date of Evaluation
FORECAST
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(Columns)
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(1)(11)(21)
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Calendar or Fiscal years/months commencing on
effective date.
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(2)(3)(4)
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Gross Production (8/8th) for the years/months which are
economical. These are expressed as thousands of barrels (Mbbl)
and millions of cubic feet (MMcf) of gas at standard conditions.
Total future production, cumulative production to effective
date, and ultimate recovery at the effective date are shown
following the annual/monthly forecasts.
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(5)(6)(7)
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Net Production accruable to evaluated interest is
calculated by multiplying the revenue interest times the gross
production. These values take into account changes in interest
and gas shrinkage.
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(8)
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Average (volume weighted) gross liquid price per barrel
before deducting production-severance taxes.
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(9)
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Average (volume weighted) gross gas price per Mcf before
deducting production-severance taxes.
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(10)
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Average (volume weighted) gross NGL price per barrel
before deducting production-severance taxes.
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(12)
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Revenue derived from oil sales column
(5) times column (8).
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(13)
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Revenue derived from gas sales column
(6) times column (9).
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(14)
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Revenue derived from NGL sales column
(7) times column (10).
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(15)
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Revenue derived from hedge positions.
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(16)
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Revenue derived from other sources not included in
column (12) through column (15); may include revenue from
electrical sales, pipeline gas transportation,
3rd party
saltwater disposal, etc.
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(17)
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Total Revenue sum of column (12) through
column (16).
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(18)
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Production-Severance taxes deducted from gross oil, gas
and NGL revenue.
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(19)
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Ad Valorem taxes.
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(20)
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$/BOE6 is the total of column (22), column
(25), column (26), and column (27) divided by Barrels of
Oil Equivalent (BOE). BOE is net oil production
column (5) plus net gas production column
(6) converted to oil at six Mcf gas per one bbl oil plus
net NGL production column (7) converted to oil at one bbl
NGL per 0.65 bbls of oil.
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(22)
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Operating Expenses are direct operating expenses to the
evaluated working interest and may include combined fixed rate
administrative overhead charges for operated oil and gas
producers known as COPAS.
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Appendix
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Cawley,
Gillespie & Associates, Inc. |
Page 1
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Annex C-5
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(23)
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Average gross wells.
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(24)
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Average net wells are gross wells times working interest.
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(25)
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Workover Expenses are non-direct operating expenses and
may include maintenance, well service, compressor, tubing, and
pump repair.
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(26)
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COPAS expenses are fixed rate administrative overhead
charges for company operated producing properties.
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(27)
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Other Deductions includes fixed rate overhead charges for
operated oil and gas producers as per the JOA.
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(28)
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Investments, if any, include re-completions, future
drilling costs, pumping units, etc. and may include either
tangible or intangible or both, and the costs for plugging and
the salvage value of equipment at abandonment may be shown as
negative investments at end of life.
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(29)(30)
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Future Net Cash Flow is column (18) less the total
of column (19), column (22), column (25), column (26), column
(27) and column (28). The data in column (29) are
accumulated in column (30). Federal income taxes have not been
considered.
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(31)
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Cumulative Discounted Cash Flow is calculated by
discounting monthly cash flows at the specified annual rates.
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MISCELLANEOUS
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DCF Profile
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The cumulative cash flow discounted at
six different interest rates are shown at the bottom of columns
(30-31).
Interest has been compounded monthly. The DCFs for the
Without Hedge case may be shown to the left of the
main DCF profile.
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Life
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The economic life of the appraised
property is noted in the lower right-hand corner of the table.
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Footnotes
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Comments regarding the evaluation may be
shown in the lower left-hand footnotes.
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Price Deck
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A table of oil and gas prices, price
caps and escalation rates may be shown in the lower middle
footnotes.
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Differentials
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Total annual price adjustments may be
shown in gray font to the left of column (8), column
(9) and column (10).
|
Appendix
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Cawley,
Gillespie & Associates, Inc. |
Page 2
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Annex C-6
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
Appendix
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Cawley,
Gillespie & Associates, Inc. |
Page 3
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Annex C-7
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 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.
Appendix
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Cawley,
Gillespie & Associates, Inc. |
Page 4
|
Annex C-8
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
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.
(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
Appendix
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Cawley,
Gillespie & Associates, Inc. |
Page 5
|
Annex C-9
(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.
Appendix
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Cawley,
Gillespie & Associates, Inc. |
Page 6
|
Annex C-10
(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. 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).
Appendix
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Cawley,
Gillespie & Associates, Inc. |
Page 7
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Annex C-11
10,785,000 Trust Units
VOC ENERGY TRUST
PROSPECTUS
Joint Book-Runners
|
|
RAYMOND
JAMES |
MORGAN STANLEY |
,
2011
PART II
INFORMATION
NOT REQUIRED IN PROSPECTUS
|
|
Item 13.
|
Other
Expenses of Issuance and Distribution.
|
Set forth below are the expenses (other than underwriting
discounts 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 and the NYSE
listing fee, the amounts set forth below are estimates.
|
|
|
|
|
Registration fee
|
|
$
|
30,240
|
|
FINRA filing fee
|
|
|
26,546
|
|
NYSE listing fee
|
|
|
125,000
|
|
Printing and engraving expenses
|
|
|
450,000
|
|
Fees and expenses of legal counsel
|
|
|
1,000,000
|
|
Accounting fees and expenses
|
|
|
550,000
|
|
Transfer agent and registrar fees
|
|
|
5,150
|
|
Trustee fees and expenses
|
|
|
87,500
|
|
Miscellaneous
|
|
|
25,564
|
|
|
|
|
|
|
Total
|
|
$
|
2,300,000
|
|
|
|
|
|
|
|
|
Item 14.
|
Indemnification
of Directors and Officers.
|
The trust agreement provides that the trustee and its officers,
agents and employees shall be indemnified from the assets of the
trust against and from any and all liabilities, expenses,
claims, damages or loss incurred by it individually or as
trustee in the administration of the trust and the trust assets,
including, without limitation, any liability, expenses, claims,
damages or loss arising out of or in connection with any
liability under environmental laws, or in the doing of any act
done or performed or omission occurring on account of it being
trustee or acting in such capacity, except such liability,
expense, claims, damages or loss as to which it is liable under
the trust agreement. In this regard, the trustee shall be liable
only for its own fraud or for facts or omissions in bad faith or
which constitute gross negligence and shall not be liable for
any act or omission of any agent or employee unless the trustee
has acted in bad faith or with gross negligence in the selection
and retention of such agent or employee. The trustee is entitled
to indemnification from the assets of the trust and shall have a
lien on the assets of the trust to secure it for the foregoing
indemnification.
Reference is made to the Underwriting Agreement to be filed as
an exhibit to this registration statement in which VOC Sponsor
and its affiliates will agree to indemnify the underwriters
against certain liabilities, including liabilities under the
Securities Act and to contribute to payments that may be
required to be made in respect of these liabilities. Subject to
any terms, conditions or restrictions set forth in the
partnership agreement, Chapter 8 of the Texas Business
Organizations Code empowers a Texas limited partnership to
indemnify and hold harmless any limited partnership or other
persons from and against all claims and demands whatsoever.
In connection with the preparation and filing of any shelf
registration statement, VOC Brazos will indemnify VOC Energy
Trust and certain of its affiliates from and against any
liabilities under the Securities Act or any state securities
laws arising from the registration statement or prospectus. VOC
Brazos will bear all costs and expenses incidental to any shelf
registration statement, excluding any underwriting discounts and
fees.
II-1
|
|
Item 15.
|
Recent
Sales of Unregistered Securities.
|
None.
|
|
Item 16.
|
Exhibits
and Financial Statement Schedules.
|
(a) Exhibits.
The following documents are filed as exhibits to this
registration statement:
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
1
|
.1**
|
|
|
|
Form of Underwriting Agreement.
|
|
2
|
.1*
|
|
|
|
Contribution and Exchange Agreement among VOC Brazos Energy
Partners, L.P., VOC Kansas Energy Partners, LLC, VAP-III,
LLC, Vess Texas Acquisition Group, LLC, Vess Texas Partners,
LLC, and the other parties named therein.
|
|
3
|
.1*
|
|
|
|
Certificate of Limited Partnership of VOC Brazos Energy
Partners, L.P.
|
|
3
|
.2*
|
|
|
|
Amended and Restated Agreement of Limited Partnership of VOC
Brazos Energy Partners, L.P. dated as of September 21, 2009.
|
|
3
|
.3***
|
|
|
|
First Amendment to Contribution and Exchange Agreement entered
into as of April 11, 2011 by and among VOC Brazos Energy
Partners, L.P., VOC Kansas Energy Partners, LLC,
VAP-III,
LLC, Vess Texas Acquisition Group, LLC, Vess Texas Partners, LLC
and the other parties named therein.
|
|
3
|
.4*
|
|
|
|
Certificate of Trust of VOC Energy Trust.
|
|
3
|
.5*
|
|
|
|
Trust Agreement dated November 3, 2010 among VOC
Brazos Energy Partners, L.P., as trustor, and Wilmington
Trust Company, and The Bank of New York Mellon
Trust Company, N.A., as trustees.
|
|
3
|
.6***
|
|
|
|
Form of Amended and Restated Trust Agreement.
|
|
5
|
.1***
|
|
|
|
Opinion of Morris James LLP relating to the validity of the
trust units.
|
|
8
|
.1***
|
|
|
|
Opinion of Vinson & Elkins L.L.P. relating to tax
matters.
|
|
10
|
.1*
|
|
|
|
Credit Agreement dated as of June 27, 2008 among VOC Brazos
Energy Partners, L.P., as borrower, Bank of America, N.A., as
lender, and the other parties named therein.
|
|
10
|
.2*
|
|
|
|
First Amendment to Credit Agreement dated August 12, 2008
by and among VOC Brazos, LP (now VOC Brazos, LLC), as borrower,
Bank of America, N.A. and the other parties named therein.
|
|
10
|
.3***
|
|
|
|
Form of Term Net Profits Interest Conveyance.
|
|
10
|
.4***
|
|
|
|
Form of Administrative Services Agreement.
|
|
10
|
.5***
|
|
|
|
Form of Registration Rights Agreement.
|
|
21
|
.1*
|
|
|
|
Subsidiaries of VOC Brazos Energy Partners, L.P.
|
|
23
|
.1***
|
|
|
|
Consent of Grant Thornton LLP
|
|
23
|
.2***
|
|
|
|
Consent of Morris James LLP (contained in Exhibit 5.1).
|
|
23
|
.3***
|
|
|
|
Consent of Vinson & Elkins L.L.P. (contained in
Exhibit 8.1).
|
|
23
|
.4***
|
|
|
|
Consent of Cawley, Gillespie & Associates, Inc.
|
|
99
|
.1***
|
|
|
|
Summary Reserve Reports of Cawley, Gillespie &
Associates, Inc. (included as Annexes A, B, C to the
prospectus)
|
|
|
|
*
|
|
Previously filed with the
Registration Statement (File No. 333-171474) on
December 30, 2010.
|
|
|
|
**
|
|
To be filed by amendment
|
II-2
(b) Financial Statement Schedules.
No financial statement schedules are required to be included
herewith or they have been omitted because the information
required to be set forth therein is not applicable.
The undersigned registrants hereby undertake:
(a) Insofar as indemnification for liabilities arising
under the Securities Act of 1933 may be permitted to
directors, officers and controlling persons of the registrants
pursuant to the provisions described in Item 14, or
otherwise, the registrants have been advised that in the opinion
of the SEC such indemnification is against public policy as
expressed in the Securities Act of 1933 and is, therefore,
unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the
registrants of expenses incurred or paid by a director, officer
or controlling person of the registrants 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 registrants will, unless in the
opinion of their respective counsel the matter has been settled
by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by them
is against public policy as expressed in the Securities Act of
1933 and will be governed by the final adjudication of such
issue.
(b) 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.
(c) For purpose of determining any liability under the
Securities Act of 1933, the information omitted from the form of
prospectus filed as part of this Registration Statement in
reliance upon Rule 430A and contained in the form of
prospectus filed by the registrants 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.
(d) For the purpose of determining any liability under the
Securities Act of 1933, 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.
(e) To send to each trust unitholder at least on an annual
basis a detailed statement of any transactions with the trustees
or their respective affiliates, and of fees, commissions,
compensation and other benefits paid, or accrued to the trustees
or their respective affiliates for the fiscal year completed,
showing the amount paid or accrued to each recipient and the
services performed.
(f) To provide to the trust unitholders the financial
statements required by
Form 10-K
for the first full fiscal year of operations of the trust.
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 Wichita, State of
Kansas, on April 13, 2011.
VOC Brazos Energy Partners, L.P.
|
|
|
|
By:
|
Vess Texas Partners, LLC,
its General Partner
|
|
|
By:
|
Vess Holding Corporation,
its Sole Managing Member
|
Name: J. Michael Vess
Title: Designated Representative
and Sole Member of Board of Directors
II-4
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 Wichita, State of
Kansas, on April 13, 2011.
VOC Energy Trust
|
|
|
|
By:
|
The Bank of New York Mellon Trust Company, N.A.
|
By:
/s/ MICHAEL
J. ULRICH
Name: Michael J. Ulrich
Title: Vice President
II-5
INDEX TO
EXHIBITS
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
1
|
.1**
|
|
|
|
Form of Underwriting Agreement.
|
|
2
|
.1*
|
|
|
|
Contribution and Exchange Agreement among VOC Brazos Energy
Partners, L.P., VOC Kansas Energy Partners, LLC, VAP-III,
LLC, Vess Texas Acquisition Group, LLC, Vess Texas Partners,
LLC, and the other parties named therein.
|
|
3
|
.1*
|
|
|
|
Certificate of Limited Partnership of VOC Brazos Energy
Partners, L.P.
|
|
3
|
.2*
|
|
|
|
Amended and Restated Agreement of Limited Partnership of VOC
Brazos Energy Partners, L.P. dated as of September 21, 2009.
|
|
3
|
.3***
|
|
|
|
First Amendment to Contribution and Exchange Agreement entered
into as of April 11, 2011 by and among VOC Brazos Energy
Partners, L.P., VOC Kansas Energy Partners, LLC,
VAP-III,
LLC, Vess Texas Acquisition Group, LLC, Vess Texas Partners, LLC
and the other parties named therein.
|
|
3
|
.4*
|
|
|
|
Certificate of Trust of VOC Energy Trust.
|
|
3
|
.5*
|
|
|
|
Trust Agreement dated November 3, 2010 among VOC
Brazos Energy Partners, L.P., as trustor, and Wilmington
Trust Company, and The Bank of New York Mellon
Trust Company, N.A., as trustees.
|
|
3
|
.6***
|
|
|
|
Form of Amended and Restated Trust Agreement.
|
|
5
|
.1***
|
|
|
|
Opinion of Morris James LLP relating to the validity of the
trust units.
|
|
8
|
.1***
|
|
|
|
Opinion of Vinson & Elkins L.L.P. relating to tax
matters.
|
|
10
|
.1*
|
|
|
|
Credit Agreement dated as of June 27, 2008 among VOC Brazos
Energy Partners L.P., as borrower, Bank of America, N.A., as
lender, and the other parties named therein.
|
|
10
|
.2*
|
|
|
|
First Amendment to Credit Agreement dated August 12, 2008
by and among VOC Brazos, LP (now VOC Brazos, LLC), as borrower,
Bank of America, N.A. and the other parties named therein.
|
|
10
|
.3***
|
|
|
|
Form of Term Net Profits Interest Conveyance.
|
|
10
|
.4***
|
|
|
|
Form of Administrative Services Agreement.
|
|
10
|
.5***
|
|
|
|
Form of Registration Rights Agreement.
|
|
21
|
.1*
|
|
|
|
Subsidiaries of VOC Brazos Energy Partners, L.P.
|
|
23
|
.1***
|
|
|
|
Consent of Grant Thornton LLP
|
|
23
|
.2***
|
|
|
|
Consent of Morris James LLP (contained in Exhibit 5.1).
|
|
23
|
.3***
|
|
|
|
Consent of Vinson & Elkins L.L.P. (contained in
Exhibit 8.1).
|
|
23
|
.4***
|
|
|
|
Consent of Cawley, Gillespie & Associates, Inc.
|
|
99
|
.1***
|
|
|
|
Summary Reserve Reports of Cawley, Gillespie &
Associates, Inc. (included as Annex A to the prospectus).
|
|
|
|
*
|
|
Previously filed with Registration
Statement (File No.
333-171474)
on December 30, 2010.
|
|
|
|
**
|
|
To be filed by amendment
|