VOC Energy Trust | VOC Brazos Energy Partners, L.P. | |
(Exact Name of co-registrant as specified in its charter) | (Exact Name of co-registrant as specified in its charter) |
Delaware | Texas | |
(State or other jurisdiction of incorporation or organization) | (State or other jurisdiction of incorporation or organization) |
1311 | 1311 | |
(Primary Standard Industrial Classification Code Number) | (Primary Standard Industrial Classification Code Number) |
80-6183103 | 20-0079353 | |
(I.R.S. Employer Identification No.) | (I.R.S. Employer Identification No.) |
919 Congress Avenue | 1700 Waterfront Parkway | |
Suite 500 | Building 500 | |
Austin, Texas 78701 | Wichita, Kansas 67206 | |
(512) 236-6599 | (316) 682-1537 | |
(Address, including zip code, and telephone number, including area code, of co-registrant’s Principal Executive Offices) | (Address, including zip code, and telephone number, including area code, of co-registrant’s Principal Executive Offices) |
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) | 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) |
David P. Oelman | Joshua Davidson | |
W. Matthew Strock | Laura Tyson | |
Vinson & Elkins L.L.P. | Baker Botts L.L.P. | |
1001 Fannin Street, Suite 2500 | 910 Louisiana, Suite 3200 | |
Houston, Texas77002-6760 | Houston, Texas 77002 | |
(713) 758-2222 | (713) 229-1234 |
Large accelerated filer o | Accelerated filer o | Non-accelerated filer þ | Smaller reporting company o |
Proposed Maximum | Amount of | |||||||||
Title of Each Class of | Aggregate Offering | Registration | ||||||||
Securities to be Registered | Price (1)(2) | Fee (3) | ||||||||
Units Of Beneficial Interest in VOC Energy Trust | $ | 260,457,750 | $ | 30,240 | ||||||
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. |
• | 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. |
• | 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. |
• | Neither the trust nor the trust’s unitholders will have the ability to influence VOC Sponsor or control the operations or development of the Underlying Properties. |
• | 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 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 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. |
Per | ||||||||
Trust | ||||||||
Unit | Total | |||||||
Initial public offering price | $ | $ | ||||||
Underwriting discounts and commissions (1) | $ | $ | ||||||
Proceeds, before expenses, to VOC Sponsor | $ | $ |
(1) | 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. |
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 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 trust’s business, financial condition, results of operations and prospects may have changed since such date.
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.
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 aPV-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 aPV-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 Sponsor’s 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 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 trust’s 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
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:
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 Sponsor’s 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 Sponsor’s 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 Sponsor’s 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 onPV-10 value and VOC 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.
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 Sponsor’s 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, LLC’s 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 Sponsor’s 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 correspondingPV-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.
PLANNED DEVELOPMENT AND WORKOVER PROGRAM The primary goals of VOC Sponsor’s 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 Sponsor’s existing wells or VOC Sponsor’s 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.
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
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 onPV-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:
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.
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
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.
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 Sponsor’s 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
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 onpage 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.
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
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.
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 pageVOC 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 VOCF-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.
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 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 Sponsor’s 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.”
19
THE OFFERING
RISK FACTORS Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the trust and cash distributions to unitholders. The trust’s 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 aquarter-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:
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 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
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 fromwell-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 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 Sponsor’s 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 Sponsor’s calculations, and VOC Sponsor has not received an opinion or report on such calculations from any independent accountants. Such calculations are
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 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 trust’s 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:
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 trust’s and VOC Sponsor’s control, including risks that could delay VOC Sponsor’s 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 Sponsor’s future business, financial condition, results of operations, liquidity or ability to finance
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:
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
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 Neither the trust nor the trust’s 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 Sponsor’s 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.
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 Sponsor’s 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 Sponsor’s 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 any12-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 trust’s 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
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 trust’s 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 trust’s 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
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 trust’s 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:
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 Sponsor’s 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 unitholder’s 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
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 Sponsor’s 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 Sponsor’s 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 Sponsor’s 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 Sponsor’s 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 Sponsor’s wells are drilled and facilities where VOC Sponsor’s 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,
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 Sponsor’s acquisition of the Underlying Properties unless such costs and expenses result from VOC Sponsor’s 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 Sponsor’s costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to VOC Sponsor’s operations. Such costs could have a material adverse effect on VOC Sponsor’s 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 trust’s 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 Sponsor’s 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
potential regulations could increase the operating costs of the Underlying Properties, reduce VOC Sponsor’s liquidity, delay VOC Sponsor’s 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 trust’s 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 Sponsor’s 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 earth’s 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 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 inventoriesand/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 Sponsor’s 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 trust’s cash available for distribution.
Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s 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 Sponsor’s assets and operations and, consequently, may reduce the proceeds attributable to the Net Profits Interest and, as a result, the trust’s 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 Sponsor’s 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 Act’s 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 EPA’s 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
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 onPV-10 value. Therefore, the value of the Net Profits Interest and the trust’s 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 onpage 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.
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 Sponsor’s 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.”
TAX RISKS RELATED TO THE TRUST’S 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 individual’s 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 trust’s 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.”
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:
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.
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 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.
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 onPV-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.
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) — Management’s 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 Predecessor’s 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 onpage 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.
The table below includes selected production and reserve information for VOC Sponsor for the periods presented.
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 Sponsor’s general partner:
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 Vessis 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 William R. Horiganis 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
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 Gaudreauis 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 Hillis 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 Howarteris 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.
BENEFICIAL OWNERSHIP OF VOC SPONSOR The following table sets forth, as of
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.
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.
MV OIL TRUST Certain members of VOC Sponsor’s 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 MVO’s 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 MVO’s 80% net profits interest) and 2,621 Boe (or approximately 2,097 Boe attributable to MVO’s 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 As publicly reported, on July 22, 2008, MVO’s 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 MVO’s 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 Eaglwing’s 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
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
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:
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. 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
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 Sponsor’s 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.
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 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 trust’s 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.
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 Sponsor’s 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 trust’s 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:
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 trust’s 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 onpage 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.
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 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 Sponsor’s 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:
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 Sponsor’s 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 Sponsor’s 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
56
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 trust’s 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 Sponsor’s 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 Oil and natural gas prices.
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,
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, 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 Costs. For the first 11 months of 2011, VOC Sponsor estimates lease operating expenses to be
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 andout-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 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.”
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 trust’s 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
THE UNDERLYING PROPERTIES The Underlying Properties consist of VOC Sponsor’s 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 Sponsor’s 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 aPV-10 value of $268.3 million. VOC Sponsor’s 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 landowner’s 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 owner’s 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 owner’s 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 onPV-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 Sponsor’s 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 Sponsor’s 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, LLC’s 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
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 onpage 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
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
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.
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
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 Predecessor’s 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 Predecessor’s oil and gas leases, filed suit to recover these funds which were estimated to be $1.4 million for Predecessor’s 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
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 Predecessor’s 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 Predecessor’s oil and gas leases, filed suit to recover these funds which were estimated to be $1.4 million for Predecessor’s 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 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
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.
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
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 Sponsor’s crude oil price risk management positions in swap contracts are as follows:
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.”
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 Sponsor’s 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.
The following is a summary of the producing wells on the Underlying Properties as of December 31, 2010:
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.
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.
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-taxPV-10 value as of December 31, 2010 and the average net production attributable to the Underlying Properties for the year ended December 31, 2010.
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 Sponsor’s 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.
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 onPV-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 Sponsor’s interests in the major fields in Kansas as of December 31, 2010.
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 onPV-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
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 Sponsor’s interests in the major fields in Texas as of December 31, 2010.
PLANNED DEVELOPMENT AND WORKOVER PROGRAM The primary goals of VOC Sponsor’s 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 Sponsor’s existing wells or VOC Sponsor’s 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.
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
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 industry’s 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 Sponsor’s 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 thefirst-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 trust’s
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 thefirst-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 throughpercent-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):
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.
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.
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.
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
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
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
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 any12-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 Sponsor’s 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.
During the year ended December 31, 2010, VOC Sponsor sold approximately 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 Vess Oil has committed to sell its crude oil in the Kurten Woodbine Units in Texas to Enterprise Crude Oil, LLC until May 31, 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 amonth-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 Sponsor’s rights to production and the value of production from the Underlying Properties, they have been taken into account in calculating the trust’s interests and in estimating the size and the value of the reserves attributable to the Underlying Properties. VOC Sponsor’s 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:
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 trust’s 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 factors—The 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
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 trust’s 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 Sponsor’s operations, including requirements to:
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
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 Sponsor’s 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 Sponsor’s 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 Sponsor’s control.
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 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
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 Earth’s 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 inventoriesand/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 Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s 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.
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 Sponsor’s 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 communityright-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.
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 “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:
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
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:
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 Sponsor’s 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 any12-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.
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.
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 trust’s 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 trust’s 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:
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
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 trustee’s principal duties consist of:
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
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 trust’s 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:
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:
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.
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 trustee’s 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 andout-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 trustee’s and Delaware trustee’s fees and legal expenses incurred in forming the trust, in connection with this initial public offering and related matters, as well as the Delaware trustee’s acceptance fee in the amount of $4,000. These costs will be deducted by the trust before distributions are made to trust unitholders.
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 trustee’s 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:
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 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.
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 trust’s 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:
The trustee would then sell all of the trust’s 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 trustee’s and the Delaware trustee’s compensation will be paid out of the trust’s 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.
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 trust’s 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.
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:
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.
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.
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 thelock-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 theselock-up arrangements. Upon the expiration of theselock-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:
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
the rule’s 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
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.
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 andnon-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 ornon-U.S. jurisdiction. Moreover, the discussion has only limited application to trust unitholders subject to specialized tax treatment such as, without limitation:
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:
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 trust’s 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.
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
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 unitholder’s net income from all investments, and (ii) the amount by which the trust unitholder’s 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 Sponsor’s 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.
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:
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 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
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 unitholder’s 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 trust’s 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 trust’s 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 unitholder’s entitlement to treat a portion of its receipts as return of principal if the Net Profits Interest is treated, in accordance with tax counsel’s 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 taxpayer’s 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
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 unitholder’s adjusted tax basis for the trust units sold. A U.S. trust unitholder’s adjusted tax basis in his trust units will be equal to the U.S. trust unitholder’s 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 unitholder’s 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 trust’s 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 unitholder’s 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 TONON-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 anon-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 thenon-U.S. trust unitholder is eligible for a lower rate under an applicable income tax treaty or the interest is effectively connected with thenon-U.S. trust unitholder’s conduct of a trade or
business in the United States, and in either case, thenon-U.S. trust unitholder provides appropriate certification. Anon-U.S. trust unitholder generally can meet the certification requirement by providing an IRSForm W-8BEN (in the case of a claim of treaty benefits) or aW-8 ECI (with respect to thenon-U.S. trust unitholder’s conduct of a U.S. trade or business). If anon-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, thenon-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 suchnon-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 anon-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 anon-U.S. trust unitholder on a sale of trust units will be subject to federal income tax only if:
Anon-U.S. trust unitholder will be subject to U.S. federal income tax on any gain allocable to thenon-U.S. trust unitholder upon the sale by the trust of all or any part of the Net Profits Interest, and distributions to thenon-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 tonon-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 thenon-U.S. trust unitholder. Anon-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 suchnon-U.S. trust unitholder complies with certain certification requirements (usually satisfied by providing a duly completed IRSForm 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 anon-U.S. trust unitholder’s U.S. federal income tax liability, provided certain required information is provided to the IRS.
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 thenon-U.S. trust unitholder properly certifies under penalties of perjury as to its foreign status and certain other conditions are met or thenon-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 anon-U.S. trust unitholder and certain other conditions are met, or thenon-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:
Any amount withheld under the backup withholding rules may be credited against thenon-U.S. trust unitholder’s 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 trust’s 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.
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 trust’s 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 trust’s 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 nonresident’s 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 trust’s 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.
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 plan’s particular circumstances before authorizing an investment in trust units. A fiduciary should consider:
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 plan’s 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.
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 their30-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 unitholder’s ownership of the trust units.
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
UNDERWRITING Subject to the terms and conditions in an underwriting agreement dated , 2011, the underwriters named below, for whom Raymond James & Associates, Inc.
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:
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
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.
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 INDEMNIFICATION VOC Sponsor 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
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.
The180-day period described in the preceding paragraphs will be extended if:
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:
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
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 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:
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 underwriter’s or any selling group member’s 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, plusout-of-pocket expenses, of the nature and in amounts customary in the industry for these financial services. DIRECTED UNIT PROGRAM At VOC Sponsor’s request, the underwriters have reserved up to 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.
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 SEC’s 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 Sponsor’s SEC filings, including the registration statement, at the SEC’s website at www.sec.gov.
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 featureand/or stratigraphic condition. Gross acresorgross 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.
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 acresornet 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 person’s interest is subject. Plugging and abandonment — Activities to remove production equipment and seal off a well at the end of a well’s 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
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 the12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of thefirst-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-oiland/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.
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 oiland/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.
INDEX TO FINANCIAL STATEMENTS
The audited combined financial statements of Predecessor can be found beginning onpage 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 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. /s/ Grant Thornton LLP Grant Thornton LLP Wichita, Kansas March 22, 2011
Predecessor Underlying Properties AND DIRECT OPERATING EXPENSES
The accompanying notes are an integral part of these combined statements.
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 Predecessor’s 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 underRegulation 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
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 trustee’s and Delaware trustee’s legal expenses incurred in forming the trust as well as the Delaware trustee’s 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 the12-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 same12-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.
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.
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
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
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 Predecessor’s reserves. The Standardized Measure relating to Predecessor’s proved reserves at December 31, 2008, 2009 and 2010 is shown below:
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 Predecessor’s 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
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 KEP’s 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. /s/ Grant Thornton LLP Grant Thornton LLP Wichita, Kansas March 22, 2011
Acquired Underlying Properties AND DIRECT OPERATING EXPENSES
The accompanying notes are an integral part of these statements.
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 KEP’s 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 underRule 3-05 ofRegulation 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 trustee’s and Delaware trustee’s legal expenses incurred in forming the trust as well as the Delaware trustee’s acceptance fee in the amount of $4,000. These costs will be deducted by the trust before distributions are made to trust
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 the12-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 same12-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
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
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, orPV-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.
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:
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
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 — Management’s 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.
UNAUDITED PRO FORMA STATEMENTS OF HISTORICAL REVENUES AND DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES
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 Trust’s 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. /s/ Grant Thornton LLP Grant Thornton LLP Wichita, Kansas March 22, 2011
VOC ENERGY TRUST
The accompanying notes are an integral part of this financial statement.
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.
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 Trust’s 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 Trustee’s 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 aunit-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 Trust’s 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 trust’s assets and income and will be directly taxable thereon as if no trust were in existence.
VOC Energy Trust NOTES TO STATEMENT OF ASSETS AND TRUST CORPUS — (Continued)
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.
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.
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.
VOC ENERGY TRUST
The accompanying notes are an integral part of the unaudited pro forma financial statement.
VOC ENERGY TRUST
The accompanying notes are an integral part of the unaudited pro forma financial statements.
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 Trust’s 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.
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:
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:
(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 trustee’s and Delaware trustee’s legal expenses incurred in forming the trust as well as the Delaware trustee’s
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 asset’s 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 Sponsor’s 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.
INFORMATION ABOUT VOC BRAZOS ENERGY PARTNERS, L.P. (VOC SPONSOR) The trust units are not interests in or obligations of VOC Sponsor
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.
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 Sponsor’s general partner:
Executive Management from Vess Oil J. Michael Vessis 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 William R. Horiganis 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 Gaudreauis 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 Hillis 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 Howarteris 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
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:
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
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
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 Sponsor’s 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.
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 “— Management’s 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 Predecessor’s 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 onpage 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,
2010, in the case of the pro forma statement of earnings information for the year ended December 31, 2010.
MANAGEMENT’S 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 “Management’s 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 pageVOC F-1. FACTORS THAT SIGNIFICANTLY AFFECT VOC SPONSOR’S RESULTS VOC Sponsor’s 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 Sponsor’s 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.
RESULTS OF OPERATIONS Set forth in the table below is a summary of VOC Predecessor’s financial data for the periods indicated.
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 In addition, at December 31, 2010, VOC Sponsor recorded a $0.3 million income for ineffectiveness of hedges compared to a
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 Sponsor’s 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 Sponsor’s outstanding debt balance decreased from $35.0 million to 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
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 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.
LIQUIDITY AND CAPITAL RESOURCES VOC Sponsor’s 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 Sponsor’s 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 Sponsor’s 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
calculation of payment due to the trust. From January 1, 2011 through December 31, 2013, VOC Sponsor’s crude oil price risk management position in swap contracts is as follows:
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 Sponsor’s 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 Sponsor’s 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 Sponsor currently anticipates that its development budget, which predominantly consists of workover drilling, secondary recovery projects and equipment, will be 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 Sponsor’s 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 Sponsor’s 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 bank’s Prime Rate. VOC Sponsor’s 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 Sponsor’s available borrowing base then utilized. Borrowings under the bank credit facility are secured by a lien on substantially all of VOC Sponsor’s assets and properties in Texas. The bank credit facility also contains restrictive covenants that may limit VOC Sponsor’s 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.
CONTRACTUAL OBLIGATIONS A summary of VOC Sponsor’s contractual obligations as of December 31, 2010 is provided in the following table.
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 Sponsor’s 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
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 company’s 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 Sponsor’s 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.
Oil and Natural Gas Reserve Quantities VOC Sponsor’s 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 awell-by-well basis. Reserves and their relation to estimated future net cash flows impact VOC Sponsor’s 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 Sponsor’s 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 entity’s 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 instrument’s fair market value. Any ineffective portion of the derivative instrument’s 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
costs are capitalized as part of the carrying amount of the related long-lived asset and amortized over the asset’s useful life. VOC Sponsor’s asset retirement obligations are primarily associated with the plugging of abandoned oil wells. NEW ACCOUNTING PRONOUNCEMENTS In January 2010, the FASB issued ASU2010-04, “Accounting for Various Topics — Technical Corrections to SEC Paragraphs ASU2010-04 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 ASU2010-06, “Improving Disclosures about Fair Value Measurements” (“ASU2010-06”), 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. ASU2010-06 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 ASU2010-09 (ASU2010-09), “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. ASU2010-09 is effective for interim or annual financial periods ending after June 15, 2010. The adoption of the provisions of ASU2010-09 did not have a material impact on our financial statements. In April 2010, the FASB issued ASU2010-14, “Accounting for Extractive Activities — Oil & Gas.” ASU2010-14 amendsparagraph 932-10-S99-1 due to SEC ReleaseNo. 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 ASU2010-21, “Accounting for Technical Amendments to Various SEC Rules and Schedules — Amendments to SEC Paragraphs Pursuant to ReleaseNo. 33-9026: Technical Amendments to Rules, Forms, Schedules and Codification of Financial Reporting Policies.” The ASU reflects changes made by the SEC in Final RulemakingRelease No. 33-9026, which was issued in April 2009 and amended SEC requirements inRegulation S-X andRegulation S-K and made changes to financial reporting requirements in response to the FASB’s 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 ASU2010-21 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 Sponsor’s potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future
losses, but rather indicators of reasonably possible losses. 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 Sponsor’s 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 Sponsor’s debt remained the same interest expense on an annual basis would have been $0.2 million higher.
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”) 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 andSchedule K-1’s, 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.
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 partner’s 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 partner’s 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 arm’s length sales, exchanges or dispositions of the general partner’s or such affiliate’s 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
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 Oil’s 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-partyout-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 Indemnitee’s 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 Indemnitee’s 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
limited partner’s or general partner’s 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.
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.
INDEX TO FINANCIAL STATEMENTS
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 Predecessor’s 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 Predecessor’s 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. /s/ Grant Thornton LLP Grant Thornton LLP Wichita, Kansas March 22, 2011
The accompanying notes are an integral part of these combined statements.
The accompanying notes are an integral part of these combined statements.
Predecessor For the years ended December 31, 2008, 2009 and 2010
The accompanying notes are an integral part of these combined statements.
The accompanying notes are an integral part of these combined statements.
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, LLC’s 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,
Predecessor NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued) For the years ended December 31, 2008, 2009 and 2010 LLC’s capital account or $42,277,581 was recorded as astep-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 theunit-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 theunit-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 the12-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.
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. Predecessor’s derivatives consist entirely of oil swap agreements, of which substantially all qualify as cash flow hedges. As such, all of Predecessor’s 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 Predecessor’s 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. Predecessor’s 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.
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 asset’s 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 Predecessor’s asset retirement obligations are primarily associated with the plugging and abandoning of oil and gas properties.
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 ASU2010-04, “Accounting for Various Topics — Technical Corrections to SEC Paragraphs”. ASU2010-04 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 ASU2010-06, “Improving Disclosures about Fair Value Measurements” (“ASU2010-06”), 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. ASU2010-06 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 ASU2010-09 (ASU2010-09), “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. ASU2010-09 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 ASU2010-14, “Accounting for Extractive Activities — Oil & Gas.” ASU2010-14 amendsparagraph 932-10-S99-1 due to SEC ReleaseNo. 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 ASU2010-21, “Accounting for Technical Amendments to Various SEC Rules and Schedules — Amendments to SEC Paragraphs Pursuant to ReleaseNo. 33-9026: Technical Amendments to Rules, Forms, Schedules and Codification of Financial Reporting Policies.” The ASU reflects changes made by the SEC in Final RulemakingRelease No. 33-9026, which was issued in April 2009 and amended SEC requirements inRegulation S-X andRegulation S-K and made changes to financial reporting requirements in response to the FASB’s issuance of SFAS No. 141(R), “Business Combinations” (FASB ASC 805), and SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an
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:
Predecessor’s 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:
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:
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.
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:
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 Note’s interest rate is adjusted periodically based on the interest rate base (either Eurodollar Rate of one, two, three or six month periods or the bank’s base rate) plus an applicable margin based on a percentage of borrowing base usage. The note’s 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 Predecessor’s credit agreement with the bank. Borrowing Base loans: Predecessor’s 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.
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 Predecessor’s 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 Bank’s 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
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, Predecessor’s 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.
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:
Predecessor’s 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, Predecessor’s 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.
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:
Following is a summary of balances due to/from related parties:
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 Predecessor’s 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 Predecessor’s oil and gas leases, filed suit to recover these funds which were estimated to be $1,438,121 for Predecessor’s 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
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:
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 Predecessor’s 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.
Predecessor NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued) For the years ended December 31, 2008, 2009 and 2010 NOTE G — ASSET RETIREMENT OBLIGATIONS The Predecessor’s 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:
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.
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:
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 Predecessor’s 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.
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:
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 the12-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 same12-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
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
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 Predecessor’s reserves.
Predecessor NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued) For the years ended December 31, 2008, 2009 and 2010 The estimated Standardized Measure relating to Predecessor’s proved reserves at December 31, 2008, 2009 and 2010 is shown below:
The following table sets forth the changes in the Standardized Measure applicable to Predecessor’s 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
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, “Management’s 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.
The accompanying notes are an integral part of these unaudited pro forma financial statements.
The accompanying notes are an integral part of these unaudited pro forma financial statements.
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 partner’s 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
obligations and distributions using proceeds from the offering. The pro forma adjustments included in the unaudited pro forma balance sheet are as follows:
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 Sponsor’s 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:
The pro forma adjustments included in the unaudited pro forma statement of earnings are as follows:
December 28, 2010 Mr. Bill Horigan VOC Brazos Energy Partners, L.P. 1700 Waterfront Pkwy, Bldg 500 Wichita, KS 67206
Dear Mr. Horigan: As requested, this report was prepared on December 28, 2010 forVOC 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) ofRegulation S-K and other rules of theSecurities and Exchange Commission(SEC). The results of this evaluation are presented in the accompanying tabulations, with a composite summary of the values presented below:
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 I’s, Summary Plots and Tables II. The Table I’s 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 a12-month average price, calculated as the unweighted arithmetic average of thefirst-day-of-the-month price for each month within the12-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.
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 Company’s 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.
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 checkand/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. Anon-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities havenot 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
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
Appendix
Appendix
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 andmay 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 obtainingand/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
commonly newly developedand/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
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 the12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of thefirst-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
“(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
“(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 CommissionRegulation 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 ofRegulation S-K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant ispermitted, 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
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
December 28, 2010 Mr. Bill Horigan VOC Kansas Energy Partners, LLC 1700 Waterfront Pkwy, Bldg 500 Wichita, Kansas 67206
Dear Mr. Horigan: As requested, this report was prepared on December 28, 2010 forVOC 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) ofRegulation S-K and other rules of theSecurities and Exchange Commission(SEC). The results of this evaluation are presented in the accompanying tabulations, with a composite summary of the values presented below:
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 I’s, Summary Plots and Tables II. The Table I’s 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 a12-month average price, calculated as the unweighted arithmetic average of thefirst-day-of-the-month price for each month within the12-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.
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 Company’s 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
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 checkand/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. Anon-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities havenot 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
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
Appendix
Appendix
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 andmay 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 obtainingand/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
commonly newly developedand/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
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 the12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of thefirst-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
“(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
“(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 CommissionRegulation 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 ofRegulation S-K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant ispermitted, 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
March 9, 2011 Mr. Bill Horigan VOC Brazos Energy Partners, L.P. 1700 Waterfront Pkwy, Bldg 500 Wichita, KS 67206
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) ofRegulation S-K and other rules of theSecurities and Exchange Commission(SEC). A composite summary of the proved reserves is presented below.
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 a12-month average price, calculated as the unweighted arithmetic average of thefirst-day-of-the-month price for each month within the12-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.
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 checkand/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
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. Anon-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)
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
Appendix
Appendix
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 andmay 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 obtainingand/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
commonly newly developedand/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
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 the12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of thefirst-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
“(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
“(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 CommissionRegulation 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 ofRegulation S-K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant ispermitted, 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
10,785,000 Trust Units VOC ENERGY TRUST PROSPECTUS Joint Book-Runners
, 2011 PART II INFORMATION NOT REQUIRED IN PROSPECTUS
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.
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.
None.
(a) Exhibits. The following documents are filed as exhibits to this registration statement:
(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 byForm 10-K for the first full fiscal year of operations of the trust.
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 VOC Brazos Energy Partners, L.P.
By: /s/ J. MICHAEL VESS Name: J. Michael Vess Title: Designated Representative and Sole Member of Board of Directors
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 VOC Energy Trust
By: /s/ MICHAEL J. Name: Michael J. Title:
INDEX TO EXHIBITS
|