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, 20092010 and the average net production attributable to the Underlying Properties for the nine-month periodyear ended September 30,December 31, 2010.
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| • | annual cash available for distribution to the trust is less than $1 million for each of two consecutive years; |
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| • | the holders of a majority of the outstanding trust units vote in favor of dissolution; or |
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| • | the trust is judicially dissolved. |
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The trustee would then sell all of the trust’s assets, either by private sale or public auction, and distribute the net proceeds of the sale to the trust unitholders.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.
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DESCRIPTION OF THE TRUST UNITS
Each trust unit is a unit of beneficial interest in the trust and is entitled to receive cash distributions from the trust on a pro rata basis. Each trust unitholder has the same rights regarding each of his trust units as every other trust unitholder has regarding his units. The trust units will be in book-entry form only and will not be represented by certificates. The trust will have 16,540,000 trust units outstanding upon completion of this offering.
DISTRIBUTIONS AND INCOME COMPUTATIONS
Each quarter, the trustee will determine the amount of funds available for distribution to the trust unitholders. Available funds are the excess cash, if any, received by the trust from the Net Profits Interest and other sources (such as interest earned on any amounts reserved by the trustee) that quarter, over the 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.
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Each trust unitholder and his representatives may examine, for any proper purpose, during reasonable business hours, the records of the trust and the trustee.
LIABILITY OF TRUST UNITHOLDERS
Under the Delaware Statutory Trust Act, trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the state of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.
VOTING RIGHTS OF TRUST UNITHOLDERS
The trustee or trust unitholders owning at least 10% of the outstanding trust units may call meetings of trust unitholders. The trust will be responsible for all costs associated with calling a meeting of trust unitholders unless such meeting is called by the trust unitholders, in which case the trust unitholders will be responsible for all costs associated with calling such meeting of trust unitholders. Meetings must be held in such location as is designated by the trustee in the notice of such meeting. The trustee must send written notice of the time and place of the meeting and the matters to be acted upon to all of the trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of trust units outstanding must be present or represented to have a quorum. Each trust unitholder is entitled to one vote for each trust unit owned.
Unless otherwise required by the trust agreement, a matter may be approved or disapproved by the vote of a majority of the trust units held by the trust unitholders at a meeting where there is a quorum. This is true, even if a majority of the total trust units did not approve it. The affirmative vote of the holders of a majority of the outstanding trust units is required to:
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| • | dissolve the trust; |
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| • | remove the trustee or the Delaware trustee; |
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| • | amend the trust agreement (except with respect to certain matters that do not adversely affect the rights of trust unitholders in any material respect); |
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| • | merge or consolidate the trust with or into another entity; or |
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| • | approve the sale of all or any material part of the assets of the trust. |
In addition, certain amendments to the trust agreement may be made by the trustee without approval of the trust unitholders. See “Description of the trust agreement — Creation and organization of the trust; amendments.” The trustee must consent before all or any part of the trust assets can be sold except in connection with the dissolution of the trust or limited sales directed by VOC Sponsor in conjunction with its sale of Underlying Properties.
COMPARISON OF TRUST UNITS AND COMMON STOCK
Trust unitholders have more limited voting rights than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for annual or other periodic re-election of the trustee.
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You should also be aware of the following ways in which an investment in trust units is different from an investment in common stock of a corporation.
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| | Trust Units | | Common Stock |
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Voting | | The trust agreement provides voting rights to trust unitholders to remove and replace the trustee and to approve or disapprove major trust transactions. | | Corporate statutes provide voting rights to stockholders to elect directors and to approve or disapprove major corporate transactions. |
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Income Tax | | The trust is not subject to income tax; trust unitholders are subject to income tax on their pro rata share of trust income, gain, loss and deduction. | | Corporations are taxed on their income and their stockholders are taxed on dividends. |
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Distributions | | Substantially all of the cash receipts of the trust is required to be distributed to trust unitholders. | | Stockholders receive dividends at the discretion of the board of directors. |
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Business and Assets | | The business of the trust is limited to specific assets with a finite economic life. | | A corporation conducts an active business for an unlimited term and can reinvest its earnings and raise additional capital to expand. |
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Fiduciary Duties | | The trustee shall not be liable to the trust unitholders for any of its acts or omissions absent its own fraud, gross negligence or bad faith. | | Officers and directors have a fiduciary duty of loyalty to stockholders and a duty to use due care in management and administration of a corporation. |
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TRUST UNITS ELIGIBLE FOR FUTURE SALE
GENERAL
Prior to this offering, there has been no public market for the trust units. Sales of substantial amounts of the trust units in the open market, or the perception that those sales could occur, could adversely affect prevailing market prices.
Upon completion of this offering, there will be outstanding 16,540,000 trust units. All of the 10,785,000 trust units sold in this offering, or 12,402,750 trust units if the underwriters exercise their option to purchase additional trust units in full, will be freely tradable without restriction under the Securities Act of 1933, as amended (the “Securities Act”). All of the trust units outstanding other than the trust units sold in this offering (a total of 5,755,000 trust units, or 4,137,250 trust units if the underwriters exercise their option to purchase additional trust units in full) will be “restricted securities” within the meaning of Rule 144 under the Securities Act and may not be sold other than through registration under the Securities Act or pursuant to an exemption from registration, subject to the restrictions on transfer contained in 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:
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| • | 1.0% of the total number of the securities outstanding, or |
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| • | the average weekly reported trading volume of the trust units for the four calendar weeks prior to the sale. |
Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about the trust. A person who is not deemed to have been an affiliate of VOC Sponsor or the trust at any time during the three months preceding a sale, and who has beneficially owned his trust units for at least six months (provided the trust is in compliance with the current public information requirement) or one year (regardless of whether the trust is in compliance with the current public information requirement), would be entitled to sell trust units under Rule 144 without regard to
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the rule’s public information requirements, volume limitations, manner of sale provisions and notice requirements.
REGISTRATION RIGHTS
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 trust will agree to register the trust units it holds for the benefit ofsold to VOC Partners, LLC. Specifically, the trust will agree:
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| • | subject to the restrictions described above under“— Lock-up agreements” and under “Underwriting —Lock-up agreements,” to use its reasonable best efforts to file a registration statement, including, if so requested, a shelf registration statement, with the SEC as promptly as practicable following receipt of a notice requesting the filing of a registration statement from holders representing a majority of the then outstanding registrable trust units; |
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| • | to use its reasonable best efforts to cause the registration statement or shelf registration statement to be declared effective under the Securities Act as promptly as practicable after the filing thereof; and |
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| • | to continuously maintain the effectiveness of the registration statement under the Securities Act for 90 days (or for three years if a shelf registration statement is requested) after the effectiveness thereof or until the trust units covered by the registration statement have been sold pursuant to such registration statement or until all registrable trust units: |
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| • | have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities;” |
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| • | have been sold in a private transaction in which the transferor’s rights under the registration rights agreement are not assigned to the transferee of the trust units; or |
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| • | become eligible for resale pursuant to Rule 144 (or any similar rule then in effect under the Securities Act). |
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 SponsorPartners, LLC will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the trust, which will be borne by the trust, and any underwriting discounts and commissions, which will be borne by VOC Partners, LLC.
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FEDERAL INCOME TAX CONSEQUENCES
U.S. FEDERAL INCOME TAX CONSEQUENCES
The following is a discussion of the material U.S. federal income tax considerations that may be relevant to prospective trust unitholders and, unless otherwise noted in the following discussion, expresses the opinion of Vinson & Elkins L.L.P., insofar as it relates to matters of law and legal conclusions. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing (and, to the extent noted, proposed) Treasury regulations thereunder, and current administrative rulings and court decisions, all of which are subject to change or different interpretation at any time, possibly with retroactive effect. Subsequent changes in such authorities may cause the U.S. federal income tax consequences to vary substantially from the consequences described below. No attempt has been made in the following discussion to comment on all U.S. federal income tax matters affecting the trust or the trust unitholders.
The following discussion is limited to trust unitholders who purchase the trust units upon the initial issuance at the initial issue price (which will equal the first price at which a substantial amount of trust units are sold to the public for cash) and who hold the trust units as “capital assets” (generally, property held for investment). All references to “trust unitholders” (including U.S. trust unitholders 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:
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| • | banks, insurance companies or other financial institutions; |
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| • | trust unitholders subject to the alternative minimum tax; |
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| • | tax-exempt organizations; |
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| • | dealers in securities or commodities; |
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| • | regulated investment companies; |
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| • | traders in securities that elect to use amark-to-market method of accounting for their securities holdings; |
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| • | non-U.S. trust unitholders (as defined below) that are “controlled foreign corporations” or “passive foreign investment companies”; |
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| • | persons that are S-corporations, partnerships or other pass-through entities; |
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| • | persons that own their interest in the trust units through S-corporations, partnerships or other pass-through entities; |
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| • | persons that at any time own more than 5% of the aggregate fair market value of the trust units; |
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| • | expatriates and certain former citizens or long-term residents of the United States; |
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| • | U.S. trust unitholders (as defined below) whose functional currency is not the U.S. dollar; |
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| • | persons who hold the trust units as a position in a hedging transaction, “straddle,” “conversion transaction” or other risk reduction transaction; or |
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| • | persons deemed to sell the trust units under the constructive sale provisions of the Code. |
Prospective investors are urged to consult their own tax advisors as to the particular tax consequences to them of the ownership and disposition of an investment in trust units, including the applicability of any U.S. federal income, federal estate or gift tax, state, local and foreign tax laws, changes in applicable tax laws and any pending or proposed legislation.
As used herein, the term “U.S. trust unitholder” means a beneficial owner of trust units that for U.S. federal income tax purposes is:
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| • | an individual who is a citizen of the United States or who is a resident of the United States for U.S. federal income tax purposes, |
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| • | a corporation, or an entity treated as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the United States, a state thereof or the District of Columbia, |
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| • | an estate the income of which is subject to U.S. federal income taxation regardless of its source, or |
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| • | a trust if it is subject to the primary supervision of a U.S. court and the control of one or more United States persons (as defined for U.S. federal income tax purposes) or that has a valid election in effect under applicable U.S. Treasury regulations to be treated as a United States person. |
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.
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The remainder of the discussion below is based on Vinson & Elkins L.L.P.’s opinion that the trust will be classified as a grantor trust for federal income tax purposes.
Reporting Requirements for Widely-Held Fixed Investment Trusts
Under Treasury Regulations, the trust is classified as a widely-held fixed investment trust. Those Treasury Regulations require the sharing of tax information among trustees and intermediaries that hold a trust interest on behalf of or for the account of a beneficial owner or any representative or agent of a trust interest holder of fixed investment trusts that are classified as widely-held fixed investment trusts. These reporting requirements provide for the dissemination of trust tax information by the trustee to intermediaries who are ultimately responsible for reporting the investor-specific information through Form 1099 to the investors and the IRS. Every trustee or intermediary that is required to file a Form 1099 for a trust unitholder must furnish a written tax information statement that is in support of the amounts as reported on the applicable Form 1099 to the trust unitholder. Any generic tax information provided by the trustee of the trust is intended to be used only to assist trust unitholders in the preparation of their federal and state income tax returns.
Direct Taxation of Trust Unitholders
Because the trust will be treated as a grantor trust for U.S. federal income tax purposes, trust unitholders will be treated for such purposes as owning a direct interest in the assets of the trust, and each trust unitholder will be taxed directly on his pro rata share of the income and gain attributable to the assets of the trust and will be entitled to claim his pro rata share of the deductions and expenses attributable to the assets of the trust (subject to certain limitations discussed below). Information returns will be filed as required by the widely held fixed investment trust rules, reporting to the trust unitholders all items of income, gain, loss, deduction and credit, which will be allocated based on record ownership on the quarterly record dates and must be included in the tax returns of the trust unitholders. Income, gain, loss, deduction and credits attributable to the assets of the trust will be taken into account by trust unitholders consistent with their method of accounting and without regard to the taxable year or accounting method employed by the trust.
Following the end of each quarter, the trustee will determine the amount of funds available as of the end of such quarter for distribution to the trust unitholders and will make distributions of available funds, if any, to the unitholders on or about the 45th day of the month following the end of the quarter to the unitholders of record on the last business30th day following the end of such quarter. In certain circumstances, however, a trust unitholder will not receive thea distribution of cash attributable to such income.the income from a quarter. For example, if the trustee establishes a reserve or borrows money to satisfy liabilities of the trust, income associated with the cash used to establish that reserve or to repay that loan must be reported by the trust unitholder, even though that cash is not distributed to him.
As described above, the trust will allocate items of income, gain, loss, deductions and credits to trust unitholders based on record ownership on the quarterly record dates. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the trust should be determined and allocated on a daily or prorated basis, which could require adjustments to the tax returns of the unitholders affected by the issue and result in an increase in the administrative expense of the trust in subsequent periods.
Tax Rates
Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to
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long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.
The recently enacted Health Care and Education Reconciliation Act of 2010 will impose a 3.8% Medicare tax on certain investment income earned by individuals and certain estates and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income would generally include interest income derived from investments such as the trust units and gain realized by a trust unitholder from a sale of trust units. In the case of an individual, the tax will be imposed on the lesser of (i) the trust 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.
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TAX CONSEQUENCES TO U.S. TRUST UNITHOLDERS
Tax Treatment of Net Profits Interest
Under the CPDI regulations, a U.S. trust unitholder generally will be required to accrue income on the Net Profits Interest in the amounts described below, regardless of whether the U.S. trust unitholder uses the cash or accrual method of tax accounting.
The CPDI regulations provide that a U.S. trust unitholder must accrue an amount of ordinary interest income for U.S. federal income tax purposes, for each accrual period prior to and including the maturity date of the debt instrument that equals:
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| • | the product of (i) the adjusted issue price (as defined below) of the debt instrument represented by ownership of trust units as of the beginning of the accrual period; and (ii) the comparable yield to maturity (as defined below) of such debt instrument, adjusted for the length of the accrual period; |
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| • | divided by the number of days in the accrual period; and |
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| • | multiplied by the number of days during the accrual period that the trust unitholder held the trust units. |
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 %, compounded semi-annually. The CPDI regulations require that the trust provide to trust unitholders, solely for determining the amount of interest accruals for U.S. federal income tax purposes, a schedule of the projected amounts of payments, which are referred to as projected payments, on the debt instrument held by the trust. These payments set forth on the schedule must produce a total return on such debt instrument equal to its comparable yield. Amounts treated as interest under the CPDI regulations are treated as original issue discount for all purposes of the Code.
As required by the CPDI regulations, for U.S. federal income tax purposes, each holder of trust units must use the comparable yield and the schedule of projected payments as described above in determining its interest accruals, and the adjustments thereto described below, in respect of the debt instrument held by the trust. You may obtain the projected payment schedule by submitting a written request for such information to VOC Brazos at 1700 Waterfront Parkway, Building 500, Wichita, Kansas 67206, Attention: Chief Financial Officer.
Our determinations of the comparable yield and the projected payment schedule are not binding on the IRS and it could challenge such determinations. If it did so, and if any such
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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 burdened properties.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
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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 percent30% 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
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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:
| | |
| • | the gain is, or is treated as, effectively connected with business conducted by thenon-U.S. trust unitholder in the United States, and in the case of an applicable tax treaty, is attributable to a U.S. permanent establishment maintained by thenon-U.S. trust unitholder; |
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| • | thenon-U.S. trust unitholder is an individual who is present in the United States for at least 183 days in the year of the sale; or |
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| • | thenon-U.S. trust unitholder owns currently or owned at certain earlier times directly or by applying certain attribution rules, more than 5% of the trusts units. |
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.
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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:
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| • | is a United States person; |
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| • | derives 50% or more of its gross income for certain periods from the conduct of a trade or business in the United States; |
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| • | is a controlled foreign corporation for U.S. federal income tax purposes; or |
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| • | is a foreign partnership that, at any time during its taxable year, has more than 50% of its income or capital interests owned by United States persons or is engaged in the conduct of a U.S. trade or business. |
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.
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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.
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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:
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| • | whether the investment satisfies the prudence requirements of Section 404(a)(1)(B) of ERISA; |
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| • | whether the investment satisfies the diversification requirements of Section 404(a)(1)(C) of ERISA; and |
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| • | whether the investment is in accordance with the documents and instruments governing the plan as required by Section 404(a)(1)(D) of ERISA. |
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.
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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 no later than 45 days afterfollowing 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.
| | | | | | | | | | | | | | | | | | | | |
| | Ownership of Trust
| | Number of
| | Ownership of Trust
|
| | Units Before Offering | | Trust Units
| | Units After Offering (1) |
Selling Trust Unitholders | | Number | | Percentage | | Being Offered | | Number | | Percentage |
|
VOC Sponsor | | | | | | | 100 | % | | | | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | |
| | Ownership of Trust
| | Number of
| | Ownership of Trust
|
| | Units Before Offering | | Trust Units
| | Units After Offering (1) |
Selling Trust Unitholders | | Number | | Percentage | | Being Offered | | Number | | Percentage |
|
VOC Sponsor | | | 16,540,000 | | | | 100 | % | | | 12,402,750 | (2) | | | — | | | | — | |
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(1) | | Gives effect to the sale of trust units to VOC Partners, LLC 45 days following the closing of the offering. |
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(2) | | Includes 1,617,750 trust units subject to purchase by the underwriters’ pursuant to their 30-day option to purchase additional 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 pursuant to the Unit Purchase Agreement, the effect of such disposal on future market prices, if any, of market sales of such remaining trust units or the availability of trust units for sale cannot be predicted. Nevertheless, sales of substantial amounts of trust units in the public market could adversely affect future market prices.
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UNDERWRITING
Subject to the terms and conditions in an underwriting agreement dated , 2011, the underwriters named below, for whom Raymond James & Associates, Inc., is acting as representative, have severally agreed to purchase from VOC Sponsor the number of trust units set forth opposite their names:
| | | | |
| | Number of
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Underwriter | | Trust Units |
|
Raymond James & Associates, Inc. | | | | |
| | | | |
Total | | | 10,785,000 | |
| | | | |
The underwriting agreement provides that the obligations of the underwriters to purchase and accept delivery of the trust units offered by this prospectus are subject to approval by their counsel of legal matters and to certain other customary conditions set forth in the underwriting agreement, including:
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| • | the accuracy of representations and warranties made by VOC Sponsor to the underwriters; |
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| • | there having been no material adverse change in financial markets or in the condition (financial or otherwise), business, prospects, management or results of operations of VOC Sponsor or the trust; and |
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| • | VOC Sponsor’s delivery of customary closing documents, and the delivery of legal opinions, to the underwriters. |
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.
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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.
| | | | | | | | | | | | |
| | Per Unit | | | No Exercise | | | Full Exercise | |
|
Public offering price | | $ | | | | $ | | | | $ | | |
Underwriting discounts and commissions | | | | | | | | | | | | |
Proceeds, before expenses, to VOC Sponsor | | | | | | | | | | | | |
VOC Sponsor will pay Raymond James & Associates, Inc. a structuring fee of $ (or $ if0.5% of the underwriters exercise their option to purchase additional trust units)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 $ (exclusive of underwriting discounts, commissions and structuring fees). This offering is being made in compliance with Rule 2310 of the Financial Industry Regulatory Authority, Inc., or “FINRA.” In no event will the maximum amount of compensation to be paid to FINRA members of the Financial Industry Regulatory Authority, Inc., or “FINRA,” in connection with this offering exceed 10% plus 0.5% for bona fide due diligence expenses.of the offering proceeds.
INDEMNIFICATION
VOC Sponsor has agreed to indemnify the underwriters and persons who control the underwriters against certain liabilities that may arise in connection with this offering, including liabilities under the Securities Act and liabilities arising from breaches of representations and warranties contained in the underwriting agreement.
LOCK-UP AGREEMENTS
VOC Sponsor and certain of its affiliates, including VOC Partners, LLC, have agreed with the underwriters, for a period of 180 days after the date of this prospectus, without the prior written consent of Raymond James & Associates, Inc.:
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| • | not to offer, sell, contract to sell, announce the intention to sell or pledge any of the trust units; |
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| • | not to grant or sell any option or contract to purchase any of the trust units; |
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| • | not to enter into any swap or other agreement that transfers any of the economic consequences of ownership of or otherwise transfer or dispose of, directly or indirectly, any of the trust units; and |
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| • | not to enter into any hedging, collar or other transaction or arrangement that is designed or reasonably expected to lead to or result in a transfer, in whole or in part, of any of the economic consequences of ownership of the trust units, whether or not such transfer would be for any consideration. |
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.
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Raymond James & Associates, Inc. may, in its discretion and at any time without notice, release all or any portion of the securities subject to these agreements. Raymond James & Associates, Inc. does not have any present intent or any understanding to release all or any portion of the securities subject to these agreements.
The180-day period described in the preceding paragraphs will be extended if:
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| • | during the last 17 days of the180-day period, the trust issues a release concerning earnings or announces material news or a material event relating to the trust occurs; or |
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| • | prior to the expiration of the180-day period, the trust announces that it will release distributable cash during the16-day period beginning on the last day of the180-day period, in which case the restrictions described in the preceding paragraphs will continue to apply until the expiration of the18-day period beginning on the issuance of the earnings release, the announcement of the material news or the occurrence of the material event. |
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, no later than 45 days following the closing of this offering.
STABILIZATION
Until this offering is completed, rules of the SEC may limit the ability of the underwriters and various selling group members to bid for and purchase the trust units. As an exception to these rules and in accordance with Regulation M under the Exchange Act, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of the trust units in order to facilitate this offering of trust units, including:
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| • | syndicate covering transactions,transactions; |
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| • | imposition of penalty bids,bids; and |
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| • | purchases to cover positions created by short sales. |
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.
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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 intends to applyhas applied to have the units approved for listing on the New York Stock Exchange under the symbol “VOC.” In connection with the listing of the trust units on the New York Stock Exchange, the underwriters will undertake to sell round lots of 100 units or more to a minimum of 400 beneficial owners.
IPO PRICING
Prior to this offering, there has been no public market for the trust units. Consequently, the initial public offering price for the trust units will be determined by negotiations among VOC Sponsor and the underwriters. The primary factors to be considered in determining the initial public offering price will be:
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| • | estimates of distributions to trust unitholders,unitholders; |
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| • | overall quality of the oil and natural gas properties attributable to the Underlying Properties,Properties; |
| | |
| • | industry and market conditions prevalent in the energy industry,industry; |
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| • | the information set forth in this prospectus and otherwise available to the representatives; and |
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| • | the general conditions of the securities markets at the time of this offering. |
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
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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 % of the units being offered by this prospectus for sale at the initial offering price to VOC Sponsor’s limited partners, executive management team (certain officers and employees of Vess Oil on behalf of VOC Sponsor’s general partner) and certain other persons associated with VOC Sponsor, as designated by VOC Sponsor. The sales will be made by Raymond James & Associates, Inc. through a directed unit program. We do not know if these persons will choose to purchase all or any portion of these reserved units, but any purchases they do make will reduce the number of units available to the general public. To the extent the allotted reserved units are not purchased in the directed unit program, we will offer these units to the general public on the same basis as all other units offered by this prospectus. These persons must commit to purchase no later than before the open of business on the day following the date of this prospectus, but in any event, these persons are not obligated to purchase units. Any members of VOC Sponsor’s limited partners, executive management team or other persons associated with VOC Sponsor purchasing reserved units will be subject to a lock-up agreement for up to days after the date of this prospectus. VOC Sponsor has agreed to indemnify Raymond James & Associates, Inc. against certain liabilities and expenses, including liabilities under the Securities Act of 1933, as amended, in connection with the sales of the reserved units.
FINRA RULES
Because FINRA is expected to view the trust units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA Conduct Rules. Investor suitability with respect to the trust units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.
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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, 20092010 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.
124119
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.
120
Mcf — One thousand cubic feet of natural gas.
125
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
121
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
126
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.
122
Recompletion — The completion for production of an existing well bore in another formation from which that well has been previously completed.
127
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.
128123
INDEX TO FINANCIAL STATEMENTS
| | | | |
PREDECESSOR UNDERLYING PROPERTIES: | | | | |
| | | F-2 | |
| | | F-3 | |
| | | F-4 | |
ACQUIRED UNDERLYING PROPERTIES: | | | | |
| | | F-10 | |
| | | F-11 | |
| | | F-12 | |
| | | | |
| | | F-18F-17 | |
| | | F-19F-18 | |
VOC ENERGY TRUST: | | | | |
| | | F-20F-19 | |
| | | F-21F-20 | |
| | | F-22F-21 | |
| | | | |
| | | F-25F-24 | |
| | | F-26F-25 | |
| | | F-27F-26 | |
| | | F-28F-27 | |
The audited combined financial statements of Predecessor can be found beginning onpage VOC F-1.
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of VOC Brazos Energy Partners, L.P.:
We have audited the accompanying combined statements of historical revenues and direct operating expenses of the Predecessor Underlying Properties, consisting of the Underlying Properties of VOC Brazos Energy Partners, L.P. (“VOC Brazos”) and the Underlying Properties of VOC Kansas Energy Partners, L.L.C. under common control with VOC Brazos, for each of the three years in the period ended December 31, 2009.2010. 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, 2009,2010, in conformity with accounting principles generally accepted in the United States of America.
Grant Thornton LLP
Wichita, Kansas
December 29, 2010
March 22, 2011
F-2
Predecessor Underlying Properties
AND DIRECT OPERATING EXPENSES
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | | Nine Months Ended September 30, | |
| | 2007 | | | 2008 | | | 2009 | | | 2009 | | | 2010 | |
| | | | | | | | | | | (Unaudited) | |
|
Revenues: | | | | | | | | | | | | | | | | | | | | |
Oil sales | | $ | 26,040,079 | | | $ | 36,632,381 | | | $ | 22,757,639 | | | $ | 15,019,562 | | | $ | 27,383,690 | |
Natural gas sales | | | 2,494,599 | | | | 3,349,695 | | | | 1,510,884 | | | | 1,044,777 | | | | 1,856,506 | |
Hedge and other derivative activity | | | (7,244,552 | ) | | | (7,784,517 | ) | | | 1,477,248 | | | | 1,880,305 | | | | (150,626 | ) |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 21,290,126 | | | | 32,197,559 | | | | 25,745,771 | | | | 17,944,644 | | | | 29,089,570 | |
| | | | | | | | | | | | | | | | | | | | |
Bad debt expense (recovery) | | | — | | | | 1,726,655 | | | | (719,061 | ) | | | (719,061 | ) | | | — | |
Direct operating expenses: | | | | | | | | | | | | | | | | | | | | |
Lease operating expenses | | | 6,586,226 | | | | 7,667,332 | | | | 6,787,857 | | | | 5,053,546 | | | | 5,228,613 | |
Production and property taxes | | | 1,874,237 | | | | 2,531,660 | | | | 1,646,052 | | | | 1,257,919 | | | | 1,918,959 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 8,460,463 | | | | 10,198,992 | | | | 8,433,909 | | | | 6,311,465 | | | | 7,147,572 | |
| | | | | | | | | | | | | | | | | | | | |
Excess of revenues over direct operating expenses | | $ | 12,829,663 | | | $ | 20,271,912 | | | $ | 18,030,923 | | | $ | 12,352,240 | | | $ | 21,941,998 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | Year Ended December 31, | |
| | 2008 | | | 2009 | | | 2010 | |
|
Revenues: | | | | | | | | | | | | |
Oil sales | | $ | 36,632,381 | | | $ | 22,757,639 | | | $ | 36,914,333 | |
Natural gas sales | | | 3,349,695 | | | | 1,510,884 | | | | 2,396,637 | |
Hedge and other derivative income (expense) | | | (7,784,517 | ) | | | 1,477,248 | | | | (707,371 | ) |
| | | | | | | | | | | | |
Total | | | 32,197,559 | | | | 25,745,771 | | | | 38,603,599 | |
| | | | | | | | | | | | |
Bad debt expense (recovery) | | | 1,726,655 | | | | (719,061 | ) | | | — | |
Direct operating expenses: | | | | | | | | | | | | |
Lease operating expenses | | | 7,667,332 | | | | 6,787,857 | | | | 7,325,042 | |
Production and property taxes | | | 2,531,660 | | | | 1,646,052 | | | | 2,720,313 | |
| | | | | | | | | | | | |
Total | | | 10,198,992 | | | | 8,433,909 | | | | 10,045,355 | |
| | | | | | | | | | | | |
Excess of revenues over direct operating expenses | | $ | 20,271,912 | | | $ | 18,030,923 | | | $ | 28,558,244 | |
| | | | | | | | | | | | |
The accompanying notes are an integral part of these combined statements.
F-3
Predecessor Underlying Properties
AND DIRECT OPERATING EXPENSES
For the years ended December 31, 2007, 2008, and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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 $120,518, $269,139, $463,295 $242,965 and $111,576$204,575 for the years ended December 31, 2007, 2008, and 2009 and for the nine months ended September 30, 2009 and 2010, (unaudited), 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
F-4
Predecessor Underlying Properties
NOTES TO COMBINED STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
overhead expenses. In the future, Vess Oil Corporation will provide these overhead services to KEP. Furthermore, trust administrative expenses are anticipated to aggregate approximately $900,000 for 2011. Administrative expenses for subsequent years could be greater or less
F-4
Predecessor Underlying Properties
NOTES TO COMBINED STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2008, 2009 and 2010
depending on future events that cannot be predicted. Included in the $900,000 annual estimate is an annual administrative fee of $150,000 for the trustee and an annual administrative fee of $2,500 for the Delaware trustee as well as an annual administrative fee payable to VOC Sponsor, which fee will total $75,000 in 2011 and will increase by 4% each year beginning in January 2012. See “The trust.” The trust will pay, out of the first cash payment received by the trust, the 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.
The accompanying Combined Statements of Historical Revenues and Direct Operating Expenses for the nine months ended September 30, 2009 and 2010 are unaudited. In the opinion of management of VOC Brazos, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation on the basis described above.
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
F-5
Predecessor Underlying Properties
NOTES TO COMBINED STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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.
F-5
Predecessor Underlying Properties
NOTES TO COMBINED STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2008, 2009 and 2010
The 2006, 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, 2006, 2007, 2008, 2009 and 20092010 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 accounting literature for OilSEC rules and Gas Extractive Activities.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
F-6
Predecessor Underlying Properties
NOTES TO COMBINED STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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.
ESTIMATED QUANTITIES OF OIL AND GAS RESERVES
| | | | | | | | |
| | Oil
| | | Gas
| |
| | (Bbls) | | | (Mcf) | |
|
Proved reserves: | | | | | | | | |
Balance at December 31, 2006 | | | 7,994,492 | | | | 4,241,321 | |
Revisions of previous estimates | | | (332,769 | ) | | | 190,995 | |
Purchase of minerals in place | | | 169,779 | | | | — | |
Extensions and discoveries | | | 9,883 | | | | 332,593 | |
Production | | | (386,879 | ) | | | (390,593 | ) |
| | | | | | | | |
Balance at December 31, 2007 | | | 7,454,506 | | | | 4,374,316 | |
Revisions of previous estimates | | | (790,795 | ) | | | (101,844 | ) |
Purchase of minerals in place | | | 221,536 | | | | 377,887 | |
Extensions and discoveries | | | 170 | | | | — | |
Production | | | (389,268 | ) | | | (426,326 | ) |
| | | | | | | | |
Balance at December 31, 2008 | | | 6,496,149 | | | | 4,224,033 | |
Revisions of previous estimates | | | 1,790,387 | | | | 634,099 | |
Purchase of minerals in place | | | 63,928 | | | | 59,689 | |
Extensions and discoveries | | | 149,533 | | | | — | |
Production | | | (407,415 | ) | | | (414,730 | ) |
| | | | | | | | |
Balance at December 31, 2009 | | | 8,092,582 | | | | 4,503,091 | |
| | | | | | | | |
Proved developed reserves: | | | | | | | | |
December 31, 2006 | | | 7,317,964 | | | | 3,910,938 | |
| | | | | | | | |
December 31, 2007 | | | 6,877,406 | | | | 4,116,158 | |
| | | | | | | | |
December 31, 2008 | | | 5,770,190 | | | | 3,928,995 | |
| | | | | | | | |
December 31, 2009 | | | 6,729,632 | | | | 3,854,008 | |
| | | | | | | | |
Proved undeveloped reserves: | | | | | | | | |
December 31, 2006 | | | 676,528 | | | | 330,383 | |
| | | | | | | | |
December 31, 2007 | | | 577,100 | | | | 258,158 | |
| | | | | | | | |
December 31, 2008 | | | 725,959 | | | | 295,038 | |
| | | | | | | | |
December 31, 2009 | | | 1,362,950 | | | | 649,083 | |
| | | | | | | | |
Material Changes. The reserve reports for the Underlying Properties were prepared effective as of December 31, 2009. During the period from December 31, 2008 to December 31, 2009, VOC Sponsor drilled and completed one horizontal well in the Kurten Woodbine Unit at a cost of $1.5 million which converted 120 MBoe from proved undeveloped to proved developed reserves. VOC also drilled a second horizontal well that was being completed at year-end 2009 at a cost of $1.1 million which converted 120 MBoe from proved undeveloped to proved developed non-producing. As a result of the success, VOC Sponsor booked an additional 921 MBoe as proved
F-7F-6
Predecessor Underlying Properties
NOTES TO COMBINED STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008, and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
undeveloped reserves attributable to eight additional identified drilling locations in the Kurten Woodbine Unit.ESTIMATED QUANTITIES OF OIL AND GAS RESERVES
| | | | | | | | |
| | Oil
| | | Gas
| |
| | (Bbls) | | | (Mcf) | |
|
Proved reserves: | | | | | | | | |
Balance at December 31, 2007 | | | 7,454,506 | | | | 4,374,316 | |
Revisions of previous estimates | | | (790,795 | ) | | | (101,844 | ) |
Purchase of minerals in place | | | 221,536 | | | | 377,887 | |
Extensions and discoveries | | | 170 | | | | — | |
Production | | | (389,268 | ) | | | (426,326 | ) |
| | | | | | | | |
Balance at December 31, 2008 | | | 6,496,149 | | | | 4,224,033 | |
Revisions of previous estimates | | | 1,790,387 | | | | 634,099 | |
Purchase of minerals in place | | | 63,928 | | | | 59,689 | |
Extensions and discoveries | | | 149,533 | | | | — | |
Production | | | (407,415 | ) | | | (414,730 | ) |
| | | | | | | | |
Balance at December 31, 2009 | | | 8,092,582 | | | | 4,503,091 | |
Revisions of previous estimates | | | 659,977 | | | | 1,041,826 | |
Production | | | (494,876 | ) | | | (446,979 | ) |
| | | | | | | | |
Balance at December 31, 2010 | | | 8,257,683 | | | | 5,097,938 | |
| | | | | | | | |
Proved developed reserves: | | | | | | | | |
December 31, 2007 | | | 6,877,406 | | | | 4,116,158 | |
| | | | | | | | |
December 31, 2008 | | | 5,770,190 | | | | 3,928,995 | |
| | | | | | | | |
December 31, 2009 | | | 6,729,632 | | | | 3,854,008 | |
| | | | | | | | |
December 31, 2010 | | | 6,799,873 | | | | 3,992,358 | |
| | | | | | | | |
Proved undeveloped reserves: | | | | | | | | |
December 31, 2007 | | | 577,100 | | | | 258,158 | |
| | | | | | | | |
December 31, 2008 | | | 725,959 | | | | 295,038 | |
| | | | | | | | |
December 31, 2009 | | | 1,362,950 | | | | 649,083 | |
| | | | | | | | |
December 31, 2010 | | | 1,457,810 | | | | 1,105,580 | |
| | | | | | | | |
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
FROM PROVED OIL AND GAS RESERVES
Future oil and natural gas sales and production and development costs have been estimated in accordance with the SEC Modernization of Oil and Gas Reporting Rules.Rules for 2009 and 2010.
The standardized measure of discounted future net cash flows (the “Standardized Measure”) represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, production and plugging and abandonment costs, discounted at 10% per annum, or PV-10 value, to reflect timing of future cash flows. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs. Because Predecessor bears no federal income tax expense and taxable income is passed through to the partners of Predecessor, no provision for federal or state income taxes is included in the reserve report or in the calculation of the Standardized Measure.
Estimated proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative
F-7
Predecessor Underlying Properties
NOTES TO COMBINED STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2008, 2009 and 2010
transactions, and were held constant throughout the life of the properties. The index prices were $96.01 per barrel for oil and $7.47 per MMBtu for natural gas at December 31, 2007, $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, 2009.2009 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 $90.83 per barrel for oil and $7.47 per Mcf for natural gas at December 31, 2007, $39.49 per barrel for oil and $5.61 per Mcf for natural gas at December 31, 2008, and $55.82 per barrel for oil and $4.58 per Mcf for natural gas at December 31, 2009.2009 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:
| | | | | | | | | | | | |
| | 2008 | | | 2009 | | | 2010 | |
|
Future cash inflows | | $ | 285,599,020 | | | $ | 479,804,227 | | | $ | 648,185,108 | |
Future costs | | | | | | | | | | | | |
Production | | | (152,898,120 | ) | | | (192,121,342 | ) | | | (223,916,334 | ) |
Development | | | (12,501,184 | ) | | | (25,183,887 | ) | | | (25,384,253 | ) |
| | | | | | | | | | | | |
Future net cash flows | | | 120,199,716 | | | | 262,498,998 | | | | 398,884,521 | |
| | | | | | | | | | | | |
Less 10% discount factor | | | (60,259,262 | ) | | | (142,117,093 | ) | | | (218,408,117 | ) |
| | | | | | | | | | | | |
Standardized measure of discounted future net cash flows | | $ | 59,940,454 | | | $ | 120,381,905 | | | $ | 180,476,404 | |
| | | | | | | | | | | | |
F-8
Predecessor Underlying Properties
NOTES TO COMBINED STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008, and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
The Standardized Measure relating to Predecessor’s proved reserves at December 31, 2007, 2008 and 2009 is shown below:
| | | | | | | | | | | | |
| | 2007 | | | 2008 | | | 2009 | |
|
Future cash inflows | | $ | 709,982,661 | | | $ | 285,599,020 | | | $ | 479,804,227 | |
Future costs | | | | | | | | | | | | |
Production | | | (230,390,861 | ) | | | (152,898,120 | ) | | | (192,121,342 | ) |
Development | | | (8,755,334 | ) | | | (12,501,184 | ) | | | (25,183,887 | ) |
| | | | | | | | | | | | |
Future net cash flows | | | 470,836,466 | | | | 120,199,716 | | | | 262,498,998 | |
| | | | | | | | | | | | |
Less 10% discount factor | | | (264,326,635 | ) | | | (60,259,262 | ) | | | (142,117,093 | ) |
| | | | | | | | | | | | |
Standardized measure of discounted future net cash flows | | $ | 206,509,831 | | | $ | 59,940,454 | | | $ | 120,381,905 | |
| | | | | | | | | | | | |
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, 2007, 2008, 2009 and 2009:2010:
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED OIL AND GAS RESERVES
| | | | | | | | | | | | | | | | | | | | | | | | |
| | 2007 | | 2008 | | 2009 | | | 2008 | | 2009 | | 2010 | |
Standardized measure at beginning of year | | $ | 139,990,054 | | | $ | 206,509,831 | | | $ | 59,940,454 | | | $ | 206,509,831 | | | $ | 59,940,454 | | | $ | 120,381,905 | |
Sales of oil and gas produced, net of production costs | | | (20,049,955 | ) | | | (29,744,163 | ) | | | (15,788,110 | ) | | | (29,744,163 | ) | | | (15,788,110 | ) | | | (29,265,616 | ) |
Net changes in price and production costs | | | 67,422,650 | | | | (154,951,804 | ) | | | 41,451,566 | | | | (154,951,804 | ) | | | 41,451,566 | | | | 52,703,598 | |
Extensions, discoveries and improved recovery, net of future production and development costs | | | 2,246,681 | | | | 5,822 | | | | 5,890,961 | | | | 5,822 | | | | 5,890,961 | | | | — | |
Changes in estimated future development costs | | | 222,643 | | | | (2,726,749 | ) | | | (14,381,027 | ) | | | (2,726,749 | ) | | | (14,381,027 | ) | | | (14,568,030 | ) |
Development costs incurred during the period which reduce future development costs | | | 1,200,100 | | | | 52,800 | | | | 2,700,100 | | | | 52,800 | | | | 2,700,100 | | | | 7,599,939 | |
Revisions of quantity estimates | | | (8,530,591 | ) | | | (7,982,910 | ) | | | 29,413,203 | | | | (7,982,910 | ) | | | 29,413,203 | | | | 15,664,245 | |
Accretion of discount | | | 13,999,005 | | | | 20,650,983 | | | | 5,994,045 | | | | 20,650,983 | | | | 5,994,045 | | | | 12,038,190 | |
Purchase of reserves in place | | | 10,959,750 | | | | 4,831,610 | | | | 1,567,625 | | | | 4,831,610 | | | | 1,567,625 | | | | — | |
Change in production rates, timing and other | | | (950,506 | ) | | | 23,295,034 | | | | 3,593,088 | | | | 23,295,034 | | | | 3,593,088 | | | | 15,922,173 | |
| | | | | | | | | | | | | | |
Standardized measure at end of year | | $ | 206,509,831 | | | $ | 59,940,454 | | | $ | 120,381,905 | | | $ | 59,940,454 | | | $ | 120,381,905 | | | $ | 180,476,404 | |
| | | | | | | | | | | | | | |
F-9
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Members of VOC Kansas Energy Partners, LLC:
We have audited the accompanying statements of historical revenues and direct operating expenses of the Acquired Underlying Properties, consisting of the Underlying Properties of VOC Kansas Energy Partners, LLC (“KEP”) not under common control with VOC Brazos Energy Partners, L.P., for each of the three years in the period ended December 31, 2009.2010. 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 audit providesaudits provide a reasonable basis for our opinion.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, 2009,2010, in conformity with accounting principles generally accepted in the United States of America.
Grant Thornton LLP
Wichita, Kansas
December 29, 2010
March 22, 2011
F-10
Acquired Underlying Properties
AND DIRECT OPERATING EXPENSES
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | | Nine Months Ended September 30, | |
| | 2007 | | | 2008 | | | 2009 | | | 2009 | | | 2010 | |
| | | | | | | | | | | (Unaudited) | |
|
Revenues: | | | | | | | | | | | | | | | | | | | | |
Oil sales | | $ | 21,327,649 | | | $ | 29,297,334 | | | $ | 17,602,148 | | | $ | 12,158,085 | | | $ | 17,298,458 | |
Natural gas sales | | | 1,904,416 | | | | 2,248,210 | | | | 780,880 | | | | 581,580 | | | | 682,819 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 23,232,065 | | | | 31,545,544 | | | | 18,383,028 | | | | 12,739,665 | | | | 17,981,277 | |
| | | | | | | | | | | | | | | | | | | | |
Bad debt expense | | | — | | | | 2,165,663 | | | | — | | | | — | | | | — | |
Direct operating expenses: | | | | | | | | | | | | | | | | | | | | |
Lease operating expenses | | | 5,412,591 | | | | 6,046,131 | | | | 5,969,209 | | | | 4,396,507 | | | | 4,690,168 | |
Production and property taxes | | | 1,231,321 | | | | 1,613,900 | | | | 1,169,798 | | | | 813,809 | | | | 950,133 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 6,643,912 | | | | 7,660,031 | | | | 7,139,007 | | | | 5,210,316 | | | | 5,640,301 | |
| | | | | | | | | | | | | | | | | | | | |
Excess of revenues over direct operating expenses | | $ | 16,588,153 | | | $ | 21,719,850 | | | $ | 11,244,021 | | | $ | 7,529,349 | | | $ | 12,340,976 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | Year Ended December 31, | |
| | 2008 | | | 2009 | | | 2010 | |
|
Revenues: | | | | | | | | | | | | |
Oil sales | | $ | 29,297,334 | | | $ | 17,602,148 | | | $ | 23,272,803 | |
Natural gas sales | | | 2,248,210 | | | | 780,880 | | | | 842,035 | |
| | | | | | | | | | | | |
Total | | | 31,545,544 | | | | 18,383,028 | | | | 24,114,838 | |
| | | | | | | | | | | | |
Bad debt expense | | | 2,165,663 | | | | — | | | | — | |
Direct operating expenses: | | | | | | | | | | | | |
Lease operating expenses | | | 6,046,131 | | | | 5,969,209 | | | | 6,401,987 | |
Production and property taxes | | | 1,613,900 | | | | 1,169,798 | | | | 1,416,534 | |
| | | | | | | | | | | | |
Total | | | 7,660,031 | | | | 7,139,007 | | | | 7,818,521 | |
| | | | | | | | | | | | |
Excess of revenues over direct operating expenses | | $ | 21,719,850 | | | $ | 11,244,021 | | | $ | 16,296,317 | |
| | | | | | | | | | | | |
The accompanying notes are an integral part of these statements.
F-11
Acquired Underlying Properties
AND DIRECT OPERATING EXPENSES
For the years ended December 31, 2007, 2008, and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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.PL.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
F-12
Acquired Underlying Properties
NOTES TO STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008, and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
$4,000. Theseunitholders 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 deductedborne by the trust before distributionsVOC Energy Trust, which are madeexpected to trust unitholders.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.
The accompanying Statements of Historical Revenues and Direct Operating Expenses for the nine months ended September 30, 2009 and 2010 are unaudited. In the opinion of management of KEP, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation on the basis described above.
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 2006, 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, 2006, 2007, 2008, 2009 and 20092010 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 the provisions of accounting literature for OilSEC rules and Gas Extractive Activities.regulations. Such estimates are calculated by adjusting the estimated reserves attributable to specified working interest percentages held by KEP outlined in the Cawley, Gillespie & Associates, Inc. reserve report to reflect the working interest percentages held in the Acquired Underlying Properties. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” and “proved undeveloped” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.
The reserve data below represent estimates only and should not be construed as being exact. Moreover, the discounted values should not be construed as representative of the current market
F-13
Acquired Underlying Properties
NOTES TO STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008, and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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 natural gas prices; (ii) the effect of federal income taxes, if any, on the Acquired Underlying Properties; (iii) an allowance for return on investment; (iv) the effect of governmental legislation; (v) the value of additional potential reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities; and (vi) other business risks.
The following tables set forth (i) the estimated net quantities of proved, proved developed and proved undeveloped oil, and natural gas reserves attributable to the oil and gas properties, and (ii) the standardized measure of the discounted future net profits interest income attributable to the oil and gas properties and the nature of changes in such standardized measure between years. These tables are prepared on the accrual basis, which is the basis on which KEP maintains its production records. The data presents the proved reserves attributable to the Acquired Underlying Properties for the economic life of such properties and is not limited to the term of the trust.
ESTIMATED QUANTITIES OF OIL AND GAS RESERVES
�� | | | | | | | | |
| | Oil
| | | Gas
| |
| | (Bbls) | | | (Mcf) | |
|
Proved reserves: | | | | | | | | |
Balance at December 31, 2007 | | | 4,538,607 | | | | 3,005,629 | |
Revisions of previous estimates | | | (1,042,884 | ) | | | (48,799 | ) |
Extensions and discoveries | | | 1,063 | | | | — | |
Production | | | (314,620 | ) | | | (323,964 | ) |
| | | | | | | | |
Balance at December 31, 2008 | | | 3,182,166 | | | | 2,632,866 | |
Revisions of previous estimates | | | 849,297 | | | | (461,342 | ) |
Purchase of minerals in places | | | 64,733 | | | | 65,972 | |
Extensions and discoveries | | | 65,804 | | | | — | |
Production | | | (324,329 | ) | | | (278,022 | ) |
| | | | | | | | |
Balance at December 31, 2009 | | | 3,837,671 | | | | 1,959,474 | |
Revisions of previous estimates | | | 767,948 | | | | 124,153 | |
Production | | | (321,661 | ) | | | (232,254 | ) |
| | | | | | | | |
Balance at December 31, 2010 | | | 4,283,958 | | | | 1,851,373 | |
| | | | | | | | |
Proved developed reserves: | | | | | | | | |
December 31, 2007 | | | 4,538,607 | | | | 3,005,629 | |
| | | | | | | | |
December 31, 2008 | | | 3,182,166 | | | | 2,632,866 | |
| | | | | | | | |
December 31, 2009 | | | 3,837,671 | | | | 1,959,474 | |
| | | | | | | | |
December 31, 2010 | | | 4,171,465 | | | | 1,851,373 | |
| | | | | | | | |
| | | | | | | | |
Proved undeveloped reserves: | | | | | | | | |
December 31, 2007 | | | — | | | | — | |
| | | | | | | | |
December 31, 2008 | | | — | | | | — | |
| | | | | | | | |
December 31, 2009 | | | — | | | | — | |
| | | | | | | | |
December 31, 2010 | | | 112,493 | | | | — | |
| | | | | | | | |
F-14
Acquired Underlying Properties
NOTES TO STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
ESTIMATED QUANTITIES OF OIL AND GAS RESERVES
| | | | | | | | |
| | Oil
| | | Gas
| |
| | (Bbls) | | | (Mcf) | |
|
Proved reserves: | | | | | | | | |
Balance at December 31, 2006 | | | 4,840,866 | | | | 2,936,664 | |
Revisions of previous estimates | | | — | | | | — | |
Extensions and discoveries | | | 16,264 | | | | 416,022 | |
Production | | | (318,523 | ) | | | (347,057 | ) |
| | | | | | | | |
Balance at December 31, 2007 | | | 4,538,607 | | | | 3,005,629 | |
Revisions of previous estimates | | | (1,042,884 | ) | | | (48,799 | ) |
Extensions and discoveries | | | 1,063 | | | | — | |
Production | | | (314,620 | ) | | | (323,964 | ) |
| | | | | | | | |
Balance at December 31, 2008 | | | 3,182,166 | | | | 2,632,866 | |
Revisions of previous estimates | | | 849,297 | | | | (461,342 | ) |
Purchase of minerals in places | | | 64,733 | | | | 65,972 | |
Extensions and discoveries | | | 65,804 | | | | — | |
Production | | | (324,329 | ) | | | (278,022 | ) |
| | | | | | | | |
Balance at December 31, 2009 | | | 3,837,671 | | | | 1,959,474 | |
| | | | | | | | |
Proved developed reserves: | | | | | | | | |
December 31, 2006 | | | 4,840,866 | | | | 2,936,664 | |
| | | | | | | | |
December 31, 2007 | | | 4,538,607 | | | | 3,005,629 | |
| | | | | | | | |
December 31, 2008 | | | 3,182,166 | | | | 2,632,866 | |
| | | | | | | | |
December 31, 2009 | | | 3,837,671 | | | | 1,959,474 | |
| | | | | | | | |
| | | | | | | | |
Proved undeveloped reserves: | | | | | | | | |
December 31, 2006 | | | — | | | | — | |
| | | | | | | | |
December 31, 2007 | | | — | | | | — | |
| | | | | | | | |
December 31, 2008 | | | — | | | | — | |
| | | | | | | | |
December 31, 2009 | | | — | | | | — | |
| | | | | | | | |
F-15
Acquired Underlying Properties
NOTES TO STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008, and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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 $96.01 per barrel for oil and $7.47 per MMBtu for natural gas at December 31, 2007, $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, 2009.2009 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 $90.83 per barrel for oil and $7.47 per Mcf for natural gas at December 31, 2007, $39.49 per barrel for oil and $5.61 per Mcf for natural gas at December 31, 2008, and $55.82 per barrel for oil and $4.58 per Mcf for natural gas at December 31, 2009.2009, 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 Predecessor’s reserves.the reserves of the Acquired Underlying Properties.
F-16F-15
Acquired Underlying Properties
NOTES TO STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008, and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
The Standardized Measure relating to Predecessor’sthe proved reserves of the Acquired Underlying Properties at December 31, 2007, 2008, 2009 and 20092010 is shown below:
| | | | | | | | | | | | |
| | 2007 | | | 2008 | | | 2009 | �� |
|
Future cash inflows | | $ | 429,961,058 | | | $ | 130,045,214 | | | $ | 212,587,116 | |
Future costs | | | | | | | | | | | | |
Production | | | (145,593,930 | ) | | | (68,863,533 | ) | | | (103,484,949 | ) |
Development | | | — | | | | — | | | | (133,055 | ) |
| | | | | | | | | | | | |
Future net cash flows | | | 284,367,128 | | | | 61,181,681 | | | | 108,969,112 | |
Less 10% discount factor | | | (150,905,146 | ) | | | (26,506,431 | ) | | | (50,661,158 | ) |
| | | | | | | | | | | | |
Standardized measure of discounted future net cash flows | | $ | 133,461,982 | | | $ | 34,675,250 | | | $ | 58,307,954 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | 2008 | | | 2009 | | | 2010 | |
|
Future cash inflows | | $ | 130,045,214 | | | $ | 212,587,116 | | | $ | 319,037,861 | |
Future costs | | | | | | | | | | | | |
Production | | | (68,863,533 | ) | | | (103,484,949 | ) | | | (146,343,958 | ) |
Development | | | — | | | | (133,055 | ) | | | (1,749,143 | ) |
| | | | | | | | | | | | |
Future net cash flows | | | 61,181,681 | | | | 108,969,112 | | | | 170,944,760 | |
Less 10% discount factor | | | (26,506,431 | ) | | | (50,661,158 | ) | | | (83,138,265 | ) |
| | | | | | | | | | | | |
Standardized measure of discounted future net cash flows | | $ | 34,675,250 | | | $ | 58,307,954 | | | $ | 87,806,495 | |
| | | | | | | | | | | | |
The following table sets forth the changes in the Standardized Measure applicable to the proved oil and natural gas reserves of the Acquired Underlying Properties for the years ended December 31, 2007, 2008, 2009 and 2009:2010:
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED OIL AND GAS RESERVES
| | | | | | | | | | | | | | | | | | | | | | | | |
| | 2007 | | 2008 | | 2009 | | | 2008 | | 2009 | | 2010 | |
Standardized measure at beginning of year | | $ | 127,561,986 | | | $ | 133,461,982 | | | $ | 34,675,250 | | | $ | 133,461,982 | | | $ | 34,675,250 | | | $ | 58,307,954 | |
Sales of oil and gas produced, net of production costs | | | (16,588,154 | ) | | | (23,885,512 | ) | | | (11,244,020 | ) | | | (23,885,512 | ) | | | (11,244,020 | ) | | | (16,296,317 | ) |
Net changes in price and production costs | | | 6,796,558 | | | | (104,323,038 | ) | | | 13,629,634 | | | | (104,323,038 | ) | | | 13,629,634 | | | | 21,385,452 | |
Extensions, discoveries and improved recovery, net of future production and development costs | | | 2,935,393 | | | | 36,385 | | | | 2,700,702 | | | | 36,385 | | | | 2,700,702 | | | | — | |
Changes in estimated future development costs | | | — | | | | — | | | | (123,046 | ) | | | — | | | | (123,046 | ) | | | (1,545,676 | ) |
Development costs incurred during the period which reduce future development costs | | | | — | | | | — | | | | 133,055 | |
Revisions of quantity estimates | | | — | | | | (10,894,366 | ) | | | 13,536,403 | | | | (10,894,366 | ) | | | 13,536,403 | | | | 16,130,251 | |
Accretion of discount | | | 12,756,199 | | | | 13,346,198 | | | | 3,467,525 | | | | 13,346,198 | | | | 3,467,525 | | | | 5,830,796 | |
Purchase of reserves in place | | | — | | | | — | | | | 1,582,671 | | | | — | | | | 1,582,671 | | | | — | |
Change in production rates, timing and other | | | — | | | | 26,933,601 | | | | 82,835 | | | | 26,933,601 | | | | 82,835 | | | | 3,860,980 | |
| | | | | | | | | | | | | | |
Standardized measure at end of year | | $ | 133,461,982 | | | $ | 34,675,250 | | | $ | 58,307,954 | | | $ | 34,675,250 | | | $ | 58,307,954 | | | $ | 87,806,495 | |
| | | | | | | | | | | | | | |
F-17F-16
UNAUDITED PRO FORMA STATEMENTS OF HISTORICAL REVENUES AND
DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES
Introduction
The following unaudited pro forma statements of historical revenues and direct operating expenses are of the Predecessor Underlying Properties, as adjusted to give effect to the acquisition of the Acquired Underlying Properties as if the acquisition had occurred on January 1, 2009.2010. 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, 2009.2010.
The unaudited pro forma statements of historical revenues and direct operating expenses should be read in conjunction with “The Underlying Properties — Discussion and analysis of historical results of the Underlying Properties,” the audited combined statements of historical revenues and direct operating expenses of Predecessor Underlying Properties and the audited statements of historical revenues and direct operating expenses of the Acquired Underlying Properties included in this prospectus.
F-18F-17
UNAUDITED PRO FORMA STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2009 | | | Nine Months Ended September 30, 2010 | |
| | Historical | | | Adjustments | | | Pro Forma | | | Historical | | | Adjustments | | | Pro Forma | |
| | | | | (a) | | | | | | | | | (a) | | | | |
|
Revenues: | | | | | | | | | | | | | | | | | | | | | | | | |
Oil sales | | $ | 22,757,639 | | | $ | 17,602,148 | | | $ | 40,359,787 | | | $ | 27,383,690 | | | $ | 17,298,458 | | | $ | 44,682,148 | |
Natural gas sales | | | 1,510,884 | | | | 780,880 | | | | 2,291,764 | | | | 1,856,506 | | | | 682,819 | | | | 2,539,325 | |
Hedge activity | | | 1,477,248 | | | | — | | | | 1,477,248 | | | | (150,626 | ) | | | — | | | | (150,626 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total | | | 25,745,771 | | | | 18,383,028 | | | | 44,128,799 | | | | 29,089,570 | | | | 17,981,277 | | | | 47,070,847 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Bad debt recovery | | | (719,061 | ) | | | — | | | | (719,061 | ) | | | — | | | | — | | | | — | |
Direct operating expenses: | | | | | | | | | | | | | | | | | | | | | | | | |
Lease operating expenses | | | 6,787,857 | | | | 5,969,209 | | | | 12,757,066 | | | | 5,228,613 | | | | 4,690,168 | | | | 9,918,781 | |
Production and property taxes | | | 1,646,052 | | | | 1,169,798 | | | | 2,815,850 | | | | 1,918,959 | | | | 950,133 | | | | 2,869,092 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total | | | 8,433,909 | | | | 7,139,007 | | | | 15,572,916 | | | | 7,147,572 | | | | 5,640,301 | | | | 12,787,873 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Excess of revenues over direct operating expenses | | $ | 18,030,923 | | | $ | 11,244,021 | | | $ | 29,274,944 | | | $ | 21,941,998 | | | $ | 12,340,976 | | | $ | 34,282,974 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | Year Ended December 31, 2010 | |
| | Historical | | | Adjustments | | | Pro Forma | |
| | | | | (a) | | | | |
|
Revenues: | | | | | | | | | | | | |
Oil sales | | $ | 36,914,333 | | | $ | 23,272,803 | | | $ | 60,187,136 | |
Natural gas sales | | | 2,396,637 | | | | 842,035 | | | | 3,238,672 | |
Hedge activity | | | (707,371 | ) | | | — | | | | (707,371 | ) |
| | | | | | | | | | | | |
Total | | | 38,603,599 | | | | 24,114,838 | | | | 62,718,437 | |
| | | | | | | | | | | | |
Direct operating expenses: | | | | | | | | | | | | |
Lease operating expenses | | | 7,325,042 | | | | 6,401,987 | | | | 13,727,029 | |
Production and property taxes | | | 2,720,313 | | | | 1,416,534 | | | | 4,136,847 | |
| | | | | | | | | | | | |
Total | | | 10,045,355 | | | | 7,818,521 | | | | 17,863,876 | |
| | | | | | | | | | | | |
Excess of revenues over direct operating expenses | | $ | 28,558,244 | | | $ | 16,296,317 | | | $ | 44,854,561 | |
| | | | | | | | | | | | |
| | |
(a) | | Pro forma adjustment to give effect to the acquisition of the Acquired Properties as if the acquisition had occurred on January 1, 2009.2010. |
F-19F-18
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Unitholders of VOC Energy Trust:
We have audited the accompanying statement of assets and trust corpus of VOC Energy Trust (the “Trust”) as of December 17,31, 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 17,31, 2010, on the basis of accounting described in Note B.
Grant Thornton LLP
Wichita, Kansas
December 29, 2010
March 22, 2011
F-20F-19
VOC ENERGY TRUST
| | | | |
| | December 17,
|
| | 2010 |
|
ASSETS | | | | |
Cash | | $ | 1,000 | |
| | | | |
TRUST CORPUS | | | | |
Trust Corpus | | $ | 1,000 | |
| | | | |
| | | | |
| | December 31,
|
| | 2010 |
|
ASSETS | | | | |
Cash | | $ | 1,000 | |
| | | | |
TRUST CORPUS | | | | |
Trust Corpus | | $ | 1,000 | |
| | | | |
The accompanying notes are an integral part of this financial statement.
F-21F-20
VOC Energy Trust
NOTE A — ORGANIZATION OF THE TRUST
VOC Energy Trust (the “Trust”) is a statutory trust formed on November 3, 2010 (capitalized on December 17, 2010), under the Delaware Statutory Trust Act pursuant to a Trust Agreement (the “Trust Agreement”) among VOC Brazos Energy Partners, L.P. (“VOC Brazos”), as trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and Wilmington Trust Company, as Delaware Trustee (the “Delaware Trustee”).
The Trust was created to acquire and hold a term net profits interest (the “Net Profits Interest”) for the benefit of the Trust unitholders. In connection with the closing of the initial public offering of trust units of the Trust, VOC Brazos will convey the Net Profits Interest to the Trust. The Net Profits Interest is an interest during the term of the trust in underlying properties consisting of working interests in substantially all of its oil and natural gas properties in the states of Kansas and Texas held by VOC Brazos and VOC Kansas Energy Partners, L.L.C. as of the date of the conveyance of the Net Profits Interest to the Trust (the “Underlying Properties”).
The Net Profits Interest is passive in nature and the Trustee will have no management control over and no responsibility relating to the operation of the Underlying Properties. The Net Profits Interest entitles the Trust to receive 80% of the net proceeds attributable to the net profits interest during the term of the Trust. The Net Profits Interest will terminate on the later to occur of (1) December 31, 2030 or (2) the time from and after January 1, 2011 when 9.710.6 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 salessales), less direct operating expenses (lease operating expenses and production and property taxes) and development expenses of the Underlying Properties plus any payments made or net of payments received in connection with the settlement of certain hedge contracts, times 80%. Cash distributions of the Trust will be made based on the amount of cash received by the Trust pursuant to terms of the conveyance creating the Net Profits Interest.
F-22F-21
VOC Energy Trust
NOTES TO STATEMENT OF ASSETS AND TRUST CORPUS — (Continued)
The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust’s assets, liabilities, Trust corpus, earnings and distributions as follows:
a)(a) Income from Net Profits Interest is recorded when distributions are received by the Trust;
b)(b) Distributions to Trust unitholders are recorded when paid by the Trust;
c)(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)(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)(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)(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.
F-23F-22
VOC Energy Trust
NOTES TO STATEMENT OF ASSETS AND TRUST CORPUS — (Continued)
| |
NOTE D — | DISTRIBUTIONS TO UNITHOLDERS |
The Trustee determines for each quarter the amount available for distribution to the Trust unitholders. This distribution is expected to be made on or before the 45th day of the month following the end of each quarter to the Trust unitholders of record on the 30th day of the month following the end of each quarter (or the next succeeding business day). Such amounts will be equal to the excess, if any, of the cash received by the Trust duringrelating to the preceding quarter, over the liabilitiesexpenses of the Trust paid duringfor such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for future liabilitiesexpenses of the Trust.
| |
NOTE E — | SUBSEQUENT EVENTS |
Management has reviewed activity through December 29, 2010,March 22, 2011, which is considered the date through which these financial statements are available to be issued for events requiring recognition or disclosure.
F-24F-23
VOC Energy Trust
UNAUDITED PRO FORMA FINANCIAL INFORMATION
Introduction
In connection with the closing of the initial public offering of trust units of VOC Energy Trust, pursuant to that certain Contribution and Exchange Agreement dated August 30, 2010, VOC Brazos Energy Partners, L.P. (“VOC Brazos”) will acquire the membership interests in VOC Kansas Energy Partners, LLC (“KEP”) in exchange for newly issued limited partnership interests in VOC Brazos, resulting in KEP becoming a wholly-owned subsidiary of VOC Brazos (the “KEP Acquisition”). As used herein, “VOC Sponsor” refers to VOC Brazos after giving effect to the KEP Acquisition. Concurrent with the closing of the initial public offering, VOC Sponsor will convey to the Trust the Net Profits Interest representing the right to receive 80% of the net proceeds from production from substantially all of the interests in oil and natural gas properties in the states of Kansas and Texas held by VOC Sponsor as of the date of the conveyance of the Net Profits Interest to the trust (the “Underlying Properties”).
The unaudited pro forma statement of assets and trust corpus presents the beginning statement of assets and trust corpus of the Trust as of September 30,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 September 30,December 31, 2010. The unaudited pro forma statements of distributable income for the year ended December 31, 2009 and the nine months ended September 30, 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, 2009,2010, 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 aan assumed public offering price of $$20.00 per unit. These estimates are based on the most recently available information. To the extent there are significant changes in these amounts, the assumptions and estimates herein could change significantly.
The unaudited pro forma statement of assets and trust corpus and unaudited pro forma statements of distributable income should be read in conjunction with the accompanying notes to such unaudited pro forma financial information and the audited statement of assets and trust corpus of the Trust, including the related notes, included in this prospectus and elsewhere in the registration statement.
F-25F-24
VOC ENERGY TRUST
| | | | | | | | | | | | |
| | September 30, 2010 | |
| | Historical | | | Adjustments | | | Pro Forma | |
| | (a) | | | | | | | |
|
ASSETS |
Cash | | $ | 1,000 | | | $ | — | | | $ | 1,000 | |
Investment in Net Profits Interest (See Note E) | | | — | | | | 121,794,079 | | | | 121,794,079 | |
| | | | | | | | | | | | |
| | $ | 1,000 | | | $ | 121,794,079 | | | $ | 121,795,079 | |
| | | | | | | | | | | | |
TRUST CORPUS | | | | | | | | | | | | |
trust units issued and outstanding | | $ | 1,000 | | | $ | 121,794,079 | | | $ | 121,795,079 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | December 31, 2010 | |
| | Historical | | | Adjustments | | | Pro Forma | |
| | (a) | | | | | | | |
|
ASSETS |
Cash | | $ | 1,000 | | | $ | — | | | $ | 1,000 | |
Investment in Net Profits Interest (See Note E) | | | — | | | | 144,536,661 | | | | 144,536,661 | |
| | | | | | | | | | | | |
| | $ | 1,000 | | | $ | 144,536,661 | | | $ | 144,537,661 | |
| | | | | | | | | | | | |
TRUST CORPUS | | | | | | | | | | | | |
16,540,000 trust units issued and outstanding | | $ | 1,000 | | | $ | 144,536,661 | | | $ | 144,537,661 | |
| | | | | | | | | | | | |
| | |
(a) | | VOC Energy Trust was formed in November, 2010 and capitalized on December 17, 2010. |
The accompanying notes are an integral part of the unaudited pro forma financial statement.
F-26F-25
VOC ENERGY TRUST
| | | | | | | | | | | | |
| | Year Ended
| | Nine Months Ended
| | | Year Ended
| |
| | December 31, 2009 | | September 30, 2010 | | | December 31, 2010 | |
|
Historical Results | | | | | | | | | | | | |
Income from the Net Profits Interest (See Note D) | | $ | 19,316,462 | | | $ | 20,363,174 | | | $ | 27,489,986 | |
Pro Forma Adjustments | | | | | | | | | | | | |
Less trust general and administrative expenses (See Note E(a)) | | | 900,000 | | | | 675,000 | | | | 900,000 | |
| | | | | | | | |
Distributable income | | $ | 18,416,462 | | | $ | 19,688,174 | | | $ | 26,589,986 | |
| | | | | | | | |
Distributable income per unit | | $ | | | | $ | | | | $ | 1.61 | |
| | | | | | | | |
The accompanying notes are an integral part of the unaudited pro forma financial statements.
F-27F-26
VOC Energy Trust
NOTE A — BASIS OF PRESENTATION
In connection with the closing of the initial public offering of trust units of VOC Energy Trust (the “Trust”), pursuant to that Certain Contribution and Exchange Agreement dated August 30, 2010, VOC Brazos Energy Partners, L.P. (“VOC Brazos”) will acquire the membership interests in VOC Kansas Energy Partners, LLC (“KEP”) in exchange for newly issued limited partnership interests in VOC Brazos, resulting in KEP becoming a wholly-owned subsidiary of VOC Brazos (the “KEP Acquisition”). As used herein, “VOC Sponsor” refers to VOC Brazos after giving effect to the KEP Acquisition. Concurrent with the closing of the initial public offering, VOC Sponsor will convey to the Trust a term net profits interest (the “Net Profits Interest”) representing the right to receive 80% of the net proceeds from production from substantially all of the interests in oil and natural gas properties in the states of Kansas and Texas held by VOC Sponsor as of the date of the conveyance of the Net Profits Interest to the Trust (the “Underlying Properties”).
The unaudited pro forma statement of assets and trust corpus presents the beginning statement of assets and trust corpus of the Trust as of September 30,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 September 30,December 31, 2010. The unaudited pro forma statements of distributable income for the year ended December 31, 2009 and the nine months ended September 30, 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, 2009,2010, 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.
F-28
VOC Sponsor believes that the assumptions used provide a reasonable basis for presenting the significant effects directly attributable to this transaction.
F-27
This unaudited pro forma financial information should be read in conjunction with the Statement of Historical Revenues and Direct Operating Costs for Underlying Properties and related notes for the periods presented.
NOTE C — INCOME TAXES
The Trust is a Delaware statutory trust and is not required to pay federal or state income taxes. Accordingly, no provision for Federal or state income taxes has been made.
NOTE D — INCOME FROM NET PROFITS INTEREST
The table below outlines the calculation of Trust income from Net Profits Interest derived from the excess of revenues over direct operating expenses of the Underlying Properties for the year ended December 31, 2009 and the nine months ended September 30, 2010:
| | | | | | | | |
| | Year Ended
| | | Nine Months Ended
| |
| | December 31, 2009 | | | September 30, 2010 | |
|
Excess of revenues over direct operating expenses of Underlying Properties | | $ | 29,274,944 | | | $ | 34,282,974 | |
Development expenses (1) | | | 5,129,366 | | | | 8,829,006 | |
| | | | | | | | |
Excess of revenues over direct operating expenses and development expenses | | | 24,145,578 | | | | 25,453,968 | |
Times Net Profits Interest over the term of the Trust | | | 80 | % | | | 80 | % |
| | | | | | | | |
Trust Income from Net Profits Interest | | $ | 19,316,462 | | | $ | 20,363,174 | |
| | | | | | | | |
| | | | |
| | Year Ended
| |
| | December 31, 2010 | |
|
Excess of revenues over direct operating expenses of Underlying Properties | | $ | 44,854,562 | |
Development expenses (1) | | | 10,492,080 | |
| | | | |
Excess of revenues over direct operating expenses and development expenses | | | 34,362,482 | |
Times Net Profits Interest over the term of the Trust | | | 80 | % |
| | | | |
Trust Income from Net Profits Interest | | $ | 27,489,986 | |
| | | | |
| | |
(1) | | Per terms of the Net Profits Interest development costs are to be deducted when calculating the distributable income to the Trust. |
NOTE E — PRO FORMA ADJUSTMENTS
The Net Profits Interest is recorded at the historical cost of VOC Sponsor and is calculated as follows as of September 30,December 31, 2010:
| | | | |
Oil and gas properties consisting of the Underlying Properties | | $ | 180,181,637 | |
Less accumulated depreciation, depletion and amortization | | | (26,331,798 | ) |
| | | | |
Net Property Value | | | 153,849,839 | |
Plus hedge asset | | | 1,245,391 | |
Less asset retirement obligation (1) | | | (5,246,492 | ) |
| | | | |
Net property to be conveyed | | | 149,848,738 | |
| | | | |
Times 80% Net Profits Interest to Trust with the asset retirement obligation limited to the life of the Trust | | $ | 121,794,079 | |
| | | | |
| | | | |
Oil and gas properties consisting of the Underlying Properties | | $ | 210,789,946 | |
Less accumulated depreciation, depletion and amortization | | | (28,174,233 | ) |
| | | | |
Net Property Value | | | 182,615,713 | |
Plus hedge asset | | | 182,817 | |
Less asset retirement obligation (1) | | | (4,242,466 | ) |
| | | | |
Net property to be conveyed | | | 178,556,064 | |
| | | | |
Times 80% Net Profits Interest to Trust with the asset retirement obligation limited to the life of the Trust | | $ | 144,536,661 | |
| | | | |
| | |
(1) | | See Note F below for a description of asset retirement obligation. |
(a) These Trust administrative expenses are anticipated to aggregate approximately $900,000 for 2011. Administrative expenses for subsequent years could be greater or less depending on future events that cannot be predicted. Included in the $900,000 annual estimate is an annual
F-29
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
F-28
acceptance fee in the amount of $4,000. These costs will be deducted by the trust before distributions are made to trust unitholders.
NOTE F — ASSET RETIREMENT OBLIGATIONS
Accounting guidance requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which the liability is incurred. The liability is measured at discounted 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. 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.
F-30F-29
INFORMATION ABOUT
VOC BRAZOS ENERGY PARTNERS, L.P.
(VOC SPONSOR)
The trust units are not interests in or obligations of
VOC Sponsor
VOC-1
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, 2009,2010, VOC Sponsor held interests in approximately 892881 gross (550.2(545.7 net) producing wells, and proved reserves of the Underlying Properties were approximately 13.013.7 MMBoe. As of December 31, 2009,2010, 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 90%91% of the total proved reserves and L.D. Drilling Inc. and Davis Petroleum, Inc. operating approximately 8%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 2009.2010. Vess Oil currently operates over 1,600 oil, natural gas and service wells located primarily in Kansas, with growing operations in Texas. As of September 30,December 31, 2010, Vess Oil employed 19 full-time employees, three contract professionals and 14 contract personnel in its Wichita office and in five field and satellite offices.
The trust units do not represent interests in, or obligations of, VOC Sponsor.
MANAGEMENT OF VOC SPONSOR
VOC Sponsor does not currently have any executive officers, directors or employees. Instead, VOC Sponsor is managed by its general partner, Vess Texas Partners, LLC. The officers of Vess Texas Partners LLC consist of employees of Vess Oil. None of the members of the executive management team of Vess Oil who perform management functions for VOC Sponsor receive any compensation from the trust or from VOC Sponsor.
VOC-2
Set forth in the table below are the names, ages, and titles at Vess Oil of the members of the executive management team of Vess Oil who perform management functions on behalf of Vess Texas Partners, LLC, VOC Sponsor’s general partner:
| | | | | | |
Name | | Age | | Title |
|
J. Michael Vess | | | 59 | | | President & Chief Executive Officer |
William R. Horigan | | | 61 | | | Vice President of Operations |
Brian Gaudreau | | | 55 | | | Vice President of Land |
Barry Hill | | | 3435 | | | Vice President and Chief Financial Officer |
Alan Howarter | | | 5455 | | | Vice President of Financial Reporting |
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 principal owner of Vess Oil since it was founded in 1979. Mr. Vess received a Bachelor of Business Administration degree from Wichita State University in 1973 and subsequently received his CPA certificate. Mr. Vess currently serves on the Board of Directors and Executive Committees for the Kansas Independent Oil and Gas Association (“KIOGA”) and is the current Chairman of the KIOGA Committee on Electricity. In addition, he is Past Chairman of the KIOGA Tax Committee and a current member of the Interstate Oil and Gas Compact Commission Outreach Committee.
William R. 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. Prior to joining Vess Oil, Mr. Hill spent approximately ten years in the Energy Investment Banking group of Raymond James and& 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.companies, until his departure in January 2010. During the last five
VOC-3
years of his employment with Raymond James & Associates, Inc., Mr. Hill held the positions of Senior Associate and Vice President. Mr. Hill earned his A.B. in Economics with honors from Harvard College in 1998 and an M.B.A. from the Darden Graduate School of Business at the University of Virginia in 2003.
Alan 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 2005.2005 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, 2009,2010, 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 90%91% of the total proved reserves for which VOC Sponsor is the designated the operator and L.D. Drilling Inc. and Davis Petroleum, Inc. operating approximately 8%7% of the total proved reserves. Vess Oil is controlled by J. Michael Vess, L.D. Drilling Inc. is controlled by L.D. Davis, and Davis Petroleum, Inc., is controlled by both Mr. Vess and Mr. Davis. Under the terms of the operating arrangement among VOC Sponsor and Vess Oil, all expenses of
VOC-4
Vess Oil incurred on behalf of VOC Sponsor are paid by VOC Sponsor at the cost incurred. Below is a summary of the transactions that occurred between VOC Sponsor and the VOC Operators:
| | | | | | | | | | | | | | | | | | | | |
| | | | Nine Months Ended
|
| | Year Ended December 31, | | September 30, |
| | 2007 | | 2008 | | 2009 | | 2009 | | 2010 |
| | (In thousands) |
| | | | | | | | (Unaudited) |
|
Lease operating expenses incurred | | $ | 10,002 | | | $ | 11,734 | | | $ | 10,723 | | | $ | 7,946 | | | $ | 8,377 | |
Overhead costs included in lease operating expenses incurred | | | 1,146 | | | | 1,253 | | | | 1,401 | | | | 1,039 | | | | 1,132 | |
Capitalized lease equipment and producing leaseholds cost incurred | | | 1,882 | | | | 1,926 | | | | 2,094 | | | | 1,132 | | | | 2,863 | |
Payment of well development costs | | | 2,219 | | | | 2,386 | | | | 2,406 | | | | 1,026 | | | | 6,099 | |
Payment of management fees | | | 447 | | | | 447 | | | | 447 | | | | 335 | | | | 335 | |
| | | | | | | | | | | | |
| | Year Ended December 31, | |
| | 2008 | | | 2009 | | | 2010 | |
| | | | | (In thousands) | | | | |
|
Lease operating expenses incurred: | | | | | | | | | | | | |
Vess Oil Corporation | | $ | 10,314 | | | $ | 9,334 | | | $ | 10,053 | |
LD Drilling | | | 768 | | | | 685 | | | | 605 | |
Davis Petroleum | | | 652 | | | | 704 | | | | 756 | |
| | | | | | | | | | | | |
Total | | $ | 11,734 | | | $ | 10,723 | | | $ | 11,414 | |
| | | | | | | | | | | | |
Overhead costs included in lease operating expenses incurred: | | | | | | | | | | | | |
Vess Oil Corporation | | $ | 1,098 | | | $ | 1,232 | | | $ | 1,314 | |
LD Drilling | | | 91 | | | | 97 | | | | 100 | |
Davis Petroleum | | | 64 | | | | 72 | | | | 72 | |
| | | | | | | | | | | | |
Total | | $ | 1,253 | | | $ | 1,401 | | | $ | 1,486 | |
| | | | | | | | | | | | |
Capitalized lease equipment and producing leasehold costs incurred: | | | | | | | | | | | | |
Vess Oil Corporation | | $ | 1,402 | | | $ | 1,937 | | | $ | 3,246 | |
LD Drilling | | | 304 | | | | 154 | | | | (8 | ) |
Davis Petroleum | | | 220 | | | | 3 | | | | 14 | |
| | | | | | | | | | | | |
Total | | $ | 1,926 | | | $ | 2,094 | | | $ | 3,252 | |
| | | | | | | | | | | | |
Payment of well development costs: | | | | | | | | | | | | |
Vess Oil Corporation | | $ | 1,709 | | | $ | 2,269 | | | $ | 7,149 | |
LD Drilling | | | 509 | | | | 137 | | | | — | |
Davis Petroleum | | | 168 | | | | — | | | | 81 | |
| | | | | | | | | | | | |
Total | | $ | 2,386 | | | $ | 2,406 | | | $ | 7,230 | |
| | | | | | | | | | | | |
Payment of management fees: | | | | | | | | | | | | |
Vess Oil Corporation | | $ | 447 | | | $ | 447 | | | $ | 447 | |
LD Drilling | | | — | | | | — | | | | — | |
Davis Petroleum | | | — | | | | — | | | | — | |
| | | | | | | | | | | | |
Total | | $ | 447 | | | $ | 447 | | | $ | 447 | |
| | | | | | | | | | | | |
VOC Sponsor pays the VOC Operators an overhead fee based on a monthly charge per active operated well to operate substantially all of the Underlying Properties located in Kansas on behalf of VOC Sponsor. The fee is adjusted annually and will increase or decrease each year based on changes in the Overhead Adjustment Index (“OAI”) published by the Council of Petroleum Accountants Society for that year. The operating activities include various maintenance, engineering, geological, accounting and administrative functions. As reflected in the summary reserve reports, in 2009,2010, the aggregate overhead fee in Kansas paid to the VOC Operators was approximately $1.4$1.5 million.
For the Underlying Properties located in Texas, VOC Sponsor reimburses Vess Texas Partners, LLC (“Vess LLC”) for certain corporate administrative and accounting services arranged by Vess LLC. This reimbursement amount is adjusted annually and will increase or decrease each year
VOC-5
based on changes in the OAI for that year. Most of the services for which Vess LLC is reimbursed are performed on behalf of Vess LLC by Vess Oil. The fee is currently $37,250 per month.
Vess LLC pays a portion of this $37,250 as an overhead fee to Vess Oil to operate substantially all of the Underlying Properties located in Texas on behalf of VOC Sponsor. The operating activities include various maintenance, engineering, geological, accounting and administrative functions. The overhead fee includes (1) a fixed monthly charge of $13,500 per month, (2) reimbursement for certain geological and engineering services and (3) a monthly charge per active well brought on production after September 2009, which is adjusted annual and based on changes in the Overhead Adjustment Index.
Vess Oil is not contractually obligated to provide the corporate administrative and accounting services on behalf of VOC Sponsor or Vess LLC other than with respect to the operation of the Underlying Properties, and VOC Sponsor and Vess LLC may contract for the provision of the corporate administrative and accounting services from other parties at any time. None of the members of the executive management team are contractually obligated to continue performing services on behalf of VOC Sponsor, and Vess Oil is not contractually obligated to make its employees available to perform such services.
The fees described above are independent of the fees payable by the Trust pursuant to the trust agreement and the Administrative Services Agreement. See “The trust” and “Description of the trust agreement — Fees and expenses.”
VOC-5
For the nine-monthsyear ended September 30,December 31, 2010, VOC Sponsor sold approximately 32%33% of the oil produced from the Underlying Properties to MV Purchasing, LLC, an affiliate of VOC Sponsor. A summary of sales and trade receivables with MV Purchasing follows:
| | | | | | | | | | | | | | | | | | | | |
| | | | | Nine Months Ended
| |
| | Year Ended December 31, | | | September 30, | |
| | 2007 | | | 2008 | | | 2009 | | | 2009 | | | 2010 | |
| | | | | | | | | | | (Unaudited) | |
|
Sales | | $ | — | | | $ | 1,207,358 | | | $ | 13,482,074 | | | $ | 9,176,357 | | | $ | 14,185,601 | |
Trade Receivables | | $ | — | | | $ | 319,109 | | | $ | 1,359,842 | | | | | | | $ | 1,410,080 | |
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | | | | | | |
| | 2008 | | | 2009 | | | 2010 | | | | | | | |
|
Sales | | $ | 1,207,358 | | | $ | 13,482,074 | | | $ | 19,125,260 | | | | | | | | | |
Trade Receivables | | $ | 319,109 | | | $ | 1,359,842 | | | $ | 1,760,141 | | | | | | | | | |
MV Purchasing began operations on August 1, 2008.
Forty-five days following the closing of the initial public offering of trust units, VOC Partners, LLC will (1) purchase, at the initial offering price, trust units owned by VOC Sponsor and (2) issue a promissory note to VOC Sponsor having a face amount equal to 90% of the purchase price for the trust units and a cash payment equal to 10% of the purchase price for the trust units. The note will have a term of ten years with interest payable at 5% per year.
VOC-6
SELECTED HISTORICAL AND UNAUDITED PRO FORMA
FINANCIAL DATA OF VOC SPONSOR
The selected financial data presented below should be read in conjunction with the accompanying financial statements and related notes included elsewhere in this prospectus. In connection with the closing of initial public offering of trust units of VOC Energy Trust, pursuant to that certain Contribution and Exchange Agreement dated August 30, 2010, VOC Brazos will acquire all of the membership interests in KEP in exchange for newly issued limited partnership interests in VOC Brazos, resulting in KEP becoming a wholly-owned subsidiary of VOC Brazos. As the Common Control Properties are deemed to be under common control with VOC Brazos, accounting rules specify that VOC Brazos and the Common Control Properties be combined from the earliest date they came under common control. The financial data and operations of such assets are referred to herein as “Predecessor,” and are described in more detail below in “— 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, 20082009 and 20092010 and for each of the years in the three-year period ended December 31, 20092010 have been derived from Predecessor’s audited financial statements. The selected combined historical financial data of Predecessor as of September 30, 2010 and for the nine-month periods ended September 30, 2009 and 2010 have been derived from Predecessor’s unaudited interim financial statements. The unaudited financial statements were prepared on a basis consistent with the audited statements and, in the opinion of VOC Brazos, include all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the results of Predecessor for the periods presented.
The selected unaudited pro forma financial data for the year ended December 31, 2009 and as of and for the nine months ended September 30, 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 September 30,December 31, 2010, in the case of the pro forma balance sheet information as of September 30,December 31, 2010, and (ii) as of January 1, 2009,
VOC-7
2010, in the case of the pro forma statement of
VOC-7
earnings information for the year ended December 31, 2009, and the nine months ended September 30, 2010.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Predecessor Pro Forma as
|
| | | | Predecessor Pro Forma for the
| | Adjusted for the Offering
|
| | | | | | | | | | | | Acquisition of the Acquired
| | (including the conveyance
|
| | | | | | | | | | | | Underlying Properties | | of the Net Profits Interests) |
| | | | | | | | | | | | | | Nine Months
| | | | Nine Months
|
| | Predecessor | | Year Ended
| | Ended
| | Year Ended
| | Ended
|
| | Year Ended December 31, | | Nine Months Ended September 30, | | December 31,
| | September 30,
| | December 31,
| | September 30,
|
| | 2007 | | 2008 | | 2009 | | 2009 | | 2010 | | 2009 | | 2010 | | 2009 | | 2010 |
| | (In thousands) |
| | | | | | | | (Unaudited) | | (Unaudited) | | (Unaudited) |
|
Revenue | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Oil and gas sales | | $ | 21,290 | | | $ | 32,198 | | | $ | 25,746 | | | $ | 17,945 | | | $ | 29,090 | | | $ | 44,129 | | | $ | 47,071 | | | $ | 8,826 | | | $ | 9,414 | |
Interest income | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
Gain on sales of assets | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 7,005 | | | | 5,217 | |
Other | | | — | | | | — | | | | 4 | | | | 4 | | | | 1 | | | | 4 | | | | 1 | | | | 4 | | | | 2 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total revenue | | | 21,290 | | | | 32,198 | | | | 25,750 | | | | 17,949 | | | | 29,091 | | | | 44,133 | | | | 47,072 | | | | 15,835 | | | | 14,633 | |
Costs and expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Lease operating | | | 6,586 | | | | 7,667 | | | | 6,788 | | | | 5,054 | | | | 5,229 | | | | 12,757 | | | | 9,919 | | | | 2,551 | | | | 1,984 | |
Production and property taxes | | | 1,874 | | | | 2,532 | | | | 1,646 | | | | 1,258 | | | | 1,919 | | | | 2,816 | | | | 2,869 | | | | 563 | | | | 574 | |
Depreciation, depletion, amortization and accretion | | | 2,259 | | | | 5,781 | | | | 5,210 | | | | 4,325 | | | | 4,355 | | | | 10,094 | | | | 7,724 | | | | 2,246 | | | | 1,756 | |
Bad debt expense (recovery) | | | — | | | | 1,727 | | | | (719 | ) | | | (719 | ) | | | — | | | | (719 | ) | | | — | | | | (719 | ) | | | — | |
General and administrative | | | 121 | | | | 269 | | | | 463 | | | | 243 | | | | 111 | | | | 463 | | | | 130 | | | | 463 | | | | 130 | |
Interest | | | 363 | | | | 1,383 | | | | 1,501 | | | | 1,168 | | | | 920 | | | | 1,501 | | | | 920 | | | | 1,501 | | | | 920 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total costs and expenses | | | 11,203 | | | | 19,359 | | | | 14,889 | | | | 11,329 | | | | 12,534 | | | | 26,912 | | | | 21,562 | | | | 6,606 | | | | 5,363 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net earnings | | $ | 10,087 | | | $ | 12,839 | | | $ | 10,861 | | | $ | 6,620 | | | $ | 16,557 | | | $ | 17,222 | | | $ | 25,510 | | | $ | 9,230 | | | $ | 9,269 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total assets (at period end) | | | | | | $ | 108,830 | | | $ | 101,280 | | | | | | | $ | 109,626 | | | | | | | $ | 173,271 | | | | | | | $ | 85,220 | |
Long-term liabilities, excluding current maturities (at period end) | | | | | | $ | 37,018 | | | $ | 28,315 | | | | | | | $ | 26,765 | | | | | | | $ | 28,822 | | | | | | | $ | 102,264 | |
Partners’ capital/Common Control owners’ equity (deficit) | | | | | | $ | 67,865 | | | $ | 67,512 | | | | | | | $ | 79,932 | | | | | | | $ | 139,876 | | | | | | | $ | (29,581 | ) |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | Predecessor Pro Forma as
|
| | | | Predecessor Pro Forma for the
| | Adjusted for the Offering
|
| | | | | | | | Acquisition of the Acquired
| | (including the conveyance
|
| | | | | | | | Underlying Properties | | of the Net Profits Interests) |
| | Predecessor | | Year Ended
| | Year Ended
|
| | Year Ended December 31, | | December 31,
| | December 31,
|
| | 2008 | | 2009 | | 2010 | | 2010 | | 2010 |
| | (In thousands) |
| | | | | | | | (Unaudited) | | (Unaudited) |
|
Revenue | | | | | | | | | | | | | | | | | | | | |
Oil and gas sales | | $ | 32,198 | | | $ | 25,746 | | | $ | 38,603 | | | $ | 62,718 | | | $ | 12,543 | |
Interest income | | | — | | | | — | | | | — | | | | — | | | | — | |
Gain on sales of assets | | | — | | | | — | | | | — | | | | — | | | | 9,423 | |
Other | | | — | | | | 4 | | | | 32 | | | | 32 | | | | 32 | |
| | | | | | | | | | | | | | | | | | | | |
Total revenue | | | 32,198 | | | | 25,750 | | | | 38,635 | | | | 62,750 | | | | 21,998 | |
Costs and expenses | | | | | | | | | | | | | | | | | | | | |
Lease operating | | | 7,667 | | | | 6,788 | | | | 7,325 | | | | 13,727 | | | | 2,745 | |
Production and property taxes | | | 2,532 | | | | 1,646 | | | | 2,720 | | | | 4,137 | | | | 827 | |
Depreciation, depletion, amortization and accretion | | | 5,781 | | | | 5,210 | | | | 6,253 | | | | 12,836 | | | | 2,979 | |
Bad debt expense (recovery) | | | 1,727 | | | | (719 | ) | | | — | | | | — | | | | — | |
General and administrative | | | 269 | | | | 463 | | | | 205 | | | | 205 | | | | 205 | |
Interest | | | 1,383 | | | | 1,501 | | | | 1,221 | | | | 1,221 | | | | 1,221 | |
| | | | | | | | | | | | | | | | | | | | |
Total costs and expenses | | | 19,359 | | | | 14,889 | | | | 17,724 | | | | 32,126 | | | | 7,977 | |
| | | | | | | | | | | | | | | | | | | | |
Net earnings | | $ | 12,839 | | | $ | 10,861 | | | | 20,911 | | | | 30,624 | | | | 14,021 | |
| | | | | | | | | | | | | | | | | | | | |
Total assets (at year end) | | $ | 108,830 | | | $ | 101,280 | | | | 109,038 | | | | 202,171 | | | | 96,358 | |
Long-term liabilities, excluding current maturities (at year end) | | $ | 37,018 | | | $ | 28,315 | | | | 26,241 | | | | 27,805 | | | | 99,392 | |
Partners’ capital/Common Control owners’ equity (deficit) | | $ | 67,865 | | | $ | 67,512 | | | | 70,936 | | | | 159,559 | | | | (26,746 | ) |
VOC-8
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 consolidatedcombined 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.
VOC-9
RESULTS OF OPERATIONS
Set forth in the table below is a summary of VOC Sponsor’sPredecessor’s financial data for the periods indicated.
| | | | | | | | | | | | | | | | | | | | |
| | | | | Nine Months Ended
| |
| | Years Ended December 31, | | | September 30 | |
| | 2007 | | | 2008 | | | 2009 | | | 2009 | | | 2010 | |
| | (In thousands) | |
| | | | | | | | | | | (Unaudited) | |
Revenue | | | | | | | | | | | | | | | | | | | | |
Oil and gas sales | | $ | 21,290 | | | $ | 32,198 | | | $ | 25,746 | | | $ | 17,945 | | | $ | 29,090 | |
Interest income | | | — | | | | — | | | | 4 | | | | 4 | | | | 1 | |
| | | | | | | | | | | | | | | | | | | | |
Total revenue | | $ | 21,290 | | | $ | 32,198 | | | $ | 25,750 | | | $ | 17,949 | | | $ | 29,091 | |
| | | | | | | | | | | | | | | | | | | | |
Costs and expenses | | | | | | | | | | | | | | | | | | | | |
Lease operating | | | 6,586 | | | | 7,667 | | | | 6,788 | | | | 5,054 | | | | 5,229 | |
Production and property taxes | | | 1,874 | | | | 2,532 | | | | 1,646 | | | | 1,258 | | | | 1,919 | |
Depreciation, depletion, amortization and accretion | | | 2,259 | | | | 5,781 | | | | 5,210 | | | | 4,325 | | | | 4,355 | |
Bad debt expense (recovery) | | | — | | | | 1,727 | | | | (719 | ) | | | (719 | ) | | | — | |
General and administrative | | | 121 | | | | 269 | | | | 463 | | | | 243 | | | | 111 | |
Interest | | | 363 | | | | 1,383 | | | | 1,501 | | | | 1,168 | | | | 920 | |
| | | | | | | | | | | | | | | | | | | | |
Total costs and expenses | | $ | 11,203 | | | $ | 19,359 | | | $ | 14,889 | | | $ | 11,329 | | | $ | 12,534 | |
| | | | | | | | | | | | | | | | | | | | |
Net earnings | | $ | 10,087 | | | $ | 12,839 | | | $ | 10,861 | | | $ | 6,620 | | | $ | 16,557 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | Years Ended December 31, | |
| | 2008 | | | 2009 | | | 2010 | |
| | (In thousands) | |
Revenue | | | | | | | | | | | | |
Oil and gas sales | | $ | 32,198 | | | $ | 25,746 | | | $ | 38,603 | |
Interest income | | | — | | | | 4 | | | | 32 | |
| | | | | | | | | | | | |
Total revenue | | $ | 32,198 | | | $ | 25,750 | | | $ | 38,635 | |
| | | | | | | | | | | | |
Costs and expenses | | | | | | | | | | | | |
Lease operating | | | 7,667 | | | | 6,788 | | | | 7,325 | |
Production and property taxes | | | 2,532 | | | | 1,646 | | | | 2,720 | |
Depreciation, depletion, amortization and accretion | | | 5,781 | | | | 5,210 | | | | 6,253 | |
Bad debt expense (recovery) | | | 1,727 | | | | (719 | ) | | | — | |
General and administrative | | | 269 | | | | 463 | | | | 205 | |
Interest | | | 1,383 | | | | 1,501 | | | | 1,221 | |
| | | | | | | | | | | | |
Total costs and expenses | | $ | 19,359 | | | $ | 14,889 | | | $ | 17,724 | |
| | | | | | | | | | | | |
Net earnings | | $ | 12,839 | | | $ | 10,861 | | | $ | 20,911 | |
| | | | | | | | | | | | |
Nine MonthsYear Ended September 30,December 31, 2010 Compared To Nine MonthsYear Ended September 30,December 31, 2009
The financial information with respect to the nine months ended September 30, 2010 and 2009 that is discussed below is unaudited. In the opinion of VOC Sponsor’s management, this information contains all adjustments, consisting only of adjustments for normally recurring accruals, necessary for a fair presentation of the results for such periods. The results of operations for these interim periods are not necessarily indicative of the results of operations for the full fiscal year.
Revenues.Revenues Revenues from oil and natural gas sales increased $11.1$12.9 million between these periods. This consists of an increase of $13.1$15.0 million of oil and natural gas revenues and a $2.0$2.2 million increase in hedge expense. The $13.1$15.0 million increase in revenues was primarily the result of an increase in the average price received for the oil sold from $50.37$55.86 per Bbl for the nine monthsyear ended September 30,December 31, 2009 to $73.15$74.59 per Bbl for the nine monthsyear ended September 30,December 31, 2010 and a 76.1an 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 $3.36$3.64 per Mcf for the nine monthsyear ended September 30,December 31, 2009 to $5.49$5.36 per Mcf for the nine monthsyear ended September 30,December 31, 2010, and a 28.2 Mmcf32.2 MMcf increase in natural gas volumes sold.
The increase in overall production sales volumes during the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 is primarily attributable to the drilling of five horizontal wells in the Texas properties. One well was drilled in the fourth quarter of 2009 and four were drilled in the first nine months of 2010.
Hedge ActivityThe increase in hedge and other derivative activity expense of $2.0$2.2 million for the nine monthsyear ended September 30,December 31, 2010 was due to an increase in realized hedge losses and was partially offset by a
VOC-10
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 first nine months ofyear ended December 31, 2010 of $77.65$79.53 compared to $57.00$61.80 for the first nine months ofyear ended December 31, 2009. The weighted average settlement price of hedges and other derivatives for the first nine months ofyear ended December 31, 2010 was $73.06 compared to $68.85 for the first nine months ofyear ended December 31, 2009.
In addition, at September 30,December 31, 2010, VOC Sponsor recorded a $0.4$0.3 million income for ineffectiveness of hedges compared to noa $0 million expense at September 30,December 31, 2009. At September 30,December 31, 2009, VOC Sponsor had open swap agreements covering the next 2724 months. At September 30,December 31, 2010, VOC Sponsor had open swap agreements covering the next 15 month periods12 months.
VOC-10
Hedge ineffectiveness of the swap agreements is the result of various factors including changes in the average crude oil price and changes in the basis differential between the NYMEX price and the price actually received by VOC Sponsor.
Hedge ineffectiveness and actual hedge losses increased during the period of rising oil prices as experienced from 2009 to 2010 when the average NYMEX price per barrel of crude oil went from $41.92 to $75.55.$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.
Prices. The average price received for sales of crude oil 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 slightly 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.
Lease operating expenses.expenses Lease operating expenses increased from $5.1$6.8 million for the nine monthsyear ended September 30,December 31, 2009 to $5.2$7.3 million for the nine monthsyear ended September 30,December 31, 2010. This increase was primarily a result of an increase in productiongeneral 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 tax expensetaxes Production and property taxes increased due to the increased price of oil and gas on which the taxes are based and casing repair to several wells, repair and cleanout of a salt water disposal system well and continuing restoration of wells from inactive status to producing status.based.
Production and property taxes. Production and property taxes increased from $1.3 million for the nine months ended September 30, 2009 to $1.9 million for the nine months ended September 30, 2010. Production and property taxes increased primarily 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.
Depreciation, depletion, amortization and accretion.accretion Depreciation, depletion, amortization and accretion increased from $4.3$5.2 million for the nine monthsyear ended September 30,December 31, 2009 to $4.4$6.3 million for the nine monthsyear ended September 30,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 nine monthsyear ended September 30,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
VOC-11
which was recorded in 2008. There
During the year ended December 31, 2010, there was no bad debt recovery during the nine months ended September 30, 2010.expense or recovery.
As publicly reported on July 22, 2008, the revenue intermediary/crude oil purchaser Eaglwing L.P., a revenue intermediary/crude oil purchase for Predecessor, 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.
General and administrative expenses.expenses General and administrative expenses decreased from $0.5 million for the year ended December 31, 2009 to $0.2 million for the nine monthsyear ended September 30, 2009 to $0.1 million for the nine months ended September 30,December 31, 2010. This is a decrease is primarily due to the timing of expenses and a reduction of general costs.
Interest expense.expenses Interest expense decreased from $1.5 million for the year ended December 31, 2009 to $1.2 million for the nine monthsyear ended September 30, 2009 to $0.9 million for the nine months ended September 30,December 31, 2010. This is primarily a result of principal payments made on outstanding indebtednessthe note during 2009 in addition to a reduction of interest rates. During the nine monthsyear ended September 30,December 31, 2009, VOC Sponsor’s outstanding debt balance decreased from $30.0$35.0 million to $24.0$27.0 million, while during the nine monthsyear ended September 30,December 31, 2010, its outstanding debt balance wasdecreased to $24.0 million.
Year Ended December 31, 2009 Compared To The Year Ended December 31, 2008
Revenues. Revenues from oil and natural gas sales decreased $6.4 million between these periods. This consists of a decrease of $15.7 million of oil and natural gas revenues and was partially offset by a $9.3 million decrease in hedge expense. The $15.7 million decrease in
VOC-11
revenues was primarily the result of a decrease in the average price received for the oil sold from $94.11 per Bbl for the year ended December 31, 2008 to $55.88 per Bbl for the year ended December 31, 2009. The decrease in revenues was also the result of a decrease in the average price received for the natural gas sold from $7.86 per Mcf for the year ended December 31, 2008 to $3.64 per Mcf for the year ended December 31, 2009.
The decrease in hedge activity expense of $9.3 million for the year ended December 31, 2009 was due primarily to the lower average NYMEX settle price for the year ended December 31, 2009 of $61.80 compared to $99.65 for the year ended December 31, 2008. The weighted average hedge price for 2009 was $68.85 compared to $70.02 for 2008.
Lease operating expenses. Lease operating expenses decreased from $7.7 million for the year ended December 31, 2008 to $6.8 million for the year ended December 31, 2009. This decrease was primarily the result of the electronification of wells in the Texas properties. The operator started replacing the inefficient gas pumping motors in the Texas properties with
VOC-12
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.
Year Ended December 31, 2008 Compared To The Year Ended December 31, 2007
Revenues. Revenues from oil and natural gas sales increased $10.9 million between these periods. This consists of an increase of $11.4 million of oil and natural gas revenues which was partially offset by a $0.5 million increase in hedge expense. The $11.4 million increase in revenues was primarily the result of an increase in the average price received for the oil sold from $67.31 per Bbl for the year ended December 31, 2007 to $94.11 per Bbl for the year ended December 31, 2008. The increase in revenues was also the result of an increase in the average price received for the natural gas sold from $6.39 per Mcf for the year ended December 31, 2007 to $7.86 per Mcf for the year ended December 31, 2008.
The increase in hedge activity expense of $0.5 million for the year ended December 31, 2008 was due primarily to the higher average NYMEX settle price for the year ended December 31, 2008 of $99.65 compared to $72.34 for the year ended December 31, 2007. The weighted average hedge price for 2008 was $70.02 compared to $52.27 for 2007.
VOC-13VOC-12
Lease operating expenses. Lease operating expenses increased from $6.6 million for the year ended December 31, 2007 to $7.7 million for the year ended December 31, 2008. This increase was primarily a result of the purchase of oil and gas leaseholds in August of 2008 along with general increased costs of primary vendors who rely on large uses of hydrocarbon products such as (1) pumpers (gasoline), (2) utilities (cost of fuel), (3) treating chemicals (hydrocarbon base) and (4) pulling units (fuel surcharge). This increase was also supplemented by wage increases associated with the increased demand for oilfield employees and increases in the price of steel for tubular and other metal products.
Production and property taxes. Production and property taxes increased from $1.9 million for the year ended December 31, 2007 to $2.5 million for the year ended December 31, 2008. Production and property taxes increased primarily 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.
Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion increased from $2.3 million for the year ended December 31, 2007 to $5.8 million for the year ended December 31, 2008. Depreciation, depletion and amortization are calculated based on units of production. The increase in depreciation, depletion and amortization was primarily the result of the addition of oil and gas leaseholds, lease and well equipment and well development that add to the asset base combined with a decrease in the total estimated reserves.
Bad debts 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 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, 2007, there was no bad debt expense or recovery.
General and administrative expenses. General and administrative expenses increased from $0.1 million for the years ended December 31, 2007 to $0.3 million for the year ended December 31, 2008. This was primarily the result of increased costs due to the purchase of oil and gas leaseholds in August of 2008 along with increases in these costs due to inflationary adjustments.
Interest expense. Interest expense increased $1.0 million from $0.4 million for the year ended December 31, 2007 to $1.4 million for the year ended December 31, 2008. 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 of 2008.
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.
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Cash Flow from Operating Activities
Net cash provided by operating activities was $9.9$15.8 million and $21.1$27.6 million for the nine monthsyears ended September 30,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.
Net cash provided by operating activities was $15.0 million during the year ended December 31, 2009, compared to $15.8 million during the year ended December 31, 2009. The increase in net cash provided by operating activities in 2009 was substantially due to decreased expenses partially offset by decreased revenues, as discussed above in “— Results of operations.”
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, at a strike price of $94.90 per barrel of oil2012 and 2013 that hedge approximately 22%47% expected oil production for such years from the proved developed producing reserves attributable to the Underlying Properties in the reserve reports. The hedge contracts will not be pledged to the trust, but any payments made by VOC Sponsor upon settlement of the hedge contracts will be factored into the calculation of the net proceeds from the Underlying Properties. Any proceeds received by VOC Sponsor upon settlement of the hedge contracts will separately be factored into the
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calculation of payment due to the trust. From January 1, 2011 through December 31, 2011,2013, VOC Sponsor’s crude oil price risk management position in swap contracts is as follows:
| | | | | | | | |
| | Fixed Price Swaps |
| | | | Weighted
|
| | Volumes
| | Average Price
|
Month | | (Bbls) | | (Per Bbl) |
|
January 2011 | | | 13,689 | | | $ | 94.90 | |
February 2011 | | | 13,621 | | | $ | 94.90 | |
March 2011 | | | 13,553 | | | $ | 94.90 | |
April 2011 | | | 13,486 | | | $ | 94.90 | |
May 2011 | | | 13,420 | | | $ | 94.90 | |
June 2011 | | | 13,354 | | | $ | 94.90 | |
July 2011 | | | 13,289 | | | $ | 94.90 | |
August 2011 | | | 13,224 | | | $ | 94.90 | |
September 2011 | | | 13,160 | | | $ | 94.90 | |
October 2011 | | | 13,096 | | | $ | 94.90 | |
November 2011 | | | 13,032 | | | $ | 94.90 | |
December 2011 | | | 12,970 | | | $ | 94.90 | |
| | | | | | | | | | | | |
| | | | Fixed Price Swaps |
| | | | Weighted
|
| | Volumes
| | Average Price
|
Month | | (Bbls) | | (Per Bbl) |
|
January 2011 | | | | | | | 13,689 | | | $ | 94.90 | |
February 2011 | | | | | | | 13,621 | | | $ | 94.90 | |
March 2011 | | | | | | | 20,014 | | | $ | 96.77 | |
April 2011 | | | | | | | 31,510 | | | $ | 98.05 | |
May 2011 | | | | | | | 31,031 | | | $ | 98.02 | |
June 2011 | | | | | | | 30,580 | | | $ | 97.99 | |
July 2011 | | | | | | | 30,150 | | | $ | 97.97 | |
August 2011 | | | | | | | 29,740 | | | $ | 97.95 | |
September 2011 | | | | | | | 29,348 | | | $ | 97.92 | |
October 2011 | | | | | | | 28,971 | | | $ | 97.90 | |
November 2011 | | | | | | | 28,610 | | | $ | 97.88 | |
December 2011 | | | | | | | 28,264 | | | $ | 97.86 | |
January 2012 | | | | | | | 27,916 | | | $ | 99.64 | |
February 2012 | | | | | | | 27,588 | | | $ | 99.64 | |
March 2012 | | | | | | | 27,279 | | | $ | 99.64 | |
April 2012 | | | | | | | 26,980 | | | $ | 99.64 | |
May 2012 | | | | | | | 26,690 | | | $ | 99.63 | |
June 2012 | | | | | | | 26,410 | | | $ | 99.63 | |
July 2012 | | | | | | | 26,139 | | | $ | 99.63 | |
August 2012 | | | | | | | 25,877 | | | $ | 99.63 | |
September 2012 | | | | | | | 25,622 | | | $ | 99.63 | |
October 2012 | | | | | | | 25,374 | | | $ | 99.63 | |
November 2012 | | | | | | | 25,124 | | | $ | 99.63 | |
December 2012 | | | | | | | 24,890 | | | $ | 99.62 | |
January 2013 | | | | | | | 24,657 | | | $ | 97.97 | |
February 2013 | | | | | | | 24,431 | | | $ | 97.97 | |
March 2013 | | | | | | | 24,212 | | | $ | 97.97 | |
April 2013 | | | | | | | 24,033 | | | $ | 97.97 | |
May 2013 | | | | | | | 23,890 | | | $ | 97.97 | |
June 2013 | | | | | | | 23,735 | | | $ | 97.97 | |
July 2013 | | | | | | | 23,596 | | | $ | 97.97 | |
August 2013 | | | | | | | 23,453 | | | $ | 97.97 | |
September 2013 | | | | | | | 23,318 | | | $ | 97.97 | |
October 2013 | | | | | | | 23,184 | | | $ | 97.97 | |
November 2013 | | | | | | | 23,053 | | | $ | 97.97 | |
December 2013 | | | | | | | 22,923 | | | $ | 97.97 | |
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.
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Cash Flows from Investing Activities
VOC Sponsor’s development expenditures were $1.8 million and $7.7 million for the nine months ended September 30, 2009 and 2010, respectively. Capital expenditures for each of the nine months ended September 30, 2009 and September 30, 2010 includes the purchase of oil and natural gas properties and the payment of well development costs.
VOC Sponsor’s development expenditures were $7.9 million in the year ended December 31, 2008 and $3.7 million in the year ended December 31, 2009.2009 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.
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VOC Sponsor currently anticipates that its development budget, which predominantly consists of workover drilling, secondary recovery projects and equipment, will be $8.0$7.2 million for the remainder of 2010 and 2011. The amount and timing of its development expenditures is largely discretionary and within its control. VOC Sponsor’s routinely monitors and adjusts its development expenditures in response to changes in oil and natural gas prices, development costs, industry conditions and internally generated cash flow. Future cash flows are subject to a number of variables, including the level of production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of development expenditures.
Financing Activities
Credit facility
On June 27, 2008, VOC Sponsor entered into a bank credit facility with a group of bank lenders that provides for a revolving line of credit, letters of credit and swing line loans. The total amount that VOC Sponsor can borrow and have outstanding at any one time is limited to the lesser of the total commitment of $100 million or the borrowing base established by the lenders. As of September 30,December 31, 2010, the borrowing base under the bank credit facility was $37.0 million. As of September 30,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 2.19%2.13% per annum as of September 30,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
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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 September 30,December 31, 2010, VOC Sponsor was in compliance with all such covenants.
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CONTRACTUAL OBLIGATIONS
A summary of VOC Sponsor’s contractual obligations as of September 30,December 31, 2010 is provided in the following table.
| | | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period | |
| | | | | Less Than
| | | | | | | | | More Than
| |
| | Total | | | 1 Year | | | 1-3 Years | | | 3-5 Years | | | 5 Years | |
| | (In thousands) | |
|
Long-term debt (a) | | $ | 24,000 | | | $ | — | | | $ | 24,000 | | | $ | — | | | $ | — | |
Asset retirement obligation | | | 5,246 | | | | 424 | | | | 230 | | | | 285 | | | | 4,307 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | $ | 29,246 | | | $ | 424 | | | $ | 24,230 | | | $ | 285 | | | $ | 4,307 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period | |
| | | | | Less Than
| | | | | | | | | More Than
| |
| | Total | | | 1 Year | | | 1-3 Years | | | 3-5 Years | | | 5 Years | |
| | (In thousands) | |
|
Long-term debt (1) | | $ | 24,000 | | | $ | — | | | $ | 24,000 | | | $ | — | | | $ | — | |
Asset retirement obligations | | | 4,243 | | | | 437 | | | | 163 | | | | 133 | | | | 3,510 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | $ | 28,243 | | | $ | 437 | | | $ | 24,163 | | | $ | 133 | | | $ | 3,510 | |
| | | | | | | | | | | | | | | | | | | | |
| | |
(1) | | The amounts included in the table above represent principal maturities only. See “Management’s discussion and analysis of financial condition and results of operations of VOC Sponsor — Quantitative and qualitative disclosure about market risk — Interest rate risk” for information regarding interest payment obligations under long-term debt obligations. |
OFF-BALANCE SHEET ARRANGEMENTS
As of September 30,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.
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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
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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
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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.
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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.
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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 discounted 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
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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 of ASU2010-04did 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 will provideprovides 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 toon 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. AdoptionThe adoption of the provisions of ASU2010-09 did not have a material effectimpact on our financial position, results of operations or cash flows.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, and2010. The adoption did not have a significantmaterial impact on our financial position.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
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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
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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 $79.97$91.38 per Bbl as of September 30,December 31, 2010, the fair value of its hedge positions for 20102011 was a receivable of $2.1$0.6 million, which it owed towas due from the counterparty. A 10% increase or decrease in the index oil price above the September 30, 2010 price for oil would increase or decrease the receivable by $1.6$1.4 million, respectively.
Interest Rate Risks
At September 30,December 31, 2010, VOC Sponsor had debt outstanding under its bank credit facility and other long-term debt of $24.3$24.0 million. The weighted average annual interest rate under the bank credit facility for the nine monthsyear ended September 30,December 31, 2010 was 2.46%2.32%. If prevailing market interest rates had been 1% higher as of September 30,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.
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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”), as amended. A copy of the Amended and Restated Partnership Agreement of VOC Brazos (the “Partnership Agreement”), as well as the amendment thereto, is included as an exhibit to the registration statement to which this prospectus forms a part.
ORGANIZATION AND DURATION
VOC Brazos was organized as a Texas limited partnership on May 21, 2003 and will remain in existence until dissolved in accordance with the Partnership Agreement. See “— Dissolution.”
BUSINESS
The Partnership Agreement limits the business of VOC Brazos to: (i) holding, maintaining, renewing, acquiring, exploring, drilling, developing and operating oil and natural gas properties, leases and wells; (ii) producing, collecting, storing, treating, delivering, marketing, selling or otherwise disposing of oil, gas and related hydrocarbons and minerals; (iii) farming-out, selling, abandoning and otherwise disposing of assets of VOC Brazos; (iv) entering into swaps, options, future contracts and other transactions to hedge or to otherwise minimize the risk associated with the fluctuation of prices to be received by VOC Brazos from the sale of oil, gas and related hydrocarbons and minerals; and (v) taking all such other actions incidental to any of the foregoing as the general partner of VOC Brazos may determine to be necessary or appropriate.
DISTRIBUTION OF AVAILABLE CASH
On or about the tenth day of the month immediately preceding the due date for a payment of estimated income tax by an individual, VOC Brazos will distribute an amount of cash which the general partner reasonably estimates equals the product of (a) maximum marginal combined federal, state, and local income tax rates applicable to a single individual residing in Kansas, and (b) the net taxable income of VOC Brazos (to the extent an estimated income tax payment is or would be due by a partner, directly or indirectly for the applicable distribution period), to the extent of cash available for such distribution and provided that such distribution (i) is not prohibited by the terms of the Partnership Agreement and (ii) would not create a default under the Texas Revised Limited Partnership Act (the “Texas LP Act”) or any agreement with an unrelated third party to which VOC Brazos is subject. In making this determination the general partner is entitled to rely on the books and records, IRS Form 1065 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.
VOC-22VOC-21
The Partnership Agreement designates Vess Texas Partners, LLC as the initial general partner. The Partnership Agreement further provides that the general partner shall have no fiduciary duty (including, but not limited to, any duty of loyalty or duty of care) to VOC Brazos or any partner except (i) a duty to act in good faith, (ii) a general obligation of fair dealing with respect to VOC Brazos and the property of VOC Brazos, (iii) any duty expressly set forth in the Partnership Agreement, and (iv) any duty expressly set forth in other written agreements of VOC Brazos. The general partner may consult a professional staff and outside consultants. The Partnership Agreement allows the general partner to possess interests and engage in business activities in addition to those relating to VOC Brazos, independently or with others, including business interests and activities in direct competition with VOC Brazos, and, subject to certain exceptions, neither VOC Brazos nor the other partners have any right, title or interest in or to such ventures.
The general partner is restricted from taking certain actions without the approval or authorization of the holders of the majority of the partnership interests, including (subject to certain exceptions) the borrowing of money, mortgage or pledging of property, selling, assigning, abandoning or otherwise disposing of any lease of VOC Brazos, guaranteeing of third-party payment or performance, making advance payments of compensation or other consideration to the general partner or the general 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
VOC-23VOC-22
cause the actual operator to properly develop, maintain and operate such leases. With respect to those leases for which Vess Oil is designated as operator, Vess Oil, as the case may be, shall be entitled to receive the compensation and reimbursement to which the operator is entitled in accordance with the provisions of the Partnership Agreement, which sets forth agreed upon charges for certain direct expenses and material furnished to, or transferred from or disposed of by the operator, or any other operating agreement governing the operation of such lease. Vess Oil may not substitute another party as operator or assign its obligations with respect to any lease of VOC Brazos for which it is designated as operator unless a majority of the limited partners request, in connection with the removal of the general partner, as such or the limited partners dissolve VOC Brazos in accordance with the Partnership Agreement.
VOC Brazos pays an overhead fee to Vess Oil to drill, develop and operate the underlying properties on behalf of VOC Brazos. The overhead fee is based on a monthly charge for administrative, supervision, officer services, overhead and warehousing costs, including overhead costs incurred in the construction and installation of fixed assets, the expansion of fixed assets and other projects required for the development and operation of the underlying properties of VOC Brazos that is determined either (a) on the same terms and conditions as Vess Oil charges unrelated parties, or (b) approved by majority of its limited partners, with knowledge of the material facts of the transaction and Vess 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
VOC-24VOC-23
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 wouldwould: (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,Brazos; (iii) have the effect of separating the voting rights from the economic rights of the interest,interest; or (iv) constitute an event of default under the terms of the Partnership Agreement of VOC Brazos. VOC Brazos may, but is not required to, recognize the assignment from the transferring partner to the assignee on the books and records of VOC Brazos, and may, but is not required to, recognize such assignment for purposes of determining and making distributions, allocations, or liquidations. No transfer of a limited partner interest of VOC Brazos, other than a transfer to a permitted transferee under the Partnership Agreement or upon the occurrence of certain events may occur unless VOC Brazos’ right of first refusal under the Partnership Agreement is first satisfied.
REMOVAL OF GENERAL PARTNER
The limited partners may remove the general partner upon a vote of the holders of a majority of the limited partner interests (including, for this purpose, voting interests held by the general partner), whether or not the general partner is proposed to be removed for cause or not for cause.
AMENDMENT OF THE PARTNERSHIP AGREEMENT
The Partnership Agreement may be amended only by an instrument in writing duly approved by a vote of the holders of a majority of the limited partner interests.
VOC-25VOC-24
DISSOLUTION
VOC Brazos will continue as a limited partnership until terminated under the Partnership Agreement. VOC Brazos will dissolve upon: (1) the approval of the holders of a majority of the limited partner interests to dissolve VOC Brazos, provided such approval and dissolution would not constitute an event of default under the terms of any agreement of VOC Brazos; (2) the occurrence of an event which would cause the dissolution of VOC Brazos under the Texas LP Act; (3) the sole general partner resigns, is removed, withdraws or suffers, except in the event of bankruptcy, death, divorce, incapacity, transfer by gift, transfer upon foreclosure or other enforcement of a security interest or lien, or termination of a partner and one or more general partners are not admitted to VOC Brazos within 90 days thereafter.
LIQUIDATION AND TERMINATION
Upon dissolution of VOC Brazos, a liquidator or liquidating committee (the “Liquidator”) approved by the general partner, which such person or group may include the general partner or any limited partner or officer, will wind up the affairs and make final distribution. The Liquidator shall continue to operate the properties of VOC Brazos with all of the power and authority of the general partner necessary or appropriate to liquidate the assets of VOC Brazos and apply the proceeds of the liquidation as described in the Partnership Agreement. Any assets distributed to the members upon liquidation shall be subject to the partnership agreements then in effect; provided, however, that if any lease is subject to an operating agreement to which an unaffiliated third person is not a party, such lease shall be subject to a standard form operating agreement as shall be agreed upon by the limited partners. Upon written request made by any limited partner, the Liquidator shall sell VOC Brazos’ leases and other properties and assets that otherwise would be distributable to such limited partner at the best cash price available therefor and distribute such cash (after deducting all expenses reasonably relating to such sale) to such limited member.
VOC-26VOC-25
INDEX TO FINANCIAL STATEMENTS
| | | | |
PREDECESSOR: | | | | |
| | | VOC F-2 | |
| | | VOC F-3 | |
| | | VOC F-4 | |
| | | VOC F-5 | |
| | | VOC F-6 | |
| | | VOC F-7 | |
| | | | |
Introduction | | | VOC F-27F-24 | |
| | | VOC F-28F-25 | |
| | | VOC F-29F-26 | |
| | | VOC F-30F-27 | |
VOC F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
VOC Brazos Energy Partners, L.P.
We have audited the accompanying combined balance sheets of VOC Brazos Energy Partners, L.P. (“VOC Brazos”), together with interests in certain oil and natural gas properties of VOC Kansas Energy Partners, LLC (“KEP”) under common control with VOC Brazos (the “Common Control Properties”), as of December 31, 20082009 and 20092010 and the related combined statements of earnings, changes in partners’ capitalcapital/common control owners’ equity and cash flows for each of the three years in the period ended December 31, 2009.2010. 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, 20082009 and 2009,2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009,2010, in conformity with accounting principles generally accepted in the United States of America.
As discussed in note A4 to the combined financial statements, the Predecessor adopted new oil and gas reserve estimation and disclosure requirements as of December 31, 2009.
Grant Thornton LLP
Wichita, Kansas
December 29, 2010
March 22, 2011
VOC F-2
| | | | | | | | | | | | |
| | December 31, | | | September 30,
| |
| | 2008 | | | 2009 | | | 2010 | |
| | | | | | | | (Unaudited) | |
|
ASSETS |
CURRENT ASSETS | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 3,680,620 | | | $ | 4,931,842 | | | $ | 10,041,005 | |
Accounts receivable — oil and gas sales | | | 722,307 | | | | 1,090,371 | | | | 938,871 | |
Accounts receivable — oil and gas sales — related parties, net of allowance for doubtful accounts of $1,726,655 in 2008 and $1,007,594 in 2009 and 2010 | | | 2,781,714 | | | | 3,622,470 | | | | 3,889,717 | |
Settlement receivable on oil swap agreements | | | 513,751 | | | | — | | | | 31,262 | |
Oil swap agreements | | | 2,975,624 | | | | — | | | | 911,691 | |
Prepaid expenses | | | 70,802 | | | | 68,828 | | | | 127,200 | |
| | | | | | | | | | | | |
Total current assets | | | 10,744,818 | | | | 9,713,511 | | | | 15,939,746 | |
OIL AND GAS PROPERTIES | | | 108,124,590 | | | | 111,171,636 | | | | 118,974,942 | |
Less accumulated depreciation, depletion and amortization | | | 17,112,290 | | | | 22,098,350 | | | | 26,331,798 | |
| | | | | | | | | | | | |
| | | 91,012,300 | | | | 89,073,286 | | | | 92,643,144 | |
OTHER ASSETS | | | | | | | | | | | | |
Oil swap agreements | | | 5,385,249 | | | | 1,371,351 | | | | 333,700 | |
Deferred loan costs, net of accumulated amortization of $289,264 in 2008, $855,173 in 2009 and $1,263,354 in 2010 | | | 1,687,148 | | | | 1,121,357 | | | | 695,527 | |
Deferred offering costs | | | — | | | | — | | | | 14,268 | |
| | | | | | | | | | | | |
| | | 7,072,397 | | | | 2,492,708 | | | | 1,043,495 | |
| | | | | | | | | | | | |
| | $ | 108,829,515 | | | $ | 101,279,505 | | | $ | 109,626,385 | |
| | | | | | | | | | | | |
|
LIABILITIES AND PARTNERS’ CAPITAL/COMMON CONTROL OWNERS’ EQUITY |
CURRENT LIABILITIES | | | | | | | | | | | | |
Accounts payable | | | | | | | | | | | | |
Trade | | $ | 55,679 | | | $ | 46,517 | | | $ | 12,286 | |
Related parties | | | 819,583 | | | | 1,285,891 | | | | 1,415,526 | |
Accrued interest | | | 400,821 | | | | 146,839 | | | | 125,811 | |
Settlement payable on oil swap agreements | | | — | | | | 106,139 | | | | 35,757 | |
Accrued ad valorem taxes | | | 488,281 | | | | 378,040 | | | | 890,631 | |
Other accrued liabilities | | | 379,010 | | | | 377,411 | | | | 182,376 | |
Current maturities of notes payable | | | 1,802,902 | | | | 1,531,276 | | | | 267,193 | |
Oil swap agreements | | | — | | | | 1,580,850 | | | | — | |
| | | | | | | | | | | | |
Total current liabilities | | | 3,946,276 | | | | 5,452,963 | | | | 2,929,580 | |
LONG-TERM LIABILITIES, less current maturities | | | | | | | | | | | | |
Notes payable | | | 33,214,365 | | | | 25,661,011 | | | | 24,000,000 | |
Asset retirement obligation | | | 3,803,915 | | | | 2,653,676 | | | | 2,764,865 | |
| | | | | | | | | | | | |
| | | 37,018,280 | | | | 28,314,687 | | | | 26,764,865 | |
COMMITMENTS AND CONTINGENCIES | | | | | | | | | | | | |
| | | | | | | | | | | | |
PARTNERS’CAPITAL/COMMON CONTROL OWNERS’ EQUITY | | | | | | | | | | | | |
General partner capital account | | | 335,922 | | | | 483,527 | | | | 697,791 | |
Limited partners capital account | | | 42,073,523 | | | | 48,246,417 | | | | 57,776,184 | |
Common control owners’ equity | | | 17,428,336 | | | | 18,991,410 | | | | 20,513,302 | |
Accumulated other comprehensive income (loss) | | | 8,027,178 | | | | (209,499 | ) | | | 944,663 | |
| | | | | | | | | | | | |
| | | 67,864,959 | | | | 67,511,855 | | | | 79,931,940 | |
| | | | | | | | | | | | |
| | $ | 108,829,515 | | | $ | 101,279,505 | | | $ | 109,626,385 | |
| | | | | | | | | | | | |
| | | | | | | | |
| | December 31, | |
| | 2009 | | | 2010 | |
|
ASSETS |
CURRENT ASSETS | | | | | | | | |
Cash and cash equivalents | | $ | 4,931,842 | | | $ | 11,594,345 | |
Accounts receivable — oil and gas sales | | | 1,090,371 | | | | 1,091,745 | |
Accounts receivable — oil and gas sales — related parties, net of allowance for doubtful accounts of $1,007,594 in 2009 and $0 in 2010 | | | 3,622,470 | | | | 3,645,127 | |
Oil swap agreements | | | — | | | | 182,817 | |
Prepaid expenses | | | 68,828 | | | | 84,627 | |
| | | | | | | | |
Total current assets | | | 9,713,511 | | | | 16,598,661 | |
OIL AND GAS PROPERTIES | | | 111,171,636 | | | | 119,848,855 | |
Less accumulated depreciation, depletion and amortization | | | 22,098,350 | | | | 28,174,233 | |
| | | | | | | | |
| | | 89,073,286 | | | | 91,674,622 | |
OTHER ASSETS | | | | | | | | |
Oil swap agreements | | | 1,371,351 | | | | — | |
Deferred loan costs, net of accumulated amortization of $855,173 in 2009, and $1,403,726 in 2010 | | | 1,121,357 | | | | 555,155 | |
Deferred offering costs | | | — | | | | 209,272 | |
| | | | | | | | |
| | | 2,492,708 | | | | 764,427 | |
| | | | | | | | |
| | $ | 101,279,505 | | | $ | 109,037,710 | |
| | | | | | | | |
|
LIABILITIES AND PARTNERS’ CAPITAL/COMMON CONTROL OWNERS’ EQUITY |
CURRENT LIABILITIES | | | | | | | | |
Accounts payable | | | | | | | | |
Trade | | $ | 46,517 | | | $ | 68,854 | |
Related parties | | | 1,285,891 | | | | 770,513 | |
Accrued interest | | | 146,839 | | | | 63,742 | |
Settlement payable on oil swap agreements | | | 106,139 | | | | 228,961 | |
Distributions payable | | | — | | | | 9,995,900 | |
Accrued ad valorem taxes | | | 378,040 | | | | 499,596 | |
Other accrued liabilities | | | 377,411 | | | | 233,531 | |
Current maturities of notes payable | | | 1,531,276 | | | | — | |
Oil swap agreements | | | 1,580,850 | | | | — | |
| | | | | | | | |
Total current liabilities | | | 5,452,963 | | | | 11,861,097 | |
LONG-TERM LIABILITIES, less current maturities | | | | | | | | |
Notes payable | | | 25,661,011 | | | | 24,000,000 | |
Asset retirement obligation | | | 2,653,676 | | | | 2,240,501 | |
| | | | | | | | |
| | | 28,314,687 | | | | 26,240,501 | |
COMMITMENTS AND CONTINGENCIES | | | | | | | | |
| | | | | | | | |
PARTNERS’CAPITAL/COMMON CONTROL OWNERS’ EQUITY | | | | | | | | |
General partner capital account | | | 483,527 | | | | 571,419 | |
Limited partners capital account | | | 48,246,417 | | | | 51,213,862 | |
Common control owners’ equity | | | 18,991,410 | | | | 19,228,511 | |
Accumulated other comprehensive loss | | | (209,499 | ) | | | (77,680 | ) |
| | | | | | | | |
| | | 67,511,855 | | | | 70,936,112 | |
| | | | | | | | |
| | $ | 101,279,505 | | | $ | 109,037,710 | |
| | | | | | | | |
The accompanying notes are an integral part of these combined statements.
VOC F-3
| | | | | | | | | | | | | | | | | | | | |
| | | | | Nine Months Ended
| |
| | Year Ended December 31, | | | September 30, | |
| | 2007 | | | 2008 | | | 2009 | | | 2009 | | | 2010 | |
| | | | | | | | | | | (Unaudited) | |
|
Revenues | | | | | | | | | | | | | | | | | | | | |
Oil and gas sales | | $ | 21,289,980 | | | $ | 32,197,559 | | | $ | 25,745,771 | | | $ | 17,944,645 | | | $ | 29,089,570 | |
Other | | | — | | | | — | | | | 4,452 | | | | 4,443 | | | | 1,681 | |
| | | | | | | | | | | | | | | | | | | | |
| | | 21,289,980 | | | | 32,197,559 | | | | 25,750,223 | | | | 17,949,088 | | | | 29,091,251 | |
Costs and expenses | | | | | | | | | | | | | | | | | | | | |
Lease operating | | | 6,586,226 | | | | 7,667,332 | | | | 6,787,857 | | | | 5,053,546 | | | | 5,228,613 | |
Production and property taxes | | | 1,874,237 | | | | 2,531,660 | | | | 1,646,052 | | | | 1,257,919 | | | | 1,918,959 | |
Depreciation, depletion, amortization and accretion | | | 2,258,922 | | | | 5,780,829 | | | | 5,210,212 | | | | 4,325,407 | | | | 4,354,677 | |
Interest expense | | | 363,230 | | | | 1,382,725 | | | | 1,500,647 | | | | 1,168,229 | | | | 920,104 | |
Bad debt expense (recovery) | | | — | | | | 1,726,655 | | | | (719,061 | ) | | | (719,061 | ) | | | — | |
General and administrative | | | 120,518 | | | | 269,139 | | | | 463,295 | | | | 242,965 | | | | 111,576 | |
| | | | | | | | | | | | | | | | | | | | |
Total costs and expenses | | | 11,203,133 | | | | 19,358,340 | | | | 14,889,002 | | | | 11,329,005 | | | | 12,533,929 | |
| | | | | | | | | | | | | | | | | | | | |
Net earnings | | $ | 10,086,847 | | | $ | 12,839,219 | | | $ | 10,861,221 | | | $ | 6,620,083 | | | $ | 16,557,322 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | Year Ended December 31, | |
| | 2008 | | | 2009 | | | 2010 | |
|
Revenues | | | | | | | | | | | | |
Oil and gas sales | | $ | 32,197,559 | | | $ | 25,745,771 | | | $ | 38,603,599 | |
Other | | | — | | | | 4,452 | | | | 31,749 | |
| | | | | | | | | | | | |
| | | 32,197,559 | | | | 25,750,223 | | | | 38,635,348 | |
Costs and expenses | | | | | | | | | | | | |
Lease operating | | | 7,667,332 | | | | 6,787,857 | | | | 7,325,042 | |
Production and property taxes | | | 2,531,660 | | | | 1,646,052 | | | | 2,720,313 | |
Depreciation, depletion, amortization and accretion | | | 5,780,829 | | | | 5,210,212 | | | | 6,252,676 | |
Interest expense | | | 1,382,725 | | | | 1,500,647 | | | | 1,221,373 | |
Bad debt expense (recovery) | | | 1,726,655 | | | | (719,061 | ) | | | — | |
General and administrative | | | 269,139 | | | | 463,295 | | | | 204,575 | |
| | | | | | | | | | | | |
Total costs and expenses | | | 19,358,340 | | | | 14,889,002 | | | | 17,723,979 | |
| | | | | | | | | | | | |
Net earnings | | $ | 12,839,219 | | | $ | 10,861,221 | | | $ | 20,911,369 | |
| | | | | | | | | | | | |
The accompanying notes are an integral part of these combined statements.
VOC F-4
Predecessor
For the years ended December 31, 2007, 2008, 2009 and 2009
and for the nine-months ended September 30, 2010 (unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Redeemed
| | | New
| | | Common
| | | Accumulated
| | | | |
| | General
| | | Limited
| | | Limited
| | | Control
| | | Other
| | | | |
| | Partner
| | | Partner
| | | Partners
| | | Owners’
| | | Comprehensive
| | | | |
| | Capital | | | Capital | | | Capital | | | Equity | | | Income (Loss) | | | Total | |
|
Balance at January 1, 2007 | | $ | 259,713 | | | $ | 25,711,560 | | | $ | — | | | $ | 11,727,423 | | | $ | (1,618,966 | ) | | $ | 36,079,730 | |
Partners’ distributions | | | (58,820 | ) | | | (5,823,180 | ) | | | — | | | | — | | | | — | | | | (5,882,000 | ) |
Common control owners’ contributions | | | — | | | | — | | | | — | | | | 1,735,400 | | | | — | | | | 1,735,400 | |
Common control owners’ distributions | | | — | | | | — | | | | — | | | | (5,542,185 | ) | | | — | | | | (5,542,185 | ) |
Comprehensive income (loss) | | | | | | | | | | | | | | | | | | | | | | | | |
Net earnings for the year | | | 68,315 | | | | 6,763,165 | | | | — | | | | 3,255,367 | | | | — | | | | 10,086,847 | |
Reclassification adjustment for realized losses on swap transactions | | | — | | | | — | | | | — | | | | — | | | | 3,765,858 | | | | 3,765,858 | |
Change in fair value of swap agreements | | | — | | | | — | | | | — | | | | — | | | | (12,140,303 | ) | | | (12,140,303 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive income | | | | | | | | | | | | | | | | | | | | | | | 1,712,402 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2007 | | | 269,208 | | | | 26,651,545 | | | | — | | | | 11,176,005 | | | | (9,993,411 | ) | | | 28,103,347 | |
Partners’ capital contributions | | | — | | | | — | | | | 40,000,000 | | | | — | | | | — | | | | 40,000,000 | |
Partners’ distributions | | | (33,350 | ) | | | (73,301,650 | ) | | | — | | | | — | | | | — | | | | (73,335,000 | ) |
Common control owners’ contributions | | | — | | | | — | | | | — | | | | 5,128,500 | | | | — | | | | 5,128,500 | |
Common control owners’ distributions | | | — | | | | — | | | | — | | | | (5,169,277 | ) | | | — | | | | (5,169,277 | ) |
Comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | |
Net earnings for the year | | | 100,064 | | | | 4,372,524 | | | | 2,073,523 | | | | 6,293,108 | | | | | | | | 12,839,219 | |
Reclassification adjustment for realized losses on swap transactions | | | — | | | | — | | | | — | | | | — | | | | 5,939,518 | | | | 5,939,518 | |
Change in fair value of swap agreements | | | — | | | | — | | | | — | | | | — | | | | 12,081,071 | | | | 12,081,071 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive income | | | | | | | | | | | | | | | | | | | | | | | 30,859,808 | |
Step-up in basis of leasehold costs and lease equipment equal to the limited partner’s liquidating distribution in excess of the partner’s capital account | | | — | | | | 42,277,581 | | | | — | | | | — | | | | — | | | | 42,277,581 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2008 | | | 335,922 | | | | — | | | | 42,073,523 | | | | 17,428,336 | | | | 8,027,178 | | | | 67,864,959 | |
Common control owners’ contributions | | | — | | | | — | | | | — | | | | 400,000 | | | | — | | | | 400,000 | |
Common control owners’ distributions | | | — | | | | — | | | | — | | | | (3,377,648 | ) | | | — | | | | (3,377,648 | ) |
Comprehensive income (loss) | | | | | | | | | | | | | | | | | | | | | | | | |
Net earnings for the year | | | 147,605 | | | | — | | | | 6,172,894 | | | | 4,540,722 | | | | — | | | | 10,861,221 | |
Reclassification adjustment for realized gains on swap transactions | | | — | | | | — | | | | — | | | | — | | | | (1,347,010 | ) | | | (1,347,010 | ) |
Change in fair value of swap agreements | | | — | | | | — | | | | — | | | | — | | | | (6,889,667 | ) | | | (6,889,667 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive income | | | | | | | | | | | | | | | | | | | | | | | 2,624,544 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2009 | | | 483,527 | | | | — | | | | 48,246,417 | | | | 18,991,410 | | | | (209,499 | ) | | | 67,511,855 | |
Partners’ distributions (unaudited) | | | (6,500 | ) | | | — | | | | (318,500 | ) | | | — | | | | — | | | | (325,000 | ) |
Common control owners’ distributions (unaudited) | | | — | | | | — | | | | — | | | | (4,966,399 | ) | | | — | | | | (4,966,399 | ) |
Comprehensive income (unaudited) | | | | | | | | | | | | | | | | | | | | | | | | |
Net earnings for the period | | | 220,764 | | | | — | | | | 9,848,267 | | | | 6,488,291 | | | | — | | | | 16,557,322 | |
Reclassification adjustment for realized losses on swap transactions | | | — | | | | — | | | | — | | | | — | | | | 451,354 | | | | 451,354 | |
Change in fair value of swap agreements | | | — | | | | — | | | | — | | | | — | | | | 702,808 | | | | 702,808 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive income | | | | | | | | | | | | | | | | | | | | | | | 17,711,484 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Balance at September 30, 2010 (unaudited) | | $ | 697,791 | | | $ | — | | | $ | 57,776,184 | | | $ | 20,513,302 | | | $ | 944,663 | | | $ | 79,931,940 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Redeemed
| | | New
| | | Common
| | | Accumulated
| | | | |
| | General
| | | Limited
| | | Limited
| | | Control
| | | Other
| | | | |
| | Partner
| | | Partner
| | | Partners
| | | Owners’
| | | Comprehensive
| | | | |
| | Capital | | | Capital | | | Capital | | | Equity | | | Income (Loss) | | | Total | |
|
Balance at January 1, 2008 | | $ | 269,208 | | | $ | 26,651,545 | | | $ | — | | | $ | 11,176,005 | | | $ | (9,993,411 | ) | | $ | 28,103,347 | |
Partners’ capital contributions | | | — | | | | — | | | | 40,000,000 | | | | — | | | | — | | | | 40,000,000 | |
Partners’ distributions | | | (33,350 | ) | | | (73,301,650 | ) | | | — | | | | — | | | | — | | | | (73,335,000 | ) |
Common control owners’ contributions | | | — | | | | — | | | | — | | | | 5,128,500 | | | | — | | | | 5,128,500 | |
Common control owners’ distributions | | | — | | | | — | | | | — | | | | (5,169,277 | ) | | | — | | | | (5,169,277 | ) |
Comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | |
Net earnings for the year | | | 100,064 | | | | 4,372,524 | | | | 2,073,523 | | | | 6,293,108 | | | | | | | | 12,839,219 | |
Reclassification adjustment for realized losses on swap transactions | | | — | | | | — | | | | — | | | | — | | | | 5,939,518 | | | | 5,939,518 | |
Change in fair value of swap agreements | | | — | | | | — | | | | — | | | | — | | | | 12,081,071 | | | | 12,081,071 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive income | | | | | | | | | | | | | | | | | | | | | | | 30,859,808 | |
Step-up in basis of leasehold costs and lease equipment equal to the limited partner’s liquidating distribution in excess of the partner’s capital account | | | — | | | | 42,277,581 | | | | — | | | | — | | | | — | | | | 42,277,581 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2008 | | | 335,922 | | | | — | | | | 42,073,523 | | | | 17,428,336 | | | | 8,027,178 | | | | 67,864,959 | |
Common control owners’ contributions | | | — | | | | — | | | | — | | | | 400,000 | | | | — | | | | 400,000 | |
Common control owners’ distributions | | | — | | | | — | | | | — | | | | (3,377,648 | ) | | | — | | | | (3,377,648 | ) |
Comprehensive income (loss) | | | | | | | | | | | | | | | | | | | | | | | | |
Net earnings for the year | | | 147,605 | | | | — | | | | 6,172,894 | | | | 4,540,722 | | | | — | | | | 10,861,221 | |
Reclassification adjustment for realized gains on swap transactions | | | — | | | | — | | | | — | | | | — | | | | (1,347,010 | ) | | | (1,347,010 | ) |
Change in fair value of swap agreements | | | — | | | | — | | | | — | | | | — | | | | (6,889,667 | ) | | | (6,889,667 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive income | | | | | | | | | | | | | | | | | | | | | | | 2,624,544 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2009 | | | 483,527 | | | | — | | | | 48,246,417 | | | | 18,991,410 | | | | (209,499 | ) | | | 67,511,855 | |
Partner’s distributions | | | (186,500 | ) | | | — | | | | (9,138,500 | ) | | | — | | | | — | | | | (9,325,000 | ) |
Common control owners’ distributions | | | — | | | | — | | | | — | | | | (8,293,931 | ) | | | — | | | | (8,293,931 | ) |
Comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | |
Net earnings for the year | | | 274,392 | | | | — | | | | 12,105,945 | | | | 8,531,032 | | | | — | | | | 20,911,369 | |
Reclassification adjustment for realized losses on swap transactions | | | — | | | | — | | | | — | | | | — | | | | 1,123,965 | | | | 1,123,965 | |
Change in fair value of swap agreements | | | — | | | | — | | | | — | | | | — | | | | (992,146 | ) | | | (992,146 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive income | | | | | | | | | | | | | | | | | | | | | | | 21,043,188 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2010 | | $ | 571,419 | | | $ | — | | | $ | 51,213,862 | | | $ | 19,228,511 | | | $ | (77,680 | ) | | $ | 70,936,112 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these combined statements.
VOC F-5
| | | | | | | | | | | | | | | | | | | | |
| | | | | Nine Months Ended
| |
| | Year Ended December 31, | | | September 30, | |
| | 2007 | | | 2008 | | | 2009 | | | 2009 | | | 2010 | |
| | | | | | | | | | | (Unaudited) | |
|
Cash flows from operating activities | | | | | | | | | | | | | | | | | | | | |
Net earnings | | $ | 10,086,847 | | | $ | 12,839,219 | | | $ | 10,861,221 | | | $ | 6,620,083 | | | $ | 16,557,322 | |
Adjustments to reconcile net earnings to net cash provided by operating activities | | | | | | | | | | | | | | | | | | | | |
Depreciation, depletion, amortization and accretion | | | 2,258,922 | | | | 5,780,829 | | | | 5,210,212 | | | | 4,325,407 | | | | 4,354,677 | |
Amortization of deferred loan costs | | | 3,806 | | | | 285,154 | | | | 565,909 | | | | 424,431 | | | | 425,830 | |
Bad debt expense | | | — | | | | 1,726,655 | | | | — | | | | — | | | | — | |
Unrealized derivative (gain) loss | | | 3,250,583 | | | | (3,581,995 | ) | | | 333,695 | | | | 333,695 | | | | (300,728 | ) |
Settlements of asset retirement obligation | | | (1,737 | ) | | | (25,143 | ) | | | (27,149 | ) | | | (27,149 | ) | | | (235,053 | ) |
Change in operating assets and liabilities | | | | | | | | | | | | | | | | | | | | |
Accounts receivable | | | (1,304,197 | ) | | | (1,306,761 | ) | | | (1,208,820 | ) | | | (1,526,664 | ) | | | (115,747 | ) |
Settlement receivable on swap agreements | | | 46,170 | | | | (513,751 | ) | | | 513,751 | | | | 513,751 | | | | (31,262 | ) |
Prepaid expenses | | | 2,211 | | | | 5,432 | | | | 1,974 | | | | (745,603 | ) | | | (58,372 | ) |
Accounts payable | | | 180,332 | | | | (132,958 | ) | | | (109,862 | ) | | | 9,873 | | | | 69,998 | |
Accrued liabilities | | | 60,491 | | | | 228,828 | | | | (205,242 | ) | | | 179,877 | | | | 512,591 | |
Accrued interest payable | | | (3,421 | ) | | | 382,102 | | | | (253,982 | ) | | | (255,516 | ) | | | (21,028 | ) |
Settlement payable on swap agreements | | | 499,557 | | | | (713,268 | ) | | | 106,139 | | | | 16,965 | | | | (70,382 | ) |
| | | | | | | | | | | | | | | | | | | | |
Net cash provided by operating activities | | | 15,079,564 | | | | 14,974,343 | | | | 15,787,846 | | | | 9,869,150 | | | | 21,087,846 | |
Cash flows from investing activities | | | | | | | | | | | | | | | | | | | | |
Purchase of oil and gas properties and equipment | | | (3,452,245 | ) | | | (6,675,201 | ) | | | (2,151,315 | ) | | | (1,057,571 | ) | | | (2,298,690 | ) |
Well development cost | | | (1,372,221 | ) | | | (1,245,986 | ) | | | (1,582,563 | ) | | | (782,600 | ) | | | (5,449,232 | ) |
| | | | | | | | | | | | | | | | | | | | |
Net cash used in investing activities | | | (4,824,466 | ) | | | (7,921,187 | ) | | | (3,733,878 | ) | | | (1,840,171 | ) | | | (7,747,922 | ) |
Cash flows from financing activities | | | | | | | | | | | | | | | | | | | | |
Proceeds from issuance of notes payable | | | 750,000 | | | | 32,622,900 | | | | — | | | | — | | | | — | |
Payments on notes payable | | | (926,365 | ) | | | (1,293,757 | ) | | | (7,824,980 | ) | | | (7,444,767 | ) | | | (2,925,094 | ) |
Payment of deferred loan costs | | | (12,667 | ) | | | (1,958,881 | ) | | | (118 | ) | | | (118 | ) | | | — | |
Payment of deferred offering costs | | | — | | | | — | | | | — | | | | — | | | | (14,268 | ) |
Partners’ contributions | | | — | | | | 40,000,000 | | | | — | | | | — | | | | — | |
Partners’ distributions | | | (5,882,000 | ) | | | (73,335,000 | ) | | | — | | | | — | | | | (325,000 | ) |
Common control owners’ contributions | | | 1,735,400 | | | | 5,128,500 | | | | 400,000 | | | | 400,000 | | | | — | |
Common control owners’ distributions | | | (5,542,185 | ) | | | (5,169,277 | ) | | | (3,377,648 | ) | | | (2,751,138 | ) | | | (4,966,399 | ) |
| | | | | | | | | | | | | | | | | | | | |
Net cash used in financing activities | | | (9,877,817 | ) | | | (4,005,515 | ) | | | (10,802,746 | ) | | | (9,796,023 | ) | | | (8,230,761 | ) |
| | | | | | | | | | | | | | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | 377,281 | | | | 3,047,641 | | | | 1,251,222 | | | | (1,767,044 | ) | | | 5,109,163 | |
Cash and cash equivalents, beginning of period | | | 255,698 | | | | 632,979 | | | | 3,680,620 | | | | 3,680,620 | | | | 4,931,842 | |
| | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents, end of period | | $ | 632,979 | | | $ | 3,680,620 | | | $ | 4,931,842 | | | $ | 1,913,576 | | | $ | 10,041,005 | |
| | | | | | | | | | | | | | | | | | | | |
Supplemental cash flow information | | | | | | | | | | | | | | | | | | | | |
Cash paid during the period for interest | | $ | 362,845 | | | $ | 715,469 | | | $ | 1,188,720 | | | $ | 999,313 | | | $ | 515,302 | |
Noncash investing and financing activities | | | | | | | | | | | | | | | | | | | | |
Asset retirement costs and obligation recorded upon drilling of new oil and gas wells | | $ | 83,668 | | | $ | 238,516 | | | $ | 77,632 | | | $ | 9,038 | | | $ | 29,978 | |
Increase (decrease) in asset retirement cost and obligation due to changes in timing and estimated cash flows | | $ | 145,120 | | | $ | 1,067,315 | | | $ | (1,331,472 | ) | | $ | — | | | $ | — | |
Purchases of oil and gas properties and equipment and well development costs included in accounts payable at year end | | $ | 520,180 | | | $ | 227,927 | | | $ | 794,935 | | | $ | 138,400 | | | $ | 820,341 | |
Step-up in basis of oil and gas properties as a result of redemption of limited partners interest | | $ | — | | | $ | 42,277,581 | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | |
| | Year Ended December 31, | |
| | 2008 | | | 2009 | | | 2010 | |
|
Cash flows from operating activities | | | | | | | | | | | | |
Net earnings | | $ | 12,839,219 | | | $ | 10,861,221 | | | $ | 20,911,369 | |
Adjustments to reconcile net earnings to net cash provided by operating activities | | | | | | | | | | | | |
Depreciation, depletion, amortization and accretion | | | 5,780,829 | | | | 5,210,212 | | | | 6,252,676 | |
Amortization of deferred loan costs | | | 285,154 | | | | 565,909 | | | | 566,202 | |
Bad debt expense | | | 1,726,655 | | | | — | | | | — | |
Unrealized derivative (gain) loss | | | (3,581,995 | ) | | | 333,695 | | | | (260,497 | ) |
Settlements of asset retirement obligations | | | (25,143 | ) | | | (27,149 | ) | | | (245,649 | ) |
Change in operating assets and liabilities | | | | | | | | | | | | |
Accounts receivable | | | (1,306,761 | ) | | | (1,208,820 | ) | | | (24,031 | ) |
Settlement receivable on swap agreements | | | (513,751 | ) | | | 513,751 | | | | — | |
Prepaid expenses | | | 5,432 | | | | 1,974 | | | | (15,799 | ) |
Accounts payable | | | (132,958 | ) | | | (109,862 | ) | | | 254,496 | |
Accrued liabilities | | | 228,828 | | | | (205,242 | ) | | | 167,986 | |
Accrued interest payable | | | 382,102 | | | | (253,982 | ) | | | (83,097 | ) |
Settlement payable on swap agreements | | | (713,268 | ) | | | 106,139 | | | | 122,822 | |
| | | | | | | | | | | | |
Net cash provided by operating activities | | | 14,974,343 | | | | 15,787,846 | | | | 27,646,478 | |
Cash flows from investing activities | | | | | | | | | | | | |
Purchase of oil and gas properties and equipment | | | (6,675,201 | ) | | | (2,151,315 | ) | | | (2,729,757 | ) |
Well development cost | | | (1,245,986 | ) | | | (1,582,563 | ) | | | (7,229,628 | ) |
| | | | | | | | | | | | |
Net cash used in investing activities | | | (7,921,187 | ) | | | (3,733,878 | ) | | | (9,959,385 | ) |
Cash flows from financing activities | | | | | | | | | | | | |
Proceeds from issuance of notes payable | | | 32,622,900 | | | | — | | | | — | |
Payments on notes payable | | | (1,293,757 | ) | | | (7,824,980 | ) | | | (3,192,287 | ) |
Payment of deferred loan costs | | | (1,958,881 | ) | | | (118 | ) | | | — | |
Payment of deferred offering costs | | | — | | | | — | | | | (209,272 | ) |
Partners’ contributions | | | 40,000,000 | | | | — | | | | — | |
Partners’ distributions | | | (73,335,000 | ) | | | — | | | | (325,000 | ) |
Common control owners’ contributions | | | 5,128,500 | | | | 400,000 | | | | — | |
Common control owners’ distributions | | | (5,169,277 | ) | | | (3,377,648 | ) | | | (7,298,031 | ) |
| | | | | | | | | | | | |
Net cash used in financing activities | | | (4,005,515 | ) | | | (10,802,746 | ) | | | (11,024,590 | ) |
| | | | | | | | | | | | |
Net increase in cash and cash equivalents | | | 3,047,641 | | | | 1,251,222 | | | | 6,662,503 | |
Cash and cash equivalents, beginning of period | | | 632,979 | | | | 3,680,620 | �� | | | 4,931,842 | |
| | | | | | | | | | | | |
Cash and cash equivalents, end of period | | $ | 3,680,620 | | | $ | 4,931,842 | | | $ | 11,594,345 | |
| | | | | | | | | | | | |
Supplemental cash flow information | | | | | | | | | | | | |
Cash paid during the period for interest | | $ | 715,469 | | | $ | 1,188,720 | | | | 738,268 | |
Noncash investing and financing activities | | | | | | | | | | | | |
Asset retirement costs and obligation recorded upon drilling of new oil and gas wells | | $ | 238,516 | | | $ | 77,632 | | | | 33,879 | |
Increase (decrease) in asset retirement cost and obligation due to changes in timing and estimated cash flows | | $ | 1,067,315 | | | $ | (1,331,472 | ) | | | (553,292 | ) |
Purchases of oil and gas properties and equipment and well development costs included in accounts payable at year end | | $ | 227,927 | | | $ | 794,935 | | | | 47,398 | |
Step-up in basis of oil and gas properties as a result of redemption of limited partners interest | | $ | 42,277,581 | | | $ | — | | | | — | |
Partners’ and common control owners’ distributions included in distributions payable at year end | | $ | — | | | $ | — | | | $ | 9,995,900 | |
The accompanying notes are an integral part of these combined statements.
VOC F-6
Predecessor
For the years ended December 31, 2007, 2008, and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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,
VOC F-7
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
LLC has a 56.53% limited partner interest and Vess Texas Acquisition Group, LLC has a 41.47% limited partner interest. The excess of the $70 million liquidating distribution over TIFD III-X,
VOC F-7
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2008, 2009 and 2010
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. Interim financial statements
The financial information as of September 30, 2010 and for the nine months ended September 30, 2009 and 2010 is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the results of the interim periods. The results of operations for the nine month period ended September 30, 2010 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2010.
4.3. 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
VOC F-8
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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.
VOC F-8
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2008, 2009 and 2010
Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to the accumulated depreciation, depletion and amortization reserve. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major replacements and renewals are capitalized. All properties are stated at cost.
5.4. Revenue recognition
Revenues from the sale of oil and gas production are recognized as oil and gas is produced and sold.
6.5. 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 consistingconsist entirely of oil swap agreements, forof 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.
VOC F-9
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
7.6. 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. Except for the trade receivable from the former revenue intermediary/crude oil purchaser (see Note E), Predecessor considers the trade receivables to be fully collectible and has historically not experienced any collection issues.issues, except for the trade receivable from the former revenue intermediary/crude oil purchaser in 2008 (see Note E). If additional amounts become uncollectible, they will be charged to operations when that determination is made.
VOC F-9
8.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, 20082009 and 2009.2010.
9.8. Deferred loan costs
Deferred loan costs are being amortized over the term of the related loan and are included in interest expense.
10.9. 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.
11.10. 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.
VOC F-10
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
12.11. 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. Predecessor adopted new accounting guidance for uncertain tax positions in 2007. This adoption had no impact on the 2007 financial statements.
13.12. 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 discounted 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.
VOC F-10
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2008, 2009 and 2010
The estimated plug and abandon dates change routinely based upon additional engineering data and changes in the price of oil impacting the date when the well is no longer economically feasible to operate. The asset retirement obligation is measured on an annual basis based upon the then current plug and abandon dates of the wells using the original measurement date rates. Asset retirement obligations on new wells drilled are calculated on their initial measurement date based upon the then current interest rate environment.
14.13. 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 of ASU2010-04did 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 will provideprovides 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 toon our financial statements.
VOC F-11
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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. AdoptionThe adoption did not have a material effectimpact on our financial position, results of operations or cash flows.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, and2010. The adoption did not have a significantmaterial impact on Predecessor’sour financial position.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
VOC F-11
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2008, 2009 and 2010
amendment of ARB No. 51” ( FASB ASC 810). Adoption of ASU2010-21The adoption did not have a material impact on Predecessor’sour financial statements.
NOTE B — OIL AND GAS PROPERTIES
Oil and gas properties are carried at cost and consist of the following at:
| | | | | | | | | | | | |
| | December 31, | | | September 30,
| |
| | 2008 | | | 2009 | | | 2010 | |
| | | | | | | | (Unaudited) | |
|
Producing leaseholds | | $ | 72,833,236 | | | $ | 72,230,517 | | | $ | 72,176,496 | |
Lease equipment | | | 22,125,646 | | | | 23,820,846 | | | | 26,039,732 | |
Well development costs | | | 13,165,708 | | | | 15,120,273 | | | | 20,758,714 | |
| | | | | | | | | | | | |
| | | 108,124,590 | | | | 111,171,636 | | | | 118,974,942 | |
Less accumulated depreciation, depletion and amortization | | | 17,112,290 | | | | 22,098,350 | | | | 26,331,798 | |
| | | | | | | | | | | | |
Net oil and gas properties | | $ | 91,012,300 | | | $ | 89,073,286 | | | $ | 92,643,144 | |
| | | | | | | | | | | | |
VOC F-12
| | | | | | | | |
| | December 31, | |
| | 2009 | | | 2010 | |
|
Producing leaseholds | | $ | 72,230,517 | | | $ | 71,617,828 | |
Lease equipment | | | 23,820,846 | | | | 26,344,965 | |
Well development costs | | | 15,120,273 | | | | 21,886,062 | |
| | | | | | | | |
| | | 111,171,636 | | | | 119,848,855 | |
Less accumulated depreciation, depletion and amortization | | | 22,098,350 | | | | 28,174,233 | |
| | | | | | | | |
Net oil and gas properties | | $ | 89,073,286 | | | $ | 91,674,622 | |
| | | | | | | | |
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
Predecessor’s oil and gas activities are conducted entirely in the United States. Costs incurred in oil and gas producing activities for the periodsyears indicated are as follows:
| | | | | | | | | | | | | | | | | | | | |
| | December 31, | | | September 30, | |
| | 2007 | | | 2008 | | | 2009 | | | 2009 | | | 2010 | |
| | | | | | | | | | | (Unaudited) | |
|
Property acquisition costs | | $ | 3,535,913 | | | $ | 6,913,717 | | | $ | 2,228,947 | | | $ | 1,066,609 | | | $ | 2,328,668 | |
Development costs | | | 1,372,221 | | | | 1,245,986 | | | | 1,582,563 | | | | 782,600 | | | | 5,449,232 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | $ | 4,908,134 | | | $ | 8,159,703 | | | $ | 3,811,510 | | | $ | 1,849,209 | | | $ | 7,777,900 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | December 31, | |
| | 2008 | | | 2009 | | | 2010 | |
|
Property acquisition costs | | $ | 6,913,717 | | | $ | 2,228,947 | | | $ | 2,446,059 | |
Development costs | | | 1,245,986 | | | | 1,582,563 | | | | 6,765,789 | |
| | | | | | | | | | | | |
Total | | $ | 8,159,703 | | | $ | 3,811,510 | | | $ | 9,211,848 | |
| | | | | | | | | | | | |
The results of operations for oil and gas producing activities, excluding corporate overhead and interest costs for each of the three years ended December 31 and for the nine months ended September 302010 are as follows:
| | | | | | | | | | | | | | | | | | | | |
| | December 31, | | | September 30, | |
| | 2007 | | | 2008 | | | 2009 | | | 2009 | | | 2010 | |
| | | | | | | | | | | (Unaudited) | |
|
Revenues from oil and gas sales | | $ | 21,289,980 | | | $ | 32,197,559 | | | $ | 25,745,771 | | | $ | 17,944,645 | | | $ | 29,089,570 | |
Less: | | | | | | | | | | | | | | | | | | | | |
Lease operating expenses | | | 6,586,226 | | | | 7,667,332 | | | | 6,787,857 | | | | 5,053,546 | | | | 5,228,613 | |
Production and property taxes | | | 1,874,237 | | | | 2,531,660 | | | | 1,646,052 | | | | 1,257,919 | | | | 1,918,959 | |
Depreciation, depletion and amortization | | | 2,258,922 | | | | 5,780,829 | | | | 5,210,212 | | | | 4,325,407 | | | | 4,354,677 | |
Bad debt expense (recovery) | | | — | | | | 1,726,655 | | | | (719,061 | ) | | | (719,061 | ) | | | — | |
| | | | | | | | | | | | | | | | | | | | |
Income from oil and gas operations | | $ | 10,570,595 | | | $ | 14,491,083 | | | $ | 12,820,711 | | | $ | 8,026,834 | | | $ | 17,587,321 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | December 31, | | | | | | | |
| | 2008 | | | 2009 | | | 2010 | | | | | | | |
|
Revenues from oil and gas sales | | $ | 32,197,559 | | | $ | 25,745,771 | | | $ | 38,603,599 | | | | | | | | | |
Less: | | | | | | | | | | | | | | | | | | | | |
Lease operating expenses | | | 7,667,332 | | | | 6,787,857 | | | | 7,325,042 | | | | | | | | | |
Production and property taxes | | | 2,531,660 | | | | 1,646,052 | | | | 2,720,313 | | | | | | | | | |
Depreciation, depletion and amortization | | | 5,780,829 | | | | 5,210,212 | | | | 6,252,676 | | | | | | | | | |
Bad debt expense (recovery) | | | 1,726,655 | | | | (719,061 | ) | | | — | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Income from oil and gas operations | | $ | 14,491,083 | | | $ | 12,820,711 | | | $ | 22,305,568 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Lease operating expenses include those costs incurred to operate and maintain productive wells and related equipment and include costs such as labor, repairs and maintenance, materials, supplies, fuel consumed and insurance.
Depreciation, depletion and amortization include costs associated with capital acquisitions and development costs.
VOC F-13F-12
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008, and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
NOTE C — NOTES PAYABLE
Notes payable consist of the following at:
| | | | | | | | | | | | |
| | December 31, | | | September 30, | |
| | 2008 | | | 2009 | | | 2010 | |
| | | | | | | | (Unaudited) | |
|
Credit facility — see details below | | $ | 30,000,000 | | | $ | 24,000,000 | | | $ | 24,000,000 | |
Note payable to bank in monthly installments of $25,443 including interest at prime (prime was 4.00%, 3.25% and 3.25% at December 31, 2008 and 2009 and September 30, 2010, respectively), with final payment due in May 2013, collateralized by mortgages on oil and gas properties and guaranteed by two members of the Common Control Properties. Note was subsequently paid in full in November 2010 | | | 1,170,212 | | | | 876,964 | | | | 267,193 | |
Note payable to bank in monthly installments of $23,000 ($50,000 at December 31, 2008) including interest at prime (with a floor of 4.50% which was the effective interest rate at December 31, 2008 and 2009), with final payment due in July 2011, collateralized by mortgages on oil and gas properties and subsequently paid in full in August 2010 | | | 1,373,063 | | | | 831,563 | | | | — | |
Note payable to bank in monthly installments of $89,329 including interest at prime (with a floor of 4.00% which was the effective interest rate at December 31, 2008 and 2009 and September 30, 2010, with final payment due August 2011, collateralized by mortgages on oil and gas properties and subsequently paid in full in August 2010 | | | 2,473,992 | | | | 1,483,760 | | | | — | |
| | | | | | | | | | | | |
| | | 35,017,267 | | | | 27,192,287 | | | | 24,267,193 | |
Less current maturities | | | 1,802,902 | | | | 1,531,276 | | | | 267,193 | |
| | | | | | | | | | | | |
| | $ | 33,214,365 | | | $ | 25,661,011 | | | $ | 24,000,000 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | December 31, | | | | |
| | 2009 | | | 2010 | | | | |
|
Credit facility — see details below | | $ | 24,000,000 | | | $ | 24,000,000 | | | | | |
| | | | | | | | | | | | |
Note payable to bank in monthly installments of $25,443 including interest at prime (prime was 3.25% at December 31, 2009), with final payment due in May 2013, collateralized by mortgages on oil and gas properties and guaranteed by two members of the Common Control Properties. Note was paid in full in November 2010 | | | 876,964 | | | | — | | | | | |
| | | | | | | | | | | | |
Note payable to bank in monthly installments of $23,000 including interest at prime (with a floor of 4.50% which was the effective interest rate at December 31, 2009), with final payment due in July 2011, collateralized by mortgages on oil and gas properties and paid in full in August 2010 | | | 831,563 | | | | — | | | | | |
| | | | | | | | | | | | |
Note payable to bank in monthly installments of $89,329 including interest at prime (with a floor of 4.00% which was the effective interest rate at December 31, 2009), with final payment due August 2011, collateralized by mortgages on oil and gas properties and paid in full in August 2010 | | | 1,483,760 | | | | — | | | | | |
| | | | | | | | | | | | |
| | | 27,192,287 | | | | 24,000,000 | | | | | |
Less current maturities | | | 1,531,276 | | | | — | | | | | |
| | | | | | | | | | | | |
| | $ | 25,661,011 | | | $ | 24,000,000 | | | | | |
| | | | | | | | | | | | |
Credit facility
On June 27, 2008, in connection with the redemption and buy-out of the 99% limited partner, TIFD III-X, LLC, VOC Brazos entered into a credit agreement with a bank with a maximum commitment for Borrowing Base, Letters of Credit and Swing Line Loans in the amount of $100,000,000. The Borrowing Base 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, 2008 and 2009 and September 30, 2010 was 5.15375%, 2.37875% and 2.19438%2.12579%, respectively. Interest is paid no less than quarterly depending on the interest rate
VOC F-14
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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.
VOC F-13
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2008, 2009 and 2010
Letters of Credit:
The credit agreement with the bank provides for the issuance of letters of credit. When the lender issues a letter of credit, initial fees are charged and interest will be due based on the Eurodollar rate plus an applicable margin of 1.50% to 2.25% depending on the amount of Predecessor’s borrowing base currently being used. At December 31, 2008 and 2009 and September 30, 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, 2008 and 2009 and September 30, 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, 2009 and September 30, 2010.
The aggregate scheduled maturities of debt at December 31, 20092010 are as follows
| | | | |
2010 | | $ | 1,531,276 | |
2011 | | | 1,330,221 | |
2012 | | | 298,880 | |
2013 | | | 24,031,910 | |
| | | | |
| | $ | 27,192,287 | |
| | | | |
| | | | |
2011 | | $ | — | |
2012 | | | — | |
2013 | | | 24,000,000 | |
| | | | |
| | $ | 24,000,000 | |
| | | | |
NOTE D — FINANCIAL INSTRUMENTS
The Predecessor uses swap agreements to reduce the effects of fluctuations in crude oil prices. At December 31, 20082009 and 2009,2010, Predecessor’s hedging activities included swap agreements maturing through the yearin 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 237,552 barrels, 279,603 barrels, 213,933 barrels and 213,933198,571 barrels of crude oil production in the years
VOC F-15
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008, and 2009
and the nine months ended September 30, 2009 and 2010,
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
ended December 31, 2007, 2008 and 2009, respectively. Predecessor produced 386,879, 389,268, 407,414 barrels and 407,414494,876 barrels of crude oil in 2007, 2008, and 2009, respectively (unaudited). Predecessor had agreements covering 161,520 barrels and 155,893 barrels of crude oil production in the nine months ended September 30, 2009 and 2010, respectively (unaudited). Predecessor produced 298,192 barrels and 374,329 barrels of crude oil in the nine months ended September 30, 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 $3,996,252 and $8,118,212 for the yearsyear ended December 31, 2007 and 2008, respectively and net revenue recorded by Predecessor for swap agreements was $1,477,248 for the year ended December 31, 2009. Net expense recorded by Predecessor for swap agreements was $967,869 for the year ended December 31, 2010. Such amounts have been reflected as an adjustment to oil and gas sales in the statements of earnings.
VOC F-14
Predecessor recorded net revenue for swap agreements of $1,880,305 for
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the nine monthsyears ended September 30,December 31, 2008, 2009 and net expense for swap agreements of $451,354 for the nine months ended September 30, 2010 (unaudited). In addition, Predecessor has recorded income of $300,728 for the nine months ended September 30, 2010 (unaudited) which represents the ineffective portion of the unrealized gain on the hedge at September 30, 2010. These amounts have also been reflected as an adjustment to oil and gas sales in the statements of earnings.
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 an expense of $3,248,300 for the year ended December 31, 2007 and 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, 2008 and 2009 and September 30, 2010 (unaudited) are as follows:
| | | | | | | | | | | | | | | | |
2008 | | | Year | | | Notional Volume | | Fixed Price | | | Fair Value | |
|
| | | | | 2009 | (A) | | 28,800 bbls | | $ | 66.32 | | | $ | 333,695 | |
| | | | | 2009 | | | 185,133 bbls | | | 68.85 | | | | 2,641,929 | |
| | | | | 2010 | | | 174,571 bbls | | | 73.06 | | | | 1,535,360 | |
| | | | | 2011 | | | 159,894 bbls | | | 94.90 | | | | 3,849,889 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | $ | 8,360,873 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
2009 | | | Year | | | Notional Volume | | Fixed Price | | | Fair Value | |
|
| | | | | 2010 | | | 174,571 bbls | | | 73.06 | | | $ | (1,580,850 | ) |
| | | | | 2011 | | | 159,894 bbls | | | 94.90 | | | | 1,371,351 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | $ | (209,499 | ) |
| | | | | | | | | | | | | | | | |
VOC F-16
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
| | | | | | | | | | | | | | | | |
2010 | | | Year | | | Notional Volume | | Fixed Price | | | Fair Value | |
|
| | | | | 2010 | | | 42,678 bbls | | | 73.06 | | | $ | (345,524 | ) |
| | | | | 2011 | | | 159,894 bbls | | | 94.90 | | | | 1,590,915 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | $ | 1,245,391 | |
| | | | | | | | | | | | | | | | |
| | |
(A) | | Does not qualify as cash flow hedge. |
| | | | | | | | | | | | | | | | |
2009 | | | Year | | | Notional Volume | | Fixed Price | | | Fair Value | |
|
| | | | | 2010 | | | 174,571 bbls | | | 73.06 | | | $ | (1,580,850 | ) |
| | | | | 2011 | | | 159,894 bbls | | | 94.90 | | | | 1,371,351 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | $ | (209,499 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
2010 | | | Year | | | Notional Volume | | Fixed Price | | | Fair Value | |
|
| | | | | 2011 | | | 159,894 bbls | | | 94.90 | | | $ | 182,817 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
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, 2009,2010, 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, 20092010 expected to be reclassified into earnings in the next 12 months is $1,587,315.$77,681. See Note A6A5 for more discussion on derivatives.
NOTE E — RELATED PARTIES
Vess Texas Partners, LLC, the general partner of Predecessor, has common ownership with Vess Oil Corporation. Vess Oil Corporation serves as the primary operator of the oil and gas wells of the Partnership. In addition, the primary owner of the primary operator has a minority investment interest in the parent of the revenue intermediary prior to July 22, 2008. As a result of the bankruptcy discussed below, Vess Oil Corporation became the new revenue intermediary on July 22, 2008.
VOC F-17F-15
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008, and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
Below is a summary of transactions that occurred between Predecessor, its general partner, operator and revenue intermediary:
| | | | | | | | | | | | | | | | | | | | |
| | December 31, | | | September 30, | |
| | 2007 | | | 2008 | | | 2009 | | | 2009 | | | 2010 | |
| | | | | | | | | | | (Unaudited) | |
|
With operator/new revenue intermediary | | | | | | | | | | | | | | | | | | | | |
Lease operating expense incurred | | $ | 5,596,992 | | | $ | 6,705,544 | | | $ | 5,770,203 | | | $ | 4,305,905 | | | $ | 4,480,470 | |
Overhead costs included in lease operating expense | | $ | 406,054 | | | $ | 466,796 | | | $ | 548,873 | | | $ | 406,175 | | | $ | 447,213 | |
Reimbursement of overhead costs* | | $ | (255,882 | ) | | $ | (355,235 | ) | | $ | (353,020 | ) | | $ | (263,198 | ) | | $ | (260,742 | ) |
Capitalized lease equipment and producing leaseholds costs incurred | | $ | 999,864 | | | $ | 794,822 | | | $ | 1,394,856 | | | $ | 593,366 | | | $ | 2,304,551 | |
Payment of well development costs | | $ | 1,485,311 | | | $ | 1,004,078 | | | $ | 1,953,828 | | | $ | 745,881 | | | $ | 5,638,441 | |
Revenue receipts | | $ | — | | | $ | 7,447,596 | | | $ | 8,151,559 | | | $ | 5,000,851 | | | $ | 13,579,071 | |
With General Partner | | | | | | | | | | | | | | | | | | | | |
Overhead costs incurred* | | $ | 447,000 | | | $ | 447,000 | | | $ | 447,000 | | | $ | 335,250 | | | $ | 335,250 | |
With former revenue intermediary | | | | | | | | | | | | | | | | | | | | |
Revenue receipts | | $ | 1,961,996 | | | $ | 5,963,891 | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | |
| | December 31, | |
| | 2008 | | | 2009 | | | 2010 | |
|
With operator/new revenue intermediary | | | | | | | | | | | | |
Lease operating expense incurred | | $ | 6,705,544 | | | $ | 5,770,203 | | | $ | 6,066,454 | |
Overhead costs included in lease operating expense | | $ | 466,796 | | | $ | 548,873 | | | $ | 586,776 | |
Reimbursement of overhead costs* | | $ | (355,235 | ) | | $ | (353,020 | ) | | $ | (345,485 | ) |
Capitalized lease equipment and producing leaseholds costs incurred | | $ | 794,822 | | | $ | 1,394,856 | | | $ | 2,591,138 | |
Payment of well development costs | | $ | 1,004,078 | | | $ | 1,953,828 | | | $ | 6,765,790 | |
Revenue receipts | | $ | 7,447,596 | | | $ | 8,151,559 | | | $ | 18,087,204 | |
With General Partner | | | | | | | | | | | | |
Overhead costs incurred* | | $ | 447,000 | | | $ | 447,000 | | | $ | 447,000 | |
With former revenue intermediary | | | | | | | | | | | | |
Revenue receipts | | $ | 5,963,891 | | | $ | — | | | $ | — | |
| | |
* | | Upon dissolution of the former partnership (see Note A2), an agreement was reached between the former partners and operator with Predecessor and new operator. The agreement provided that the existing overhead agreement would continue to apply to all working interest owners other than Predecessor. Predecessor negotiated a new overhead arrangement with lower rates with the new operator, which includes a reimbursement to Predecessor for overhead amounts paid by the other working interest owners. The overhead charges, net of the reimbursement for the amounts paid by the other working interest owners, is included in operating expenses in the statements of earnings. |
VOC F-18
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
Following is a summary of balances due to/from related parties:
| | | | | | | | | | | | | | | | |
| | | | | Former
| | | | | | | |
| | | | | Revenue
| | | Crude Oil
| | | | |
| | Operator | | | Intermediary | | | Purchasers | | | Total | |
|
December 31, 2008 | | | | | | | | | | | | | | | | |
Accounts receivable | | $ | 1,036,818 | | | $ | 1,438,121 | | | $ | 2,033,430 | | | $ | 4,508,369 | |
Accounts payable | | $ | 819,583 | | | $ | — | | | $ | — | | | $ | 819,583 | |
Other accrued liabilities | | $ | 95,002 | | | $ | — | | | $ | — | | | $ | 95,002 | |
December 31, 2009 | | | | | | | | | | | | | | | | |
Accounts receivable | | $ | 2,167,284 | | | $ | — | | | $ | 2,462,780 | | | $ | 4,630,064 | |
Accounts payable | | $ | 1,285,891 | | | $ | — | | | $ | — | | | $ | 1,285,891 | |
September 30 2010 (Unaudited) | | | | | | | | | | | | | | | | |
Accounts receivable | | $ | 3,084,163 | | | $ | — | | | $ | 1,813,148 | | | $ | 4,897,311 | |
Accounts payable | | $ | 1,415,526 | | | $ | — | | | $ | — | | | $ | 1,415,526 | |
| | | | | | | | | | | | |
| | | | | Crude Oil
| | | | |
| | Operator | | | Purchasers | | | Total | |
|
December 31, 2009 | | | | | | | | | | | | |
Accounts receivable | | $ | 2,167,284 | | | $ | 2,462,780 | | | $ | 4,630,064 | |
Accounts payable | | $ | 1,285,891 | | | $ | — | | | $ | 1,285,891 | |
December 31, 2010 | | | | | | | | | | | | |
Accounts receivable | | $ | 2,878,164 | | | $ | 766,963 | | | $ | 3,645,127 | |
Accounts payable | | $ | 770,513 | | | $ | — | | | $ | 770,513 | |
As publicly reported on July 22, 2008, the former revenue intermediary/crude oil purchaser (Eaglwing L.P.) and its parent (SemGroup, L.P.) filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code. During this process, the monies that had been transferred to the revenue intermediary by certain of 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
VOC F-16
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2008, 2009 and 2010
recovered or the timing of such recovery, an allowance for doubtful accounts of $719,061 or 50% of the total estimated amount owed from Eaglwing, L.P. to Predecessor was established as of December 31, 2008. In addition, an allowance was set up for the oil purchased from the Common Control Properties in the amount of $1,007,594 which represents approximately 87% of June 2008 sales made to Eaglwing, L.P.
In 2009, Predecessor was successful in its suit and received $1,430,660 which resulted in a bad debt recovery of $719,061 as reflected in the 2009 statement of earnings. In regards to oil sales made to Eaglwing, L.P., Predecessor received 100% of the sales made to Eaglwing, L.P. from July 2, 2008 through July 22, 2008 in April 2010 and approximately 13% of the sales made to Eaglwing from June 1, 2008 through July 1, 2008 in October 2010.
A summary of sales and trade receivables with MV Purchasing, LLC, an affiliate of VOC Sponsor, follows:
| | | | | | | | | | | | | | | | | | | | |
| | | | | Nine Months Ended
| |
| | Year Ended December 31, | | | September 30, | |
| | 2007 | | | 2008 | | | 2009 | | | 2009 | | | 2010 | |
|
Sales | | $ | — | | | $ | 646,957 | | | $ | 5,993,119 | | | $ | 4,063,764 | | | $ | 6,239,438 | |
Trade Receivables | | $ | — | | | $ | 180,841 | | | $ | 610,191 | | | | | | | $ | 656,226 | |
VOC F-19
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | |
| | Year Ended December 31, | |
| | 2008 | | | 2009 | | | 2010 | |
|
Sales | | $ | 646,957 | | | $ | 5,993,119 | | | $ | 8,526,840 | |
Trade Receivables | | $ | 180,841 | | | $ | 610,191 | | | $ | 766,963 | |
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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 F.D.I.C. limits.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 82%, 80% and 83%76% of Predecessor’s trade receivables balance at December 31, 2008 and 2009 and September 30, 2010, (unaudited), respectively, was represented by two, three and twoone customers and the revenue intermediaries, respectively. Approximately 79%, 81%, 74%, 73% and 78%80% of sales for the years ended December 31, 2007, 2008, and 2009 and for the nine months ended September 30, 2009 and 2010, (unaudited), respectively, were made to three, four, three, three and three customers respectively. Management continually evaluates the credit worthiness of the customers and believes net amount recorded will be received.
Predecessor has entered into certain swap agreements as discussed in Note D.
VOC F-17
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2008, 2009 and 2010
NOTE G — ASSET RETIREMENT OBLIGATIONOBLIGATIONS
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, and for the period ended September 30, 2010 is as follows:
| | | | | | | | | | | | | | | | |
| | December 31, | | | September 30,
| |
| | 2007 | | | 2008 | | | 2009 | | | 2010 | |
| | | | | | | | | | | (Unaudited) | |
|
Asset retirement obligation — beginning of period | | $ | 2,285,964 | | | $ | 2,641,033 | | | $ | 4,075,952 | | | $ | 3,019,115 | |
Liabilities incurred during the period | | | 83,668 | | | | 238,516 | | | | 77,632 | | | | 29,978 | |
Liabilities settled during the period | | | (1,737 | ) | | | (25,143 | ) | | | (27,149 | ) | | | (235,053 | ) |
Accretion expense | | | 128,018 | | | | 154,231 | | | | 224,152 | | | | 121,229 | |
Increase (decrease) in asset retirement obligation due to changes in timing and changes in estimated cash flows | | | 145,120 | | | | 1,067,315 | | | | (1,331,472 | ) | | | — | |
| | | | | | | | | | | | | | | | |
Asset retirement obligation — end of period | | | 2,641,033 | | | | 4,075,952 | | | | 3,019,115 | | | | 2,935,269 | |
Less current portion included in other accrued liabilities | | | 80,844 | | | | 272,037 | | | | 365,439 | | | | 170,404 | |
| | | | | | | | | | | | | | | | |
Long-term portion | | $ | 2,560,189 | | | $ | 3,803,915 | | | $ | 2,653,676 | | | $ | 2,764,865 | |
| | | | | | | | | | | | | | | | |
VOC F-20
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | |
| | December 31, | |
| | 2008 | | | 2009 | | | 2010 | |
|
| | | | | | | | | | | | |
Asset retirement obligations — beginning of year | | $ | 2,641,033 | | | $ | 4,075,952 | | | $ | 3,019,115 | |
Liabilities incurred during the year | | | 238,516 | | | | 77,632 | | | | 33,879 | |
Liabilities settled during the year | | | (25,143 | ) | | | (27,149 | ) | | | (245,649 | ) |
Accretion expense | | | 154,231 | | | | 224,152 | | | | 161,577 | |
Increase (decrease) in asset retirement obligations due to changes in timing and changes in estimated cash flows | | | 1,067,315 | | | | (1,331,472 | ) | | | (553,292 | ) |
| | | | | | | | | | | | |
Asset retirement obligations — end of year | | | 4,075,952 | | | | 3,019,115 | �� | | | 2,415,630 | |
Less current portion included in other accrued liabilities | | | 272,037 | | | | 365,439 | | | | 175,129 | |
| | | | | | | | | | | | |
Long-term portion | | $ | 3,803,915 | | | $ | 2,653,676 | | | $ | 2,240,501 | |
| | | | | | | | | | | | |
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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 notenotes payable approximates fair value because the actual interest rates do not significantly differ from current rates offered for instruments with similar characteristics.
VOC F-18
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2008, 2009 and 2010
The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2008 and 2009 and September 30, 2010 (unaudited):2010:
| | | | | | | | | | | | |
| | Quoted Prices in
| | Significant Other
| | Unobservable
|
| | Active Markets
| | Observable Inputs
| | Inputs
|
| | (Level 1) | | (Level 2) | | (Level 3) |
|
Financial assets (liabilities): | | | | | | | | | | | | |
2008 Hedge agreements, net | | $ | — | | | $ | 8,360,873 | | | $ | — | |
2009 Hedge agreements, net | | $ | — | | | $ | (209,499 | ) | | $ | — | |
2010 Hedge agreements, net | | $ | — | | | $ | 1,245,391 | | | $ | — | |
2008 asset retirement obligations incurred | | $ | — | | | $ | — | | | $ | (238,516 | ) |
2009 asset retirement obligations incurred | | $ | — | | | $ | — | | | $ | (77,632 | ) |
2010 asset retirement obligations incurred | | $ | — | | | $ | — | | | $ | (29,978 | ) |
| | | | | | | | | | | | |
| | Quoted Prices in
| | Significant Other
| | Unobservable
|
| | Active Markets
| | Observable Inputs
| | Inputs
|
| | (Level 1) | | (Level 2) | | (Level 3) |
|
Financial assets (liabilities): | | | | | | | | | | | | |
2009 Hedge agreements, net | | $ | — | | | $ | (209,499 | ) | | $ | — | |
2010 Hedge agreements, net | | $ | — | | | $ | 182,817 | | | $ | — | |
2009 asset retirement obligations incurred | | $ | — | | | $ | — | | | $ | (77,632 | ) |
2010 asset retirement obligations incurred | | $ | — | | | $ | — | | | $ | (33,879 | ) |
Level 1 Fair Value Measurements
None.
Level 2 Fair Value Measurements
Hedge agreements — The fair value of hedge agreements has been established utilizing established index prices, oil future price curves and discount factors. These estimates are compared to the counterparty values for reasonableness. The hedge agreements are also subject to the risk that the counterparty will be unable to meet its obligations. Such non-performance risk is
VOC F-21
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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 A13A12 and G for further discussion.
NOTE I — COMMITMENTS AND CONTINGENCIES
The Partnership has entered into two drilling authorization for expenditure (AFE) agreements in late 2009 that total $3,738,210. As of December 31, 2009, the Partnership has incurred $843,483 leaving an estimated balance to completion remaining on these AFEs of $2,894,727.
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, 20092010 through December 29, 2010March 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 2010,2011, Predecessor has entered into five moretwo drilling AFEsauthorizations for expenditures totaling $5,644,195.$2,170,776.
VOC F-19
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2008, 2009 and 2010
On February 24, 2011 and on March 16, 2011, the predecessor entered into additional oil swap agreements maturing through 2013 with the same counterparty and similar terms as discussed in Note D. The notional volumes and fixed prices are as follows:
| | | | |
Year | | Notional Volume | | Fixed Price |
|
2011 | | 155,634 Bbls | | $100.25 - $100.70 |
2012 | | 315,889 Bbls | | $ 99.10 - $100.00 |
2013 | | 284,485 Bbls | | $ 97.30 - $ 98.45 |
NOTE K — DISCLOSURES ABOUT OIL AND GAS ACTIVITIES (UNAUDITED)
In December 2009, Predecessor adopted revised oil and gas reserve estimation and disclosure requirements. The primary impact of the new disclosures is to conform the definition of proved reserves to the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The new rules revised the definition of proved oil and gas reserves to require that the average,first-day-of-the-month price during 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 2006,
VOC F-22
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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, 2006, 2007, 2008, and 2009 and for the Common Control Properties as of December 31, 2007, 2008 and 20092010 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 accounting literature for OilSEC rules and Gas Extractive Activities.regulations. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” and “proved undeveloped” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.
The reserve data below represent estimates only and should not be construed as being exact. Moreover, the discounted values should not be construed as representative of the current market value of the oil and gas properties. A market value determination would include many additional factors including: (i) anticipated future oil and gas prices; (ii) the effect of federal income taxes, if any, on Predecessor; (iii) an allowance for return on investment; (iv) the effect of governmental legislation; (v) the value of additional potential reserves, not considered proved at present, which
VOC F-20
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2008, 2009 and 2010
may be recovered as a result of further exploration and development activities; and (vi) other business risks.
The following tables set forth (i) the estimated net quantities of proved, proved developed and proved undeveloped oil and natural gas reserves attributable to the oil and gas properties, and (ii) the standardized measure of the discounted future Net Profits Interest income attributable to the oil and gas properties and the nature of changes in such standardized measure between
VOC F-23
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
years. These tables are prepared on the accrual basis, which is the basis on which Predecessor maintains its production records.
ESTIMATED QUANTITIES OF OIL AND GAS RESERVES
| | | | | | | | | | | | | | | | |
| | Oil | | Gas | | | Oil | | Gas | |
| | (Bbls) | | (Mcf) | | | (Bbls) | | (Mcf) | |
|
Proved reserves: | | | | | | | | | | | | | | | | |
Balance at December 31, 2006 | | | 7,994,492 | | | | 4,241,321 | | |
Revisions of previous estimates | | | (332,769 | ) | | | 190,995 | | |
Purchase of minerals in place | | | 169,779 | | | | — | | |
Extension and discoveries | | | 9,883 | | | | 332,593 | | |
Production | | | (386,879 | ) | | | (390,593 | ) | |
| | | | | | |
Balance at December 31, 2007 | | | 7,454,506 | | | | 4,374,316 | | | | 7,454,506 | | | | 4,374,316 | |
Revisions of previous estimates | | | (790,795 | ) | | | (101,844 | ) | | | (790,795 | ) | | | (101,844 | ) |
Purchase of minerals in place | | | 221,536 | | | | 377,887 | | | | 221,536 | | | | 377,887 | |
Extensions and discoveries | | | 170 | | | | — | | | | 170 | | | | — | |
Production | | | (389,268 | ) | | | (426,326 | ) | | | (389,268 | ) | | | (426,326 | ) |
| | | | | | | | | | |
Balance at December 31, 2008 | | | 6,496,149 | | | | 4,224,033 | | | | 6,496,149 | | | | 4,224,033 | |
Revisions of previous estimates | | | 1,790,387 | | | | 634,099 | | | | 1,790,387 | | | | 634,099 | |
Purchase of minerals in place | | | 63,928 | | | | 59,689 | | | | 63,928 | | | | 59,689 | |
Extensions and discoveries | | | 149,533 | | | | — | | | | 149,533 | | | | — | |
Production | | | (407,415 | ) | | | (414,730 | ) | | | (407,415 | ) | | | (414,730 | ) |
| | | | | | | | | | |
Balance at December 31, 2009 | | | 8,092,582 | | | | 4,503,091 | | | | 8,092,582 | | | | 4,503,091 | |
Revisions of previous estimates | | | | 659,977 | | | | 1,041,826 | |
Production | | | | (494,876 | ) | | | (446,979 | ) |
| | | | | | |
Balance at December 31, 2010 | | | | 8,257,683 | | | | 5,097,938 | |
| | | | | | | | | | |
Proved developed reserves: | | | | | | | | | | | | | | | | |
December 31, 2006 | | | 7,317,964 | | | | 3,910,938 | | |
| | | | | | |
December 31, 2007 | | | 6,877,406 | | | | 4,116,158 | | | | 6,877,406 | | | | 4,116,158 | |
| | | | | | | | | | |
December 31, 2008 | | | 5,770,190 | | | | 3,928,995 | | | | 5,770,190 | | | | 3,928,995 | |
| | | | | | | | | | |
December 31, 2009 | | | 6,729,632 | | | | 3,854,008 | | | | 6,729,632 | | | | 3,854,008 | |
| | | | | | | | | | |
December 31, 2010 | | | | 6,799,873 | | | | 3,992,358 | |
| | | | | | |
Proved undeveloped reserves: | | | | | | | | | | | | | | | | |
December 31, 2006 | | | 676,528 | | | | 330,383 | | |
| | | | | | |
December 31, 2007 | | | 577,100 | | | | 258,158 | | | | 577,100 | | | | 258,158 | |
| | | | | | | | | | |
December 31, 2008 | | | 725,959 | | | | 295,038 | | | | 725,959 | | | | 295,038 | |
| | | | | | | | | | |
December 31, 2009 | | | 1,362,950 | | | | 649,083 | | | | 1,362,950 | | | | 649,083 | |
| | | | | | | | | | |
December 31, 2010 | | | | 1,457,810 | | | | 1,105,580 | |
| | | | | | |
Material Changes. The reserve reports for the Underlying Properties were prepared effective as of December 31, 2009. During the period from December 31, 2008 to December 31, 2009, VOC Sponsor drilled and completed one horizontal well in the Kurten Woodbine Unit at a cost of $1.5 million which converted 120 MBoe from proved undeveloped to proved developed reserves. VOC also drilled a second horizontal well that was being completed at year-end 2009 at a cost of $1.1 million which converted 120 MBoe from proved undeveloped to proved developed non-producing. As a result of the success, VOC Sponsor booked an additional 921 MBoe as proved
VOC F-24F-21
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008, and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
undeveloped reserves attributable to eight additional identified drilling locations in the Kurten Woodbine Unit.
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.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 $90.83/Bbl$44.60 per barrel for oil and $7.47/Mcf for natural gas at December 31, 2007, $39.49/Bbl for oil and $5.61/Mcf$5.62 per MMBtu for natural gas at December 31, 2008, and the unweighted arithmetic averagefirst-dayof-the-month first-day of-the-month prices for the prior 12 months were $55.82/Bbl$61.18 per barrel for oil and $4.58/Mcf$3.83 per MMBtu for natural gas at December 31, 2009. These2009 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 were adjustedper 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.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.
VOC F-25F-22
Predecessor
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
For the years ended December 31, 2007, 2008, and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
The estimated Standardized Measure relating to Predecessor’s proved reserves at December 31, 2007, 2008, 2009 and 20092010 is shown below:
| | | | | | | | | | | | |
| | 2007 | | | 2008 | | | 2009 | |
|
Future cash inflows | | $ | 709,982,661 | | | $ | 285,599,020 | | | $ | 479,804,227 | |
Future costs | | | | | | | | | | | | |
Production | | | (230,390,861 | ) | | | (152,898,120 | ) | | | (192,121,342 | ) |
Development | | | (8,755,334 | ) | | | (12,501,184 | ) | | | (25,183,887 | ) |
| | | | | | | | | | | | |
Future net cash flows | | | 470,836,466 | | | | 120,199,716 | | | | 262,498,998 | |
Less 10% discount factor | | | (264,326,635 | ) | | | (60,259,262 | ) | | | (142,117,093 | ) |
| | | | | | | | | | | | |
Standardized measure of discounted future net cash flows | | $ | 206,509,831 | | | $ | 59,940,454 | | | $ | 120,381,905 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | 2008 | | | 2009 | | | 2010 | |
|
Future cash inflows | | $ | 285,599,020 | | | $ | 479,804,227 | | | $ | 648,185,108 | |
Future costs | | | | | | | | | | | | |
Production | | | (152,898,120 | ) | | | (192,121,342 | ) | | | (223,916,334 | ) |
Development | | | (12,501,184 | ) | | | (25,183,887 | ) | | | (25,384,253 | ) |
| | | | | | | | | | | | |
Future net cash flows | | | 120,199,716 | | | | 262,498,998 | | | | 398,884,521 | |
Less 10% discount factor | | | (60,259,262 | ) | | | (142,117,093 | ) | | | (218,408,117 | ) |
| | | | | | | | | | | | |
Standardized measure of discounted future net cash flows | | $ | 59,940,454 | | | $ | 120,381,905 | | | $ | 180,476,404 | |
| | | | | | | | | | | | |
The following table sets forth the changes in the Standardized Measure applicable to Predecessor’s proved oil and natural gas reserves for the years ended December 31, 2007, 2008, 2009 and 2009:2010:
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED OIL AND GAS RESERVES
| | | | | | | | | | | | | | | | | | | | | | | | |
| | 2007 | | 2008 | | 2009 | | | 2008 | | 2009 | | 2010 | |
|
Standardized measure at beginning of year | | $ | 139,990,054 | | | $ | 206,509,831 | | | $ | 59,940,454 | | | $ | 206,509,831 | | | $ | 59,940,454 | | | $ | 120,381,905 | |
Sales of oil and gas produced, net of production costs | | | (20,049,955 | ) | | | (29,744,163 | ) | | | (15,788,110 | ) | | | (29,744,163 | ) | | | (15,788,110 | ) | | | (29,265,616 | ) |
Net changes in price and production costs | | | 67,422,650 | | | | (154,951,804 | ) | | | 41,451,566 | | | | (154,951,804 | ) | | | 41,451,566 | | | | 52,703,598 | |
Extensions, discoveries and improved recovery, net of future production and development costs | | | 2,246,681 | | | | 5,822 | | | | 5,890,961 | | | | 5,822 | | | | 5,890,961 | | | | — | |
Changes in estimated future development costs | | | 222,643 | | | | (2,726,749 | ) | | | (14,381,027 | ) | | | (2,726,749 | ) | | | (14,381,027 | ) | | | (14,568,030 | ) |
Development costs incurred during the period which reduce future development costs | | | 1,200,100 | | | | 52,800 | | | | 2,700,100 | | | | 52,800 | | | | 2,700,100 | | | | 7,599,939 | |
Revisions of quantity estimates | | | (8,530,591 | ) | | | (7,982,910 | ) | | | 29,413,203 | | | | (7,982,910 | ) | | | 29,413,203 | | | | 15,664,245 | |
Accretion of discount | | | 13,999,005 | | | | 20,650,983 | | | | 5,994,045 | | | | 20,650,983 | | | | 5,994,045 | | | | 12,038,190 | |
Purchase of reserves in place | | | 10,959,750 | | | | 4,831,610 | | | | 1,567,625 | | | | 4,831,610 | | | | 1,567,625 | | | | — | |
Change in production rates, timing and other | | | (950,506 | ) | | | 23,295,034 | | | | 3,593,088 | | | | 23,295,034 | | | | 3,593,088 | | | | 15,922,173 | |
| | | | | | | | | | | | | | |
Standardized measure at end of year | | $ | 206,509,831 | | | $ | 59,940,454 | | | $ | 120,381,905 | | | $ | 59,940,454 | | | $ | 120,381,905 | | | $ | 180,476,404 | |
| | | | | | | | | | | | | | |
VOC F-26F-23
Predecessor
The following unaudited pro forma financial statements have been prepared to illustrate the acquisition of the Acquired Properties and the conveyance of a Net Profits Interest in all the Underlying Properties by VOC Sponsor to the Trust and distribution by VOC Sponsor to its limited partners of the net proceeds of this offering including the sale of trust units to VOC Partners, LLC, an affiliate of VOC Sponsor, 45 days after the closing of this offering. The unaudited pro forma balance sheet is presented as of September 30,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 September 30,December 31, 2010. The unaudited pro forma statementsstatement of earnings present the historical statements of earnings of VOC Sponsor for the year ended December 31, 2009 and the nine months ended September 30, 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, 20092010 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.
VOC F-27F-24
| | | | | | | | | | | | | | | | | | | | |
| | September 30, 2010 | |
| | | | | | | | | | | Additional
| | | Pro Forma
| |
| | Historical | | | Adjustments (a) | | | Pro Forma | | | Adjustments | | | as Adjusted | |
|
Cash and cash equivalents | | $ | 10,041,005 | | | $ | 13,178 | | | $ | 10,054,183 | | | | — | (b) | | | 10,054,183 | |
Accounts receivable — oil and gas sales | | | 938,871 | | | | 1,014,020 | | | | 1,952,891 | | | | — | | | | 1,952,891 | |
Accounts receivable — oil and gas sales — related parties, net of allowance for doubtful accounts of $1,007,594 | | | 3,889,717 | | | | 1,074,812 | | | | 4,964,529 | | | | — | | | | 4,964,529 | |
Settlement receivable on oil swap agreements | | | 31,262 | | | | — | | | | 31,262 | | | | — | | | | 31,262 | |
Receivable from Trust | | | — | | | | — | | | | — | | | | 339,234 | (d) | | | 339,234 | |
Note receivable — related parties | | | — | | | | — | | | | — | | | | 33,097,222 | (c) | | | 33,097,222 | |
Oil Swap agreements | | | 911,691 | | | | — | | | | 911,691 | | | | — | | | | 911,691 | |
Prepaid expenses | | | 127,200 | | | | — | | | | 127,200 | | | | — | | | | 127,200 | |
| | | | | | | | | | | | | | | | | | | | |
Total current assets | | | 15,939,746 | | | | 2,102,010 | | | | 18,041,756 | | | | 33,436,456 | | | | 51,478,212 | |
| | | | | | | | | | | | | | | | | | | | |
OIL AND GAS PROPERTIES | | | 118,974,942 | | | | 61,206,695 | | | | 180,181,637 | | | | (144,145,310 | )(d) | | | 36,036,327 | |
Less accumulated depreciation, depletion and amortization | | | 26,331,798 | | | | — | | | | 26,331,798 | | | | (21,065,438 | ) (d) | | | 5,266,360 | |
| | | | | | | | | | | | | | | | | | | | |
| | | 92,643,144 | | | | 61,206,695 | | | | 153,849,839 | | | | (123,079,872 | ) (d) | | | 30,769,967 | |
OTHER ASSETS | | | | | | | | | | | | | | | | | | | | |
Oil swap agreements | | | 333,700 | | | | — | | | | 333,700 | | | | — | | | | 333,700 | |
Receivable from Trust | | | — | | | | — | | | | — | | | | 1,942,872 | (d) | | | 1,942,872 | |
Deferred loan costs, net of accumulated amortization of $1,263,354 | | | 695,527 | | | | — | | | | 695,527 | | | | — | | | | 695,527 | |
Deferred offering costs | | | 14,268 | | | | 336,048 | | | | 350,316 | | | | (350,316 | ) (e) | | | — | |
| | | | | | | | | | | | | | | | | | | | |
| | | 1,043,495 | | | | 336,048 | | | | 1,379,543 | | | | 1,592,556 | | | | 2,972,099 | |
| | | | | | | | | | | | | | | | | | | | |
| | $ | 109,626,385 | | | $ | 63,644,753 | | | $ | 173,271,138 | | | $ | (88,050,860 | ) | | $ | 85,220,278 | |
| | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND PARTNERS’ CAPITAL/COMMON CONTROL OWNERS’ EQUITY (DEFICIT) |
CURRENT LIABILITIES | | | | | | | | | | | | | | | | | | | | |
Accounts payable | | | | | | | | | | | | | | | | | | | | |
Trade | | $ | 12,286 | | | $ | 127,356 | | | $ | 139,642 | | | $ | — | | | $ | 139,642 | |
Related parties | | | 1,415,526 | | | | 615,059 | | | | 2,030,585 | | | | — | | | | 2,030,585 | |
Accrued interest | | | 125,811 | | | | — | | | | 125,811 | | | | — | | | | 125,811 | |
Settlement payable on oil swap agreements | | | 35,757 | | | | — | | | | 35,757 | | | | — | | | | 35,757 | |
Accrued ad valorem taxes | | | 890,631 | | | | 496,458 | | | | 1,387,089 | | | | — | | | | 1,387,089 | |
Other accrued liabilities | | | 182,376 | | | | 403,770 | | | | 586,146 | | | | — | | | | 586,146 | |
Due to Trust | | | | | | | | | | | | | | | 729,353 | (d) | | | 729,353 | |
Deferred gain on sale | | | | | | | | | | | | | | | 7,235,963 | (e) | | | 7,235,963 | |
Current maturities of notes payable | | | 267,193 | | | | — | | | | 267,193 | | | | — | | | | 267,193 | |
| | | | | | | | | | | | | | | | | | | | |
Total current liabilities | | | 2,929,580 | | | | 1,642,643 | | | | 4,572,223 | | | | 7,965,316 | | | | 12,537,539 | |
LONG-TERM LIABILITIES, less current maturities | | | | | | | | | | | | | | | | | | | | |
Notes payable | | | 24,000,000 | | | | — | | | | 24,000,000 | | | | — | | | | 24,000,000 | |
Deferred gain on sale | | | — | | | | — | | | | — | | | | 73,174,296 | (e) | | | 73,174,296 | |
Due to Trust | | | — | | | | — | | | | — | | | | 266,960 | (d) | | | 266,960 | |
Asset retirement obligation | | | 2,764,865 | | | | 2,057,585 | | | | 4,822,450 | | | | — | | | | 4,822,450 | |
| | | | | | | | | | | | | | | | | | | | |
| | | 26,764,865 | | | | 2,057,585 | | | | 28,822,450 | | | | 73,441,256 | | | | 102,263,706 | |
PARTNERS’ CAPITAL/COMMON CONTROL OWNERS’ EQUITY (DEFICIT) | | | | | | | | | | | | | | | | | | | | |
General partner capital account | | | 697,791 | | | | — | | | | 697,791 | | | | (1,349,220 | )(f) | | | (651,429 | ) |
Limited partner capital account | | | 57,776,184 | | | | — | | | | 57,776,184 | | | | (66,121,443 | ) (g) | | | (8,345,259 | ) |
Common control owners’ equity | | | 20,513,302 | | | | 59,944,525 | | | | 80,457,827 | | | | (101,986,769 | ) (h) | | | (21,528,942 | ) |
Accumulated other comprehensive income | | | 944,663 | | | | — | | | | 944,663 | | | | — | | | | 944,663 | |
| | | | | | | | | | | | | | | | | | | | |
| | | 79,931,940 | | | | 59,944,525 | | | | 139,876,465 | | | | (169,457,432 | ) | | | (29,580,967 | ) |
| | | | | | | | | | | | | | | | | | | | |
| | $ | 109,626,385 | | | $ | 63,644,753 | | | $ | 173,271,138 | | | $ | (88,050,860 | ) | | $ | 85,220,278 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2010 | |
| | | | | | | | | | | Additional
| | | Pro Forma
| |
| | Historical | | | Adjustments (a) | | | Pro Forma | | | Adjustments | | | as Adjusted | |
|
Cash and cash equivalents | | $ | 11,594,345 | | | $ | — | | | $ | 11,594,345 | | | $ | — | (b) | | $ | 11,594,345 | |
Accounts receivable — oil and gas sales | | | 1,091,745 | | | | 1,198,682 | | | | 2,290,427 | | | | — | | | | 2,290,427 | |
Accounts receivable — oil and gas sales — related parties | | | 3,645,127 | | | | 993,178 | | | | 4,638,305 | | | | — | | | | 4,638,305 | |
Receivable from Trust | | | — | | | | — | | | | — | | | | 349,674 | (d) | | | 349,674 | |
Note receivable — related parties | | | — | | | | — | | | | — | | | | 38,786,916 | (c) | | | 38,786,916 | |
Oil Swap agreements | | | 182,817 | | | | — | | | | 182,817 | | | | — | | | | 182,817 | |
Prepaid expenses | | | 84,627 | | | | — | | | | 84,627 | | | | — | | | | 84,627 | |
| | | | | | | | | | | | | | | | | | | | |
Total current assets | | | 16,598,661 | | | | 2,191,860 | | | | 18,790,521 | | | | 39,136,590 | | | | 57,927,111 | |
| | | | | | | | | | | | | | | | | | | | |
OIL AND GAS PROPERTIES | | | 119,848,855 | | | | 90,941,091 | | | | 210,789,946 | | | | (168,631,957 | )(d) | | | 42,157,989 | |
Less accumulated depreciation, depletion and amortization | | | 28,174,233 | | | | — | | | | 28,174,233 | | | | (22,539,386 | ) (d) | | | 5,634,847 | |
| | | | | | | | | | | | | | | | | | | | |
| | | 91,674,622 | | | | 90,941,091 | | | | 182,615,713 | | | | (146,092,571 | ) (d) | | | 36,523,142 | |
OTHER ASSETS | | | | | | | | | | | | | | | | | | | | |
Receivable from Trust | | | — | | | | — | | | | — | | | | 1,352,490 | (d) | | | 1,352,490 | |
Deferred loan costs, net of accumulated amortization of $1,403,726 | | | 555,155 | | | | — | | | | 555,155 | | | | — | | | | 555,155 | |
Deferred offering costs | | | 209,272 | | | | — | | | | 209,272 | | | | (209,272 | ) (e) | | | — | |
| | | | | | | | | | | | | | | | | | | | |
| | | 764,427 | | | | — | | | | 764,427 | | | | 1,143,218 | | | | 1,907,645 | |
| | | | | | | | | | | | | | | | | | | | |
| | $ | 109,037,710 | | | $ | 93,132,951 | | | $ | 202,170,661 | | | $ | (105,812,763 | ) | | $ | 96,357,898 | |
| | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND PARTNERS’ CAPITAL/COMMON CONTROL OWNERS’ EQUITY (DEFICIT) |
CURRENT LIABILITIES | | | | | | | | | | | | | | | | | | | | |
Accounts payable | | | | | | | | | | | | | | | | | | | | |
Trade | | $ | 68,854 | | | $ | 15,798 | | | $ | 84,652 | | | $ | — | | | $ | 84,652 | |
Related parties | | | 770,513 | | | | 626,830 | | | | 1,397,343 | | | | — | | | | 1,397,343 | |
Accrued interest | | | 63,742 | | | | — | | | | 63,742 | | | | — | | | | 63,742 | |
Settlement payable on oil swap agreements | | | 228,961 | | | | — | | | | 228,961 | | | | — | | | | 228,961 | |
Distributions payable | | | 9,995,900 | | | | 1,549,232 | | | | 11,545,132 | | | | — | | | | 11,545,132 | |
Accrued ad valorem taxes | | | 499,596 | | | | 491,392 | | | | 990,988 | | | | — | | | | 990,988 | |
Other accrued liabilities | | | 233,531 | | | | 261,964 | | | | 495,495 | | | | — | | | | 495,495 | |
Due to Trust | | | — | | | | — | | | | — | | | | 146,254 | (d) | | | 146,254 | |
Deferred gain on sale | | | — | | | | — | | | | — | | | | 8,759,435 | (e) | | | 8,759,435 | |
| | | | | | | | | | | | | | | | | | | | |
Total current liabilities | | | 11,861,097 | | | | 2,945,216 | | | | 14,806,313 | | | | 8,905,689 | | | | 23,712,002 | |
LONG-TERM LIABILITIES, less current maturities | | | | | | | | | | | | | | | | | | | | |
Notes payable | | | 24,000,000 | | | | — | | | | 24,000,000 | | | | (24,000,000 | ) (b) | | | — | |
Deferred gain on sale | | | — | | | | — | | | | — | | | | 95,586,548 | (e) | | | 95,586,548 | |
Asset retirement obligation | | | 2,240,501 | | | | 1,564,872 | | | | 3,805,373 | | | | — | | | | 3,805,373 | |
| | | | | | | | | | | | | | | | | | | | |
| | | 26,240,501 | | | | 1,564,872 | | | | 27,805,373 | | | | 71,586,548 | | | | 99,391,921 | |
PARTNERS’ CAPITAL/COMMON CONTROL OWNERS’ EQUITY (DEFICIT) | | | | | | | | | | | | | | | | | | | | |
General partner capital account | | | 571,419 | | | | — | | | | 571,419 | | | | (1,483,360 | )(f) | | | (911,941 | ) |
Limited partner capital account | | | 51,213,862 | | | | — | | | | 51,213,862 | | | | (72,695,279 | ) (g) | | | (21,481,417 | ) |
Common control owners’ equity | | | 19,228,511 | | | | 88,622,863 | | | | 107,851,374 | | | | (112,126,361 | ) (h) | | | (4,274,987 | ) |
Accumulated other comprehensive loss | | | (77,680 | ) | | | — | | | | (77,680 | ) | | | — | | | | (77,680 | ) |
| | | | | | | | | | | | | | | | | | | | |
| | | 70,936,112 | | | | 88,622,863 | | | | 159,558,975 | | | | (186,305,000 | ) | | | (26,746,025 | ) |
| | | | | | | | | | | | | | | | | | | | |
| | $ | 109,037,710 | | | $ | 93,132,951 | | | $ | 202,170,661 | | | $ | (105,812,763 | ) | | $ | 96,357,898 | |
| | | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these unaudited pro forma financial statements.
VOC F-28F-25
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2009 | | | | Nine Months Ended September 30, 2010 | |
| | | | | | | | | | | | | | Pro
| | | | | | | | | | | | | | | | Pro
| |
| | | | | (a)
| | | Pro
| | | Additional
| | | Forma as
| | | | | | | (a)
| | | Pro
| | | Additional
| | | Forma as
| |
| | Historical | | | Adjustments | | | Forma | | | Adjustments | | | Adjusted | | | | Historical | | | Adjustments | | | Forma | | | Adjustments | | | Adjusted | |
Revenues | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Oil and gas sales | | $ | 25,745,771 | | | $ | 18,383,029 | | | $ | 44,128,800 | | | $ | (35,303,040 | )(i) | | $ | 8,825,760 | | | | $ | 29,089,570 | | | $ | 17,981,276 | | | $ | 47,070,846 | | | $ | (37,656,677 | )(i) | | $ | 9,414,169 | |
Gain on sale of assets | | | — | | | | — | | | | — | | | | 7,005,413 | (j) | | | 7,005,413 | | | | | — | | | | — | | | | — | | | | 5,216,956 | (j) | | | 5,216,956 | |
Other | | | 4,452 | | | | — | | | | 4,452 | | | | — | | | | 4,452 | | | | | 1,681 | | | | — | | | | 1,681 | | | | — | | | | 1,681 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 25,750,223 | | | | 18,383,029 | | | | 44,133,252 | | | | (28,297,627 | ) | | | 15,835,625 | | | | | 29,091,251 | | | | 17,981,276 | | | | 47,072,527 | | | | (32,439,721 | ) | | | 14,632,806 | |
Costs and expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Lease operating | | | 6,787,857 | | | | 5,969,210 | | | | 12,757,067 | | | | (10,205,654 | )(k) | | | 2,551,413 | | | | | 5,228,613 | | | | 4,690,168 | | | | 9,918,781 | | | | (7,935,024 | )(k) | | | 1,983,757 | |
Production and property taxes | | | 1,646,052 | | | | 1,169,799 | | | | 2,815,851 | | | | (2,252,681 | )(l) | | | 563,170 | | | | | 1,918,959 | | | | 950,133 | | | | 2,869,092 | | | | (2,295,274 | )(l) | | | 573,818 | |
Depreciation, depletion, amortization and accretion | | | 5,210,212 | | | | 4,883,586 | | | | 10,093,798 | | | | (7,847,694 | )(m) | | | 2,246,104 | | | | | 4,354,677 | | | | 3,369,504 | | | | 7,724,181 | | | | (5,968,621 | )(m) | | | 1,755,560 | |
Interest expense | | | 1,500,647 | | | | — | | | | 1,500,647 | | | | — | | | | 1,500,647 | | | | | 920,104 | | | | — | | | | 920,104 | | | | — | | | | 920,104 | |
Bad debt expense (recovery) | | | (719,061 | ) | | | — | | | | (719,061 | ) | | | — | | | | (719,061 | ) | | | | — | | | | — | | | | — | | | | — | | | | — | |
General and administrative | | | 463,295 | | | | — | | | | 463,295 | | | | — | | | | 463,295 | | | | | 111,576 | | | | 18,518 | | | | 130,094 | | | | — | | | | 130,094 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total costs and expenses | | | 14,889,002 | | | | 12,022,595 | | | | 26,911,597 | | | | (20,306,029 | ) | | | 6,605,568 | | | | | 12,533,929 | | | | 9,028,323 | | | | 21,562,252 | | | | (16,198,919 | ) | | | 5,363,333 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net earnings | | $ | 10,861,221 | | | $ | 6,360,434 | | | $ | 17,221,655 | | | $ | (7,991,598 | ) | | $ | 9,230,057 | | | | $ | 16,557,322 | | | $ | 8,952,953 | | | $ | 25,510,275 | | | $ | (16,240,802 | ) | | $ | 9,269,473 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2010 | |
| | | | | | | | | | | | | | Pro
| |
| | | | | (a)
| | | Pro
| | | Additional
| | | Forma as
| |
| | Historical | | | Adjustments | | | Forma | | | Adjustments | | | Adjusted | |
|
Revenues | | | | | | | | | | | | | | | | | | | | |
Oil and gas sales | | $ | 38,603,599 | | | $ | 24,114,838 | | | $ | 62,718,437 | | | $ | (50,174,750 | )(i) | | $ | 12,543,687 | |
Gain on sale of assets | | | — | | | | — | | | | — | | | | 9,423,003 | (j) | | | 9,423,003 | |
Other | | | 31,749 | | | | — | | | | 31,749 | | | | — | | | | 31,749 | |
| | | | | | | | | | | | | | | | | | | | |
| | | 38,635,348 | | | | 24,114,838 | | | | 62,750,186 | | | | (40,751,747 | ) | | | 21,998,439 | |
Costs and expenses | | | | | | | | | | | | | | | | | | | | |
Lease operating | | | 7,325,042 | | | | 6,401,986 | | | | 13,727,028 | | | | (10,981,622 | )(k) | | | 2,745,406 | |
Production and property taxes | | | 2,720,313 | | | | 1,416,534 | | | | 4,136,847 | | | | (3,309,478 | )(l) | | | 827,369 | |
Depreciation, depletion, amortization and accretion | | | 6,252,676 | | | | 6,583,585 | | | | 12,836,261 | | | | (9,856,928 | )(m) | | | 2,979,333 | |
Interest expense | | | 1,221,373 | | | | — | | | | 1,221,373 | | | | — | | | | 1,221,373 | |
General and administrative | | | 204,575 | | | | — | | | | 204,575 | | | | — | | | | 204,575 | |
| | | | | | | | | | | | | | | | | | | | |
Total costs and expenses | | | 17,723,979 | | | | 14,402,105 | | | | 32,126,084 | | | | (24,148,028 | ) | | | 7,978,056 | |
| | | | | | | | | | | | | | | | | | | | |
Net earnings | | $ | 20,911,369 | | | $ | 9,712,733 | | | $ | 30,624,102 | | | $ | (16,603,719 | ) | | $ | 14,020,383 | |
| | | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these unaudited pro forma financial statements.
VOC F-29F-26
Predecessor
NOTE A — BASIS OF PRESENTATION
VOC Sponsor will convey the Net Profits Interest in oil and natural gas producing properties located in the States of Kansas and Texas to the VOC Energy Trust (the “Trust”). The Net Profits Interest entitles the Trust to receive 80% of the net proceeds attributable to VOC Sponsors’ interest from the sale of production from the underlying properties. The Net Profits Interest will terminate and the underlying properties will revert back to VOC Sponsor on the later to occur of (1) December 31, 2030, or (2) the time from and after January 1, 2011 when 9.710.6 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 $169.5$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 $$17.1 million (comprised of underwriter, legal, accounting and other fees). As of September 30,December 31, 2010, VOC Sponsor had incurred $350 thousand$1.0 million of these direct transaction costs.
VOC Sponsor will sell 10,785,000 of the trust units to the public for cash of $$215.7 million and recognize a deferred gain of $80.4$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 $9.3$11.5 million in cash and notes receivable for $83.6$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 20112013 such that VOC Sponsor would be entitled to receive payments from the counterparties in the event that reference prices for oil contracts traded on NYMEX for the periods covered are less than the fixed prices specified for the hedge and other derivatives. VOC Sponsor will also be required to make payments to the counterparties in the event that reference prices for oil contracts traded on NYMEX for the periods covered are more than the fixed prices specified for the hedge arrangements. Although these hedge and other derivative arrangements will not be directly dedicated or pledged to the Trust, VOC Sponsor expects that payments received or made by it under these hedge arrangements will affect its financial obligations to make payments to the Trust. The effects of these hedge and other derivative arrangements, if any, are reflected in these unaudited pro forma financial statements.
NOTE B — PRO FORMA ADJUSTMENTS
Pro forma adjustments are necessary to reflect the issuance of the trust units, the conveyance of the Net Profits Interest, the sale of trust units and the payment of VOC Sponsors’ long-term
VOC F-30F-27
obligations and distributions using proceeds from the offering. The pro forma adjustments included in the unaudited pro forma balance sheet are as follows:
| |
(a) | Pro forma adjustments necessary to record the acquisition of the Acquired Properties oil and gas related assets at estimated fair value (at December 31, 2009)2010), liabilities, owners’ equity and oil and gas revenues and related expenses. |
Additional pro forma adjustments are necessary to reflect the issuance of the trust units, the conveyance of the Net Profits Interest, the sale of trust units and the payment of VOC 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:
| | | | | | | | | | | | |
| | | | September 30, 2010 | | | | | December 31, 2010 | |
|
(b) | | Gross cash proceeds from the sale of the trust units | | $ | 174,000,000 | | | Gross cash proceeds from the sale of the trust units | | $ | 215,681,600 | |
| | | Cash down payment from VOC Sponsor on related party note | | | 11,511,840 | |
| | Cash down payment on related party note | | | 9,287,116 | | | Repayment of outstanding borrowing on credit facility | | | (24,000,000 | ) |
| | Payment of estimated remaining transaction fees and costs from the sale of trust units | | | (13,829,684 | ) | | Payment of underwriting discount, structuring fee and other offering expenses | | | 16,888,440 | (1) |
| | Distribution to members | | | (169,457,432 | ) | | Distribution to partners | | | (186,305,000 | ) |
| | | | | | |
| | | | $ | — | | | | | $ | — | |
| | | | | | |
(c) | | Receivable from related party for sale of 34.8% of trust units at historical value | | $ | 42,384,338 | | | Receivable from VOC Sponsor for sale of 34.8% of trust units at historical value | | $ | 50,298,756 | |
| | Cash down payment on receivable | | | 9,287,116 | | | Cash down payment on receivable | | | 11,511,840 | |
| | | | | | |
| | Remaining receivable from related party for sale of 34.8% of trust units | | $ | 33,097,222 | | | Remaining receivable from VOC Sponsor for sale of 34.8% of trust units | | $ | 38,786,916 | |
| | | | | | |
(d) | | Current payable for conveyance of oil swap agreements to the Trust | | $ | 729,353 | | | Current payable for conveyance of oil swap agreements to the Trust | | $ | 146,254 | |
| | Long-term payable for conveyance of oil swap agreements to the Trust | | | 266,960 | | | Long-term payable for conveyance of oil swap agreements to the Trust | | | — | |
| | | | | | |
| | | | $ | 996,313 | | | | | $ | 146,254 | |
| | | | | | |
| | Reduction of oil and gas properties due to conveyance of Net Profits Interest | | $ | (144,145,310 | ) | | Reduction of oil and gas properties due to conveyance of Net Profits Interest | | $ | (168,631,957 | ) |
| | Reduction of associated accumulated depreciation, depletion, and amortization | | | 21,065,438 | | | Reduction of associated accumulated depreciation, depletion, and amortization | | | 22,539,386 | |
| | | | | | |
| | | | $ | (123,079,872 | ) | | | | $ | (146,092,571 | ) |
| | | | | | |
| | Current receivable from Trust for conveyance of asset retirement obligation | | $ | 339,234 | | | Current receivable from Trust for conveyance of asset retirement obligations | | $ | 349,674 | |
| | Long-term receivable from Trust for conveyance of asset retirement obligation | | | 1,942,872 | | | Long-term receivable from Trust for conveyance of asset retirement obligations | | | 1,352,490 | |
| | | | | | |
| | | | $ | 2,282,106 | | | | | $ | 1,702,164 | |
| | | | | | |
| | Net oil and gas properties and equipment | | $ | 153,849,839 | | | Net oil and gas properties and equipment | | $ | 182,615,713 | |
| | Asset retirement obligation liability | | | (2,852,632 | ) | | Asset retirement obligation liability | | | (2,127,700 | ) |
| | Oil swap agreements | | | 1,245,391 | | | Oil swap agreements | | | 182,817 | |
| | | | | | |
| | | | | 152,242,598 | | | | | | 180,670,830 | |
| | | | | | |
| | 80% Net Profits Interest | | $ | 121,794,078 | | | 80% Net Profits Interest | | $ | 144,536,664 | |
| | | | | | |
(e) | | Deferred gain on sale of Net Profits Interest is calculated as follows: | | | | | | Deferred gain on sale of Net Profits Interest is calculated as follows: | | | | |
| | Gross cash proceeds from the sale of the trust units | | $ | 174,000,000 | | | Gross cash proceeds from the sale of the trust units | | $ | 215,681,600 | |
| | Less: Net book value of conveyed Net Profits Interests | | | (79,409,741 | ) | | Less: Net book value of conveyed Net Profits Interests | | | (94,237,905 | ) |
| | Deferred transaction fees and costs incurred as of September 30, 2010 | | | (350,316 | ) | | Payment of underwriting discounts, structuring fees and other offering expenses | | | (16,888,440 | ) (1) |
| | Payment of Underwriting discounts, structuring fees and other offering expenses | | | (13,829,684 | ) | | Deferred transaction fees and costs incurred as of December 31, 2010 | | | (209,272 | ) |
| | | | | | |
| | Deferred gain on sale | | $ | 80,410,259 | | | Deferred gain on sale | | $ | 104,345,983 | |
| | | | | | |
| | Current portion of deferred gain | | $ | 7,235,963 | | | Current portion of deferred gain | | $ | 8,759,435 | |
| | Long-term portion of deferred gain | | $ | 73,174,296 | | | Long-term portion of deferred gain | | $ | 95,586,548 | |
| | |
(f) | | To record distribution of remaining cash to general partner | | $ | (1,349,220 | ) | | To record distribution of remaining cash to general partner | | $ | (1,483,360 | ) |
| | | | | | |
(g) | | To record distribution of remaining cash to limited partner | | $ | (66,121,443 | ) | | To record distribution of remaining cash to limited partner | | $ | (72,695,279 | ) |
| | | | | | |
(h) | | To record distribution of remaining cash to common control owners | | $ | (101,986,769 | ) | | To record distribution of remaining cash to common control owners | | $ | (112,126,361 | ) |
| | | | | | |
| | |
(1) | | Includes offering expenses of $829,959 incurred by VOC Kansas Energy Partners, LLC. |
VOC F-31F-28
The pro forma adjustments included in the unaudited pro forma statementsstatement of earnings are as follows:
| | | | | | | | | | | | | | | | |
| | | | Year Ended
| | Nine Months Ended
| | | | | Year Ended
| |
| | | | December 31, 2009 | | September 30, 2010 | | | | | December 31, 2010 | |
|
(i) | | Decrease in oil and gas sales attributable to Net Profits Interest | | $ | (35,303,040 | ) | | $ | (37,656,677 | ) | | Decrease in oil and gas sales attributable to Net Profits Interest | | $ | (50,174,750 | ) |
| | | | | | | | |
(j) | | To record amortization of gain on sale of trust units over the life of the trust | | $ | 7,005,413 | | | $ | 5,216,956 | | | To record amortization of gain on sale of trust units over the life of the trust | | $ | 9,423,003 | |
| | | | | | | | |
(k) | | Decrease in lease operating expenses attributable to the Net Profits Interest | | $ | (10,205,654 | ) | | $ | (7,935,024 | ) | | Decrease in lease operating expenses attributable to the Net Profits Interest | | $ | (10,981,622 | ) |
| | | | | | | | |
(l) | | Decrease in production and property taxes attributable to the Net Profits Interest | | $ | (2,252,681 | ) | | $ | (2,295,274 | ) | | Decrease in production and property taxes attributable to the Net Profits Interest | | $ | (3,309,478 | ) |
| | | | | | | | |
(m) | | Reduce depreciation on assets sold to Trust | | $ | (7,847,694 | ) | | $ | (5,968,621 | ) | | Reduce depreciation on assets sold to Trust | | $ | (9,856,928 | ) |
| | | | | | | | |
VOC F-32F-29
March 22,December 28, 2010
Mr. Bill Horigan
Vess Oil Corporation
VOC Brazos Energy Partners, L.P.
1700 Waterfront Pkwy, Bldg 500
Wichita, KS 67206
| | | | |
| | Re: | | Evaluation Summary VOC Brazos Energy Partners, L.P. Interests Total Proved Reserves As of January 1,December 31, 2010
|
| | | | |
| | | | Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue |
Dear Mr. Horigan:
As requested, this report was prepared on March 22,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, 2009,2010, 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:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Proved
| | Proved
| | | | | | | | | Proved
| | Proved
| | | | | |
| | | | Developed
| | Developed
| | Proved
| | Total
| | | | | Developed
| | Developed
| | Proved
| | Total
| |
| | | | Producing | | Non-Producing | | Undeveloped | | Proved | | | | | Producing | | Non-Producing | | Undeveloped | | Proved | |
|
Net Reserves | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Oil | | — Mbbl | | | 3,836.3 | | | | 378.1 | | | | 1,363.0 | | | | 5,577.4 | | | — Mbbl | | | 3,879.6 | | | | 258.8 | | | | 1,338.0 | | | | 5,479.4 | |
Gas | | — MMcf | | | 1,902.0 | | | | 180.4 | | | | 649.1 | | | | 2,731.5 | | | — MMcf | | | 2,161.0 | | | | 132.3 | | | | 1,105.6 | | | | 3,398.8 | |
Revenue | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Oil | | — M$ | | | 219,756.3 | | | | 21,937.3 | | | | 80,222.0 | | | | 321,915.5 | | | — M$ | | | 291,669.2 | | | | 19,410.2 | | | | 102,474.8 | | | | 413,554.3 | |
Gas | | — M$ | | | 12,897.5 | | | | 1,135.6 | | | | 3,164.4 | | | | 17,197.5 | | | — M$ | | | 15,898.8 | | | | 983.5 | | | | 8,220.8 | | | | 25,103.1 | |
Severance Taxes | | — M$ | | | 10,447.4 | | | | 1,094.3 | | | | 3,927.5 | | | | 15,469.2 | | | — M$ | | | 13,754.6 | | | | 966.6 | | | | 5,330.4 | | | | 20,051.6 | |
Ad Valorem Taxes | | — M$ | | | 6,378.4 | | | | 658.0 | | | | 2,480.1 | | | | 9,516.5 | | |
AdValorem Taxes | | | — M$ | | | 8,485.8 | | | | 551.2 | | | | 3,466.5 | | | | 12,503.5 | |
Operating Expenses | | — M$ | | | 81,383.0 | | | | 3,847.0 | | | | 8,268.8 | | | | 93,498.6 | | | — M$ | | | 84,055.8 | | | | 4,156.3 | | | | 6,465.3 | | | | 94,677.3 | |
Workover Expenses | | — M$ | | | 3,725.5 | | | | 0.0 | | | | 0.0 | | | | 3,725.5 | | | — M$ | | | 3,933.7 | | | | 0.0 | | | | 0.0 | | | | 3,933.7 | |
3rd Party COPAS | | — M$ | | | 0.0 | | | | 0.0 | | | | 0.0 | | | | 0.0 | | |
Other Deductions | | — M$ | | | 2,481.7 | | | | 100.7 | | | | 203.5 | | | | 2,786.0 | | | — M$ | | | 4,518.2 | | | | 256.0 | | | | 309.9 | | | | 5,084.2 | |
Investments | | — M$ | | | 0.0 | | | | 3,344.8 | | | | 21,448.6 | | | | 24,793.3 | | | — M$ | | | 0.0 | | | | 1,467.4 | | | | 22,505.6 | | | | 23,973.0 | |
Net Operating Income | | — M$ | | | 128,238.0 | | | | 14,028.1 | | | | 47,057.9 | | | | 189,323.9 | | | — M$ | | | 192,819.8 | | | | 12,996.2 | | | | 72,618.0 | | | | 278,434.0 | |
Discounted @ 10% (Present Worth) | | — M$ | | | 56,090.4 | | | | 7,286.6 | | | | 18,253.6 | | | | 81,630.5 | | | — M$ | | | 81,812.5 | | | | 7,293.0 | | | | 31,050.2 | | | | 120,155.6 | |
Annex A-1
VOC Brazos Energy Partners, L.P. Interests
March 22,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 field and 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, 20092010 were $61.18/$79.43/bbl and $3.833/$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 20092010 and the base gas price is based upon Henry Hub spot prices (EIA) during 2009.2010.
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 $57.718$75.406 per barrel for oil and $6.296$7.386 per MCF for gas. All economic factors were held constant in accordance with SEC guidelines.
Annex A-2
VOC Brazos Energy Partners, L.P. Interests
March 22,December 28, 2010
Expenses and TaxesEconomic 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) 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 1211 proved undeveloped locations, with 11 of the locations targeting the Woodbine reservoir in the Kurten Field and one (1) location targeting the Chisum reservoir in the Sand Flat field.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 based onusing either volumetric or analogy to offsetting productionand/methods, or type curve analysis. a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for the Company properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.
Annex A-3
VOC Brazos Energy Partners, L.P. Interests
March 22,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.PL.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 FirmF-693
/s/ W. Todd Brooker
W. Todd Brooker, P. E.
| | |
W. Todd Brooker, P. E. Vice President | | |
Annex A-4
APPENDIX
Explanatory Comments for Summary Tables
HEADINGS
Table I
Description of Table Information
Identity of Interest Evaluated
Reserve Classification and Development Status
Property Description — Location
Effective Date of Evaluation
FORECAST
| | | | |
| (Columns) | | | |
| (1)(11)(21) | | | Calendar orFiscalyears/months commencing on effective date. |
| (2)(3)(4) | | | Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts. |
| (5)(6)(7) | | | Net Productionaccruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage. |
| (8) | | | Average (volume weighted)gross liquid price per barrel before deducting production-severance taxes. |
| (9) | | | Average (volume weighted)gross gas price per Mcf before deducting production-severance taxes. |
| (10) | | | Average (volume weighted)gross NGL price per barrel before deducting production-severance taxes. |
| (12) | | | Revenue derived from oil sales — column(5) times column(8). |
| (13) | | | Revenuederived from gas sales — column(6) times column(9). |
| (14) | | | Revenuederived from NGL sales — column(7) times column(10). |
| (15) | | | Revenue derived from hedge positions. |
| (16) | | | Revenue derived from other sourcesnot included in column (12) through column (15); may include revenue from electrical sales, pipeline gas transportation, 3rd party saltwater disposal, etc. |
| (17) | | | Total Revenue — sum of column (12) through column(16). |
| (18) | | | Production-Severance taxes deducted from gross oil, gas and NGL revenue. |
| (19) | | | Ad Valorem taxes. |
�� | (20) | | | $/BOE6 — is the total of column (22), column (25), column (26), and column (27) divided by Barrels of Oil Equivalent (“BOE”). BOE is net oil production column(5) plus net gas production column(6) converted to oil at six Mcf gas per one bbl oil plus net NGL production column(7) converted to oil at one bbl NGL per 0.65 bbls of oil. |
| (22) | | | Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS. |
Appendix
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Annex A-5
| | | | |
| (23) | | | Averagegross wells. |
| (24) | | | Averagenet wells are gross wells times working interest. |
| (25) | | | Workover Expensesare non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair. |
| (26) | | | 3rd Party COPAS may includeexpenses are fixed rate administrative overhead charges for non-operated oil and gas producers.company operated producing properties. |
| (27) | | | Other Deductions includes fixed rate overhead charges for operated oil and gas producers as per the JOA. |
| (28) | | | Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life. |
| (29)(30) | | | Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered. |
| (31) | | | Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates. |
|
MISCELLANEOUS |
| | | | |
| DCF Profile | | | • The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns(30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile. |
| Life | | | • The economic life of the appraised property is noted in the lower right-hand corner of the table. |
| Footnotes | | | • Comments regarding the evaluation may be shown in the lower left-hand footnotes. |
| Price Deck | | | • A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes. |
| Differentials | | | • Total annual price adjustments may be shown in gray font to the left of column(8), column(9) and column(10). |
Appendix
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Annex A-6
APPENDIX
Methods Employed in the Estimation of Reserves
The four methods customarily employed in the estimation of reserves are ( 1 )(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
Appendix
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Annex A-7
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
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Annex A-7
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
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Annex A-8
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 thefrrst-day-of-the-monthfirst-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Appendix
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Annex A-9
“(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
“(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
“(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
“(18)Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
“(iv) See also guidelines in paragraphs ( 17)(iv) and ( 17)(vi) of this section (below).
Appendix
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Annex A-10
“(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”
Instruction 4 of Item 2(b) of Securities and Exchange 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
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Annex A-11
production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
“Note to paragraph (26):Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”
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Annex A-12
October 20,December 28, 2010
Mr. Bill Horigan
|
Mr. Bill Horigan
Vess Oil Corporation
1700 Waterfront Pkwy, Bldg 500
VOC Kansas Energy Partners, LLC 1700 Waterfront Pkwy, Bldg 500 Wichita, Kansas 67206 |
| | | | | | |
| | | Re: | | | Evaluation Summary VOC Kansas Energy Partners, LLC Total Proved Reserves As of December 31, 2010 |
| | | | | | VOC Kansas Energy Partners, LLC
Total Proved Reserves
As of December 31, 2009 |
| | | | | | |
| | | | | | Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue |
Dear Mr. Horigan:
As requested, this report was prepared on October 20,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, 2009,2010, 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:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Proved
| | Proved
| | | | | Proved
| | Proved
| | | | | |
| | Developed
| | Developed
| | Total
| | | Developed
| | Developed
| | Proved
| | Total
| |
| | Producing | | Non-Producing | | Proved | | | Producing | | Non-Producing | | Undeveloped | | Proved | |
|
Net Reserves | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Oil | | | 6,209.9 | | | | 143.0 | | | | 6,352.9 | | | | 6,696.6 | | | | 136.3 | | | | 232.3 | | | | 7,065.3 | |
Gas | | | 3,731.0 | | | | 0.0 | | | | 3,731.0 | | | | 3,550.5 | | | | 0.0 | | | | 0.0 | | | | 3,550.5 | |
Revenue | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Oil | | | 334,898.6 | | | | 7,713.1 | | | | 342,611.8 | | | | 488,614.9 | | | | 9,862.5 | | | | 16,803.3 | | | | 515,280.6 | |
Gas | | | 10,666.6 | | | | 0.0 | | | | 10,666.6 | | | | 13,285.0 | | | | 0.0 | | | | 0.0 | | | | 13,285.0 | |
Severance Taxes | | | 3,469.9 | | | | 0.0 | | | | 3,469.9 | | | | 4,486.1 | | | | 0.0 | | | | 436.2 | | | | 4,922.3 | |
Ad Valorem Taxes | | | 11,541.8 | | | | 388.5 | | | | 11,930.4 | | | | 16,339.7 | | | | 295.9 | | | | 504.1 | | | | 17,139.7 | |
Operating Expenses | | | 128,561.1 | | | | 1,358.5 | | | | 129,919.6 | | | | 164,009.5 | | | | 133.3 | | | | 3,658.8 | | | | 167,801.7 | |
Workover Expenses | | | 0.0 | | | | 0.0 | | | | 0.0 | | | | 12,159.0 | | | | 347.8 | | | | 0.0 | | | | 12,506.9 | |
COPAS | | | 25,024.1 | | | | 266.5 | | | | 25,290.6 | | | | 31,639.5 | | | | 0.0 | | | | 0.0 | | | | 31,639.5 | |
Investments | | | 0.0 | | | | 523.6 | | | | 523.6 | | | | 0.0 | | | | 716.6 | | | | 2,443.8 | | | | 3,160.4 | |
Net Operating Income | | | 176,968.3 | | | | 5,176.0 | | | | 182,144.3 | | | | 273,266.1 | | | | 8,368.9 | | | | 9,760.3 | | | | 291,395.3 | |
Discounted @ 10% (Present Worth) | | | 94,549.7 | | | | 2,509.7 | | | | 97,059.3 | | | | 138,869.4 | | | | 4,163.6 | | | | 5,094.3 | | | | 148,127.3 | |
Annex A-13B-1
VOC Kansas Energy Partners, LLC
October 20,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 threefour main sections: Summary (“TP”), Proved Developed Producing (“PDP”) and, 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 sorted alphabeticallyon DCF by lease name,property, and the second Table II is sorted on DCFalphabetically by property,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, 20092010 were $61.18/$79.43/bbl and $3.833/$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 20092010 and the base gas price is based upon Henry Hub spot prices (EIA) during 2009.2010.
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 $53.930$72.931 per barrel for oil and $2.859$3.742 per MCF for gas. All economic factors were held constant in accordance with SEC guidelines.
Annex A-14B-2
VOC Kansas Energy Partners, LLC
October 20,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 no13 proved undeveloped locations.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.
ProvedNon-producing reserve estimates, for both developed non-producing reserve estimatesand undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods
Annex B-3
VOC Kansas Energy Partners, LLC
December 28, 2010
provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for the Company properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.
General Discussion
The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to
Annex A-15
VOC Kansas Energy Partners, LLC
October 20, 2010
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
/s/ W. Todd Brooker
W. Todd Brooker, P. E.
| | |
W. Todd Brooker, P. E. Vice President | | |
Annex A-16B-4
APPENDIX
Explanatory Comments for Summary Tables
HEADINGS
Table I
Description of Table Information
Identity of Interest Evaluated
Reserve Classification and Development Status
Property Description — Location
Effective Date of Evaluation
FORECAST
| | | | |
| (Columns) | | | |
| (1)(11)(21) | | | Calendar orFiscalyears/months commencing on effective date. |
| (2)(3)(4) | | | Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts. |
| (5)(6)(7) | | | Net Productionaccruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage. |
| (8) | | | Average (volume weighted)gross liquid price per barrel before deducting production-severance taxes. |
| (9) | | | Average (volume weighted)gross gas price per Mcf before deducting production-severance taxes. |
| (10) | | | Average (volume weighted)gross NGL price per barrel before deducting production-severance taxes. |
| (12) | | | Revenue derived from oil sales — column (5) times column (8). |
| (13) | | | Revenuederived from gas sales — column (6) times column (9). |
| (14) | | | Revenuederived from NGL sales — column (7) times column (10). |
| (15) | | | Revenue derived from hedge positions. |
| (16) | | | Revenue derived from other sourcesnot included in column (12) through column (15); may include revenue from electrical sales, pipeline gas transportation, 3rd party saltwater disposal, etc. |
| (17) | | | Total Revenue — sum of column (12) through column (16). |
| (18) | | | Production-Severance taxes deducted from gross oil, gas and NGL revenue. |
| (19) | | | Ad Valorem taxes. |
| (20) | | | $/BOE6 — is the total of column (22), column (25), column (26), and column (27) divided by Barrels of Oil Equivalent (“BOE”). BOE is net oil production column (5) plus net gas production column (6) converted to oil at six Mcf gas per one bbl oil plus net NGL production column (7) converted to oil at one bbl NGL per 0.65 bbls of oil. |
Appendix
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| | Cawley, Gillespie & Associates, Inc. | Page 1 |
Annex A-17
| (22) | |
(22) | | Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS. |
Appendix
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| | Cawley, Gillespie & Associates, Inc. | Page 1 |
Annex B-5
| | | | |
| (23) | | | Averagegross wells. |
| (24) | | | Averagenet wells are gross wells times working interest. |
| (25) | | | Workover Expensesare non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair. |
| (26) | | | 3rd Party COPAS may includeexpenses are fixed rate administrative overhead charges for non-operated oil and gas producers.company operated producing properties. |
| (27) | | | Other Deductions includes fixed rate overhead charges for operated oil and gas producers as per the JOA. |
| (28) | | | Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life. |
| (29)(30) | | | Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered. |
| (31) | | | Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates. |
|
MISCELLANEOUS | | | | | | DCF Profile | | | • The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns(30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile. | | Life | | | • The economic life of the appraised property is noted in the lower right-hand corner of the table. | | Footnotes | | | • Comments regarding the evaluation may be shown in the lower left-hand footnotes. | | Price Deck | | | • A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes. | | Differentials | | | • Total annual price adjustments may be shown in gray font to the left of column (8), column (9) and column (10). |
Appendix | | | | | | Cawley, Gillespie & Associates, Inc. | Page 2 |
Annex A-18B-6
APPENDIX
Methods Employed in the Estimation of Reserves The four methods customarily employed in the estimation of reserves are (1) ( 1 )production performance, (2)material balance, (3)volumetricand (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 Appendix
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Annex A-19
information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most Appendix | | | | | | Cawley, Gillespie & Associates, Inc. | Page 3 |
Annex B-7
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 | | | | | | Cawley, Gillespie & Associates, Inc. | Page 4 |
Annex A-20B-8
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 | | | | | | Cawley, Gillespie & Associates, Inc. | Page 5 |
Annex B-9
“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Appendix
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Annex A-21
“(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)( 17)(iv) and (17)( 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 | | | | | | Cawley, Gillespie & Associates, Inc. | Page 6 |
Annex B-10
“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. “(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. “(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the Appendix
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Annex A-22
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 | | | | | | Cawley, Gillespie & Associates, Inc. | Page 7 |
Annex A-23B-11
March 9, 2011 Mr. Bill Horigan VOC Brazos Energy Partners, L.P. 1700 Waterfront Pkwy, Bldg 500 Wichita, KS 67206 | | | | | | | Re: | | Evaluation Summary VOC Energy Trust Net Profits Interests Total Proved Reserves Certain Oil and Gas Assets — KS & TX As of December 31, 2010 | | | | | | | | | | Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue |
Dear Mr. Horigan: As requested, this report was prepared on 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. | | | | | | | | | | | | | | | | | | | | | | | Proved
| | | Proved
| | | | | | | | | | | | Developed
| | | Developed
| | | Proved
| | | Total
| | | | | | Producing | | | Non-Producing | | | Undeveloped | | | Proved | | | Net Reserves | | | | | | | | | | | | | | | | | | | Oil | | — MBBL | | | 7,924.5 | | | | 371.5 | | | | 1,343.6 | | | | 9,639.6 | | Gas | | — MMCF | | | 4,953.0 | | | | 132.3 | | | | 938.7 | | | | 6,024.0 | | Revenue | | | | | | | | | | | | | | | | | | | Oil | | — M$ | | | 583,748.3 | | | | 27,566.4 | | | | 102,017.1 | | | | 713,331.8 | | Gas | | — M$ | | | 24,917.8 | | | | 983.5 | | | | 6,979.8 | | | | 32,881.1 | | Severance Taxes | | — M$ | | | 13,472.1 | | | | 966.6 | | | | 4,904.0 | | | | 19,342.7 | | Ad Valorem Taxes | | — M$ | | | 19,118.9 | | | | 795.8 | | | | 3,393.6 | | | | 23,308.3 | | Operating Expenses | | — M$ | | | 157,288.9 | | | | 4,209.4 | | | | 5,923.2 | | | | 167,421.5 | | Workover Expenses | | — M$ | | | 10,210.8 | | | | 347.8 | | | | 0.0 | | | | 10,558.6 | | COPAS | | — M$ | | | 23,909.1 | | | | 256.0 | | | | 162.3 | | | | 24,327.4 | | Investments | | — M$ | | | 0.0 | | | | 2,184.0 | | | | 24,949.4 | | | | 27,133.4 | | 80% NPI Net Operating Income (BFIT) | | — M$ | | | 307,733.0 | | | | 15,832.1 | | | | 55,731.6 | | | | 379,296.6 | | 80% NPI Disc. @ 10% | | — M$ | | | 171,454.1 | | | | 9,079.3 | | | | 28,019.1 | | | | 208,552.5 | |
Annex C-1
VOC Energy Trust Net Profits Interests December 28, 2010 Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties. The oil reserves include oil and condensate. Oil volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base. Our estimates are for proved reserves only and do not include any probable or possible reserves nor have any values been attributed to interest in acreage beyond the location for which undeveloped reserves have been estimated. Net Profits Calculations The net profits interests entitle the Trust to receive 80% of the net proceeds attributable to the Companies’ interests from the sale of production from the underlying properties. The net profits interests will terminate on the later to occur (1) December 31, 2030, or (2) the time when 10.6 MMBOE (which is equivalent of 8.5 MMBOE in respect of the net profits interest) have been produced from the underlying properties and sold. Hydrocarbon Pricing The base SEC oil and gas prices calculated for December 31, 2010 were $79.43/bbl and $4.37/MMBTU, respectively. As specified by the SEC, a company must use 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. Annex C-2
VOC Energy Trust Net Profits Interests December 28, 2010 For Kansas properties, severance taxes were applied at 4.33 percent of revenue until exemption levels were forecasted to be reached. The severance tax rate was dropped to zero when a rate of 6 barrels/day per oil well was reached, or when gross gas production value reached $87/day per gas well. Severance taxes were forecasted at 4.6 percent of oil revenue and 7.5 percent of gas revenue for properties in Texas. Ad valorem taxes for Kansas properties were applied at 6 percent of revenue, but dropped to 3 percent as properties qualified for the tax exemption. Kansas oil and gas conservation taxes were included within the ad valorem tax estimates. Ad valorem taxes were applied at 2% of revenue for Texas properties. SEC Conformance and Regulations The reserve classifications and the economic considerations used herein for the SEC pricing scenario conform to the criteria of the SEC as defined in pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves. This evaluation includes 24 proved undeveloped locations based in various fields throughout Kansas and Texas. Each of these drilling locations proposed as part of the Companies’ development plan conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, the Companies have indicated they have every intent to complete this development plan within the next five years. Furthermore, the Companies have demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five year development plan will be fully executed. Reserve Estimation Methods The methods employed in estimating reserves are described in page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for the Companies’ properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report. General Discussion The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to 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 Annex C-3
VOC Energy Trust Net Profits Interests December 28, 2010 represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts. 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) | | | W. Todd Brooker, P.E. Vice President | | |
Annex C-4
APPENDIX Explanatory Comments for Summary Tables HEADINGS Table I Description of Table Information Identity of Interest Evaluated Reserve Classification and Development Status Property Description — Location Effective Date of Evaluation FORECAST | | | | | | (Columns) | | | | | (1)(11)(21) | | | Calendar orFiscalyears/months commencing on effective date. | | (2)(3)(4) | | | Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts. | | (5)(6)(7) | | | Net Productionaccruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage. | | (8) | | | Average (volume weighted)gross liquid price per barrel before deducting production-severance taxes. | | (9) | | | Average (volume weighted)gross gas price per Mcf before deducting production-severance taxes. | | (10) | | | Average (volume weighted)gross NGL price per barrel before deducting production-severance taxes. | | (12) | | | Revenue derived from oil sales — column (5) times column (8). | | (13) | | | Revenuederived from gas sales — column (6) times column (9). | | (14) | | | Revenuederived from NGL sales — column (7) times column (10). | | (15) | | | Revenue derived from hedge positions. | | (16) | | | Revenue derived from other sourcesnot included in column (12) through column (15); may include revenue from electrical sales, pipeline gas transportation, 3rd party saltwater disposal, etc. | | (17) | | | Total Revenue — sum of column (12) through column (16). | | (18) | | | Production-Severance taxes deducted from gross oil, gas and NGL revenue. | | (19) | | | Ad Valorem taxes. | | (20) | | | $/BOE6 — is the total of column (22), column (25), column (26), and column (27) divided by Barrels of Oil Equivalent (“BOE”). BOE is net oil production column (5) plus net gas production column (6) converted to oil at six Mcf gas per one bbl oil plus net NGL production column (7) converted to oil at one bbl NGL per 0.65 bbls of oil. | | (22) | | | Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS. |
Appendix | | | | | | Cawley, Gillespie & Associates, Inc. | Page 1 |
Annex C-5
| | | | | | (23) | | | Averagegross wells. | | (24) | | | Averagenet wells are gross wells times working interest. | | (25) | | | Workover Expensesare non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair. | | (26) | | | COPAS expenses are fixed rate administrative overhead charges for company operated producing properties. | | (27) | | | Other Deductions includes fixed rate overhead charges for operated oil and gas producers as per the JOA. | | (28) | | | Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life. | | (29)(30) | | | Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered. | | (31) | | | Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates. | | MISCELLANEOUS | | | | | | | DCF Profile | | | • The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns(30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile. | | Life | | | • The economic life of the appraised property is noted in the lower right-hand corner of the table. | | Footnotes | | | • Comments regarding the evaluation may be shown in the lower left-hand footnotes. | | Price Deck | | | • A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes. | | Differentials | | | • Total annual price adjustments may be shown in gray font to the left of column (8), column (9) and column (10). |
Appendix | | | | | | Cawley, Gillespie & Associates, Inc. | Page 2 |
Annex 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 | | | | | | Cawley, Gillespie & Associates, Inc. | Page 3 |
Annex C-7
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 | | | | | | Cawley, Gillespie & Associates, Inc. | Page 4 |
Annex C-8
Reserve Definitions and Classifications The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves: “(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. “(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. “(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. “(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. “(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. “(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during 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 | | | | | | Cawley, Gillespie & Associates, Inc. | Page 5 |
Annex C-9
“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. “(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. “(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. “(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. “(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. “(18)Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. “(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. “(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. “(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. “(iv) See also guidelines in paragraphs ( 17)(iv) and ( 17)(vi) of this section (below). “(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. “(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Appendix | | | | | | Cawley, Gillespie & Associates, Inc. | Page 6 |
Annex C-10
“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. “(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. “(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. “(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. “(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.” Instruction 4 of Item 2(b) of Securities and Exchange 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 | | | | | | Cawley, Gillespie & Associates, Inc. | Page 7 |
Annex C-11
10,785,000 Trust Units VOC ENERGY TRUST PROSPECTUS RAYMOND JAMES , 2011
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS | | Item 13. | Other Expenses of Issuance and Distribution. |
Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing and the NYSE listing fee, the amounts set forth below are estimates. | | | | | Registration fee | | $ | 23,220 | | FINRA filing fee | | | 20,500 | | NYSE listing fee | | | * | | Printing and engraving expenses | | | * | | Fees and expenses of legal counsel | | | * | | Accounting fees and expenses | | | * | | Transfer agent and registrar fees | | | * | | Trustee fees and expenses | | | * | | Miscellaneous | | | * | | | | | | | Total | | $ | * | | | | | | |
| | | | | Registration fee | | $ | 30,240 | | FINRA filing fee | | | 26,548 | | NYSE listing fee | | | * | | Printing and engraving expenses | | | * | | Fees and expenses of legal counsel | | | * | | Accounting fees and expenses | | | * | | Transfer agent and registrar fees | | | * | | Trustee fees and expenses | | | * | | Miscellaneous | | | * | | | | | | | Total | | $ | * | | | | | | |
| | | * | | To be provided by amendment |
| | Item 14. | Indemnification of Directors and Officers. |
The trust agreement provides that the trustee and its officers, agents and employees shall be indemnified from the assets of the trust against and from any and all liabilities, expenses, claims, damages or loss incurred by it individually or as trustee in the administration of the trust and the trust assets, including, without limitation, any liability, expenses, claims, damages or loss arising out of or in connection with any liability under environmental laws, or in the doing of any act done or performed or omission occurring on account of it being trustee or acting in such capacity, except such liability, expense, claims, damages or loss as to which it is liable under the trust agreement. In this regard, the trustee shall be liable only for its own fraud or gross negligence or for actsfacts 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 II-1
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. | | Item 15. | Recent Sales of Unregistered Securities. |
None. | | Item 16. | Exhibits and Financial Statement Schedules. |
(a) Exhibits. The following documents are filed as exhibits to this registration statement: | | | | | | | Exhibit
| | | | | Number | | | | Description | | | 1 | .1** | | — | | Form of Underwriting Agreement. | | 2 | .1* | | — | | Contribution and Exchange Agreement among VOC Brazos Energy Partners, L.P., VOC Kansas Energy Partners, LLC, VAP-III, LLC, Vess Texas Acquisition Group, LLC, Vess Texas Partners, LLC, and the other parties named therein. | | 3 | .1* | | — | | Certificate of Limited Partnership of VOC Brazos Energy Partners, L.P. | | 3 | .2* | | — | | Amended and Restated Agreement of Limited Partnership of VOC Brazos Energy Partners, L.P. dated as of September 21, 2009. | | 3 | .3** | | — | | Form of First Amendment to Amended and Restated Agreement of Limited Partnership of VOC Brazos Energy Partners, L.P. | | 3 | .4* | | — | | Certificate of Trust of VOC Energy Trust. | | 3 | .5* | | — | | Trust Agreement dated November 3, 2010 among VOC Brazos Energy Partners, L.P., as trustor, and Wilmington Trust Company, and The Bank of New York Mellon Trust Company, N.A., as trustees. | | 3 | .6** | | — | | Form of Amended and Restated Trust Agreement. | | 5 | .1** | | — | | Opinion of Morris James LLP relating to the validity of the trust units. | | 8 | .1** | | — | | Opinion of Vinson & Elkins L.L.P. relating to tax matters. | | 10 | .1* | | — | | Credit Agreement dated as of June 27, 2008 among VOC Brazos Energy Partners, L.P., as borrower, Bank of America, N.A., as lender, and the other parties named therein. | | 10 | .2* | | — | | First Amendment to Credit Agreement dated August 12, 2008 by and among VOC Brazos, LP (now VOC Brazos, LLC), as borrower, Bank of America, N.A. and the other parties named therein. | | 10 | .3** | | — | | Form of Term Net Profits Interest Conveyance. | | 10 | .4** | | — | | Form of Administrative Services Agreement. | | 10 | .5** | | — | | Form of Registration Rights Agreement. | | 21 | .1* | | — | | Subsidiaries of VOC Brazos Energy Partners, L.P. | | 23 | .1*** | | — | | Consent of Grant Thornton LLP. | | 23 | .2** | | — | | Consent of Morris James LLP (contained in Exhibit 5.1). | | 23 | .3** | | — | | Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1). | | 23 | .4*** | | — | | Consent of Cawley, Gillespie & Associates, Inc. | | 99 | .1*** | | — | | Summary Reserve Reports of Cawley, Gillespie & Associates, Inc. (included as Annex A to the prospectus) |
| | | * | | Previously filed with the Registration Statement (File No. 333-171474) on December 30, 2010. |
| | | ** | | To be filed by amendment |
II-2
(b) Financial Statement Schedules. No financial statement schedules are required to be included herewith or they have been omitted because the information required to be set forth therein is not applicable. The undersigned registrants hereby undertake: (a) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrants pursuant to the provisions described in Item 14, or otherwise, the registrants have been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrants of expenses incurred or paid by a director, officer or controlling person of the registrants in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrants will, unless in the opinion of their respective counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by them is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue. (b) To provide to the underwriters at the closing specified in the underwriting agreement, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser. (c) For purpose of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in the form of prospectus filed by the registrants pursuant to Rule 424(b) (1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective. (d) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. (e) To send to each trust unitholder at least on an annual basis a detailed statement of any transactions with the trustees or their respective affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to the trustees or their respective affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed. (f) To provide to the trust unitholders the financial statements required byForm 10-K for the first full fiscal year of operations of the trust. II-3
SIGNATURES Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Wichita, State of Kansas, on February 10,March 22, 2011. VOC Brazos Energy Partners, L.P. | | | | By: | Vess Texas Partners, LLC, its General Partner |
| | | | By: | Vess Holding Corporation, its Sole Managing Member |
Name: J. Michael Vess Title: Designated Representative and Sole Member of Board of Directors II-4
SIGNATURES Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Wichita, State of Kansas, on February 10,March 22, 2011. VOC Energy Trust | | | | By: | VOC Brazos Energy Partners, L.P. | | | By: | Vess Texas Partners, LLC, its General Partner |
| | | | By: | Vess Holding Corporation, its Sole Managing Member |
Name: J. Michael Vess Title: Designated Representative and Sole Member of Board of Directors II-5
INDEX TO EXHIBITS | | | | | | | Exhibit
| | | | | Number | | | | Description | | | 1 | .1** | | — | | Form of Underwriting Agreement. | | 2 | .1* | | — | | Contribution and Exchange Agreement among VOC Brazos Energy Partners, L.P., VOC Kansas Energy Partners, LLC, VAP-III, LLC, Vess Texas Acquisition Group, LLC, Vess Texas Partners, LLC, and the other parties named therein. | | 3 | .1* | | — | | Certificate of Limited Partnership of VOC Brazos Energy Partners, L.P. | | 3 | .2* | | — | | Amended and Restated Agreement of Limited Partnership of VOC Brazos Energy Partners, L.P. dated as of September 21, 2009. | | 3 | .3** | | — | | Form of First Amendment to Amended and Restated Agreement of Limited Partnership of VOC Brazos Energy Partners, L.P. | | 3 | .4* | | — | | Certificate of Trust of VOC Energy Trust. | | 3 | .5* | | — | | Trust Agreement dated November 3, 2010 among VOC Brazos Energy Partners, L.P., as trustor, and Wilmington Trust Company, and The Bank of New York Mellon Trust Company, N.A., as trustees. | | 3 | .6** | | — | | Form of Amended and Restated Trust Agreement. | | 5 | .1** | | — | | Opinion of Morris James LLP relating to the validity of the trust units. | | 8 | .1** | | — | | Opinion of Vinson & Elkins L.L.P. relating to tax matters. | | 10 | .1* | | — | | Credit Agreement dated as of June 27, 2008 among VOC Brazos Energy Partners L.P., as borrower, Bank of America, N.A., as lender, and the other parties named therein. | | 10 | .2* | | — | | First Amendment to Credit Agreement dated August 12, 2008 by and among VOC Brazos, LP (now VOC Brazos, LLC), as borrower, Bank of America, N.A. and the other parties named therein. | | 10 | .3** | | — | | Form of Term Net Profits Interest Conveyance. | | 10 | .4** | | — | | Form of Administrative Services Agreement. | | 10 | .5** | | — | | Form of Registration Rights Agreement. | | 21 | .1* | | — | | Subsidiaries of VOC Brazos Energy Partners, L.P. | | 23 | .1*** | | — | | Consent of Grant Thornton LLP. | | 23 | .2** | | — | | Consent of Morris James LLP (contained in Exhibit 5.1). | | 23 | .3** | | — | | Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1). | | 23 | .4*** | | — | | Consent of Cawley, Gillespie & Associates, Inc. | | 99 | .1*** | | — | | Summary Reserve Reports of Cawley, Gillespie & Associates, Inc. (included as Annex A to the prospectus). |
| | | * | | Previously filed with Registration Statement (File No.333-171474) on December 30, 2010. |
| | | ** | | To be filed by amendment |
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