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UNDER
THE SECURITIES ACT OF 1933
VOC Energy Trust | VOC Brazos Energy Partners, L.P. | |
(Exact Name of co-registrant as specified in its charter) | (Exact Name of co-registrant as specified in its charter) |
Delaware | Texas | |
(State or other jurisdiction of incorporation or organization) | (State or other jurisdiction of incorporation or organization) |
1311 | 1311 | |
(Primary Standard Industrial Classification Code Number) | (Primary Standard Industrial Classification Code Number) |
80-6183103 | 20-0079353 | |
(I.R.S. Employer Identification No.) | (I.R.S. Employer Identification No.) |
919 Congress Avenue | 1700 Waterfront Parkway | |
Suite 500 | Building 500 | |
Austin, Texas 78701 | Wichita, Kansas 67206 | |
(512) 236-6599 | (316) 682-1537 | |
(Address, including zip code, and telephone number, including area code, of co-registrant’s Principal Executive Offices) | (Address, including zip code, and telephone number, including area code, of co-registrant’s Principal Executive Offices) |
The Bank of New York Mellon Trust Company, N.A., Trustee 919 Congress Avenue Suite 500 Austin, Texas 78701 (512) 236-6599 Attention: Michael J. Ulrich (Name, address, including zip code, and telephone number, including area code, of agent for service) | Barry Hill 1700 Waterfront Parkway Building 500 Wichita, Kansas 67206 (316) 682-1537 (Name, address, including zip code, and telephone number, including area code, of agent for service) |
David P. Oelman | Joshua Davidson | |
W. Matthew Strock | Laura Tyson | |
Vinson & Elkins L.L.P. | Baker Botts L.L.P. | |
1001 Fannin Street, Suite 2500 | 910 Louisiana, Suite 3200 | |
Houston, Texas77002-6760 | Houston, Texas 77002 | |
(713) 758-2222 | (713) 229-1234 |
Large accelerated filer o | Accelerated filer o | Non-accelerated filer þ | Smaller reporting company o |
Proposed Maximum | Amount of | |||||
Title of Each Class of | Aggregate Offering | Registration | ||||
Securities to be Registered | Price (1)(2) | Fee | ||||
Units Of Beneficial Interest in VOC Energy Trust | $200,000,000 | $23,220 | ||||
(1) | Includes trust units issuable upon exercise of the underwriters’ over-allotment option. | |
(2) | Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o). |
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The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted. |
Per | ||||||||
Trust | ||||||||
Unit | Total | |||||||
Initial public offering price | $ | $ | ||||||
Underwriting discounts and commissions (1) | $ | $ | ||||||
Proceeds, before expenses, to VOC Sponsor | $ | $ |
(1) | Excludes a structuring fee of 0.50% of gross proceeds of the offering, or $ , payable to Raymond James & Associates, Inc. by VOC Sponsor for the evaluation, analysis and structuring of the trust. |
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of the Underlying Properties in the States of Kansas and Texas
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F-1 | ||||||||
VOC-1 | ||||||||
VOC F-1 | ||||||||
Annex A-1 | ||||||||
EX-2.1 | ||||||||
EX-3.1 | ||||||||
EX-3.2 | ||||||||
EX-3.4 | ||||||||
EX-3.5 | ||||||||
EX-10.1 | ||||||||
EX-10.2 | ||||||||
EX-21.1 | ||||||||
EX-23.1 | ||||||||
EX-23.4 |
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• | the gross proceeds received from sales of oil and natural gas attributable to the Underlying Properties for each calendar quarter;less | |
• | the sum of the following: |
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• | 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 below in “Computation of net proceeds — Net profits interest”), paid by VOC Sponsor (collectively, “production and development costs”); plus | |
• | amounts that may be reserved for future development expenditures (which reserve amounts may not exceed $1.0 million in the aggregate at any given time); plus | |
• | amounts paid to counterparties under hedge contracts; less | |
• | amounts received from counterparties under hedge contracts. |
• | VOC Brazos will acquire all of the membership interests in KEP in exchange for newly issued limited partner interests in VOC Brazos pursuant to a Contribution and Exchange Agreement dated August 30, 2010, resulting in KEP becoming a wholly-owned subsidiary of VOC Brazos. KEP was formed in November 2009 to engage in the production and development of oil and natural gas primarily within the state of Kansas. KEP’s properties consist of oil and gas properties that have been acquired or developed by KEP’s members since 1979. KEP’s members contributed these properties to KEP in December 2010. The closing of the KEP Acquisition is conditioned solely upon the closing of this offering. | |
• | VOC Sponsor will convey to the trust the Net Profits Interest effective as of January 1, 2011 in exchange for trust units in the aggregate, representing all of the outstanding trust units of the trust. | |
• | VOC Sponsor will sell the trust units offered hereby, representing a 65.2% interest in the trust. VOC Sponsor will also make available during the30-day option period up to trust units for the underwriters to purchase at the initial offering |
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price to cover over-allotments. VOC Sponsor intends to use the proceeds of the offering as disclosed under “Use of Proceeds.” |
• | No more than forty-five days after the closing of this offering, VOC Sponsor will sell the remaining trust units which it holds to VOC Partners, LLC, an affiliate of VOC Sponsor, at the initial offering price. | |
• | VOC Sponsor and the trust will enter into an administrative services agreement which will define the services VOC Sponsor will provide to the trust on an ongoing basis as well as its compensation therefor. Please see “The trust.” |
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Nine Month | ||||||||||||||||||||||||||||||||||||||||
Period Ended | ||||||||||||||||||||||||||||||||||||||||
Number | September 30, | |||||||||||||||||||||||||||||||||||||||
of | Proved Reserves (1) | Average | 2010 | |||||||||||||||||||||||||||||||||||||
Gross | Natural | Average | Net | Average | ||||||||||||||||||||||||||||||||||||
Producing | Oil | Gas | Total | % Oil | % PDP | PV-10 | Working | Revenue | Net Production | |||||||||||||||||||||||||||||||
Operating Area | Wells | (MBbls) | (MMcf) | (MBoe) (2) | Reserves | Reserves | Value (3) | Interest | Interest | (Boe per day) | ||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||||||
Kansas | 750 | 5,840 | 3,731 | 6,462 | 90.4 | % | 97.8 | % | $ | 88.5 | 74.7 | % | 62.5 | % | 1,559 | |||||||||||||||||||||||||
Texas | 142 | 6,090 | 2,732 | 6,545 | 93.0 | % | 71.3 | % | $ | 90.2 | 66.8 | % | 55.1 | % | 1,024 | |||||||||||||||||||||||||
Total | 892 | 11,930 | 6,463 | 13,007 | 91.7 | % | 84.5 | % | $ | 178.7 | 70.7 | % | 58.8 | % | 2,583 | |||||||||||||||||||||||||
(1) | In accordance with the rules and regulations promulgated by the SEC, the proved reserves presented above were determined using the twelve month unweighted arithmetic average of thefirst-day-of-the-month price for the period from January 1, 2009 through December 1, 2009, without giving effect to any hedge transactions, and were held constant for the life of the properties. This yielded a price for oil of $61.18 per Bbl and a price for natural gas of $3.83 per MMBtu. | |
(2) | Oil equivalents in the table are the sum of the Bbls of oil and the Boe of the stated Mcfs of natural gas, calculated on the basis that six Mcfs of natural gas is the energy equivalent of one Bbl of oil. | |
(3) | PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted using an annual discount rate of 10%, calculated without deducting future income taxes. Standardized measure of discounted net cash flows is calculated the same asPV-10 except that it deducts future income taxes. Because VOC Sponsor bears no federal income tax expense and taxable income is passed through to the unitholders of the trust, no provision for federal or state income taxes is included in the reserve reports and therefore the standardized measure of discounted future net cash flows attributable to the Underlying Properties is equal to the pre-taxPV-10 value. PV-10 may not be considered a generally accepted accounting principle (“GAAP”) financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. The pre-taxPV-10 value and the standardized measure of discounted future net cash flows do not purport to present the fair value of the oil and natural gas reserves attributable to Underlying Properties. |
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• | Kansas. VOC Sponsor’s historical development and workover program for the Kansas Underlying Properties has included recompleting certain existing wells, drilling infill development wells, conducting3-D seismic surveys, completing workovers and applying new production technologies. VOC Sponsor intends to continue this program with respect to the Kansas Underlying Properties, and expects to incur total development expenditures for these properties during the next five years of approximately $0.5 million, most of which is expected to be incurred during 2010 by the planned drilling of two vertical development wells. | |
• | Texas. VOC Sponsor’s historical development and workover program for the Texas Underlying Properties has included recompleting certain existing wells, drilling infill development wells, completing workovers and applying new production technologies. In 2009, after an extensive review of horizontal development drilling in the area, VOC Sponsor commenced drilling horizontal wells in the Kurten Woodbine Unit in order to accelerate the development of proved undeveloped reserves. VOC Sponsor has successfully completed each of its first four horizontal wells to the Woodbine C sand in this area with average lateral lengths of approximately 3,000 feet. VOC Sponsor intends to continue developing the Woodbine C sand underlying the Kurten Woodbine Unit, utilizing horizontal wells completed with multiple fracture stimulations together with recompletions of existing vertical wellbores into additional pay intervals. VOC Sponsor expects total development expenditures for the Texas Underlying Properties during the next five years to be approximately $24.8 million. Of this total, VOC Sponsor contemplates spending approximately $21.5 million to drill and complete 11 horizontal wells in the Woodbine C sand and one vertical well in the Sand Flat Unit. The remaining approximate $3.3 million is expected to be used for recompletions and workovers of 13 Woodbine vertical wells to additional Woodbine sands and six existing wells in the Sand Flat Unit. |
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• | Long-lived oil-producing properties. Oil-producing properties in VOC Sponsor’s areas of operation have historically had stable production profiles and generally long-lived production, often with total economic lives in excess of 50 years. VOC Sponsor acquired interests in the Texas Underlying Properties through various acquisitions that have occurred since the inception of VOC Brazos in 2003 and in the Kansas Underlying Properties through the contribution to KEP by its members in December 2010 of properties obtained through various acquisitions and drilling activities since 1979. Proved reserves attributable to the Underlying Properties have remained relatively stable, ranging from approximately 13.2 MMBoe as of December 31, 2007, to approximately 13.0 MMBoe as of December 31, 2009. Based on the reserve reports and assuming for purposes of this calculation that no additional development drilling or other development expenditures are made on the Underlying Properties after 2014, production from the Underlying Properties is expected to decline at an average annual rate of approximately 6.7% over the next 20 years. VOC Sponsor may continue to drill beyond 2014, and such drilling may reduce the anticipated decline rate if successful. | |
• | Substantial proved developed producing reserves. Proved developed producing reserves are the lowest risk category of reserves because production has already commenced, and VOC Sponsor does not expect the proved developed producing reserves attributable to the Underlying Properties to require significant future development costs. Proved developed producing reserves attributable to the Underlying Properties represented approximately 84% of thePV-10 value of the Underlying Properties as of December 31, 2009. | |
• | Near term development activities. VOC Sponsor has identified multiple locations on the Underlying Properties on which it intends to drill new infill wells and recomplete existing wells into new horizons over the next several years. See “— Planned development and workover program” for a summary of VOC Sponsor’s development plans. These locations are currently classified as proved undeveloped reserves on the reserve reports. If these wells are successfully completed or recompleted, as the case may be, the additional production from these wells would partially offset the natural decline in production from the Underlying Properties. Any additional incremental revenue received by VOC Sponsor from this additional production could have the effect of increasing future distributions to the trust unitholders. | |
• | Operational control. The right to operate an oil and natural gas lease is important because the operator can control the timing and amount of discretionary expenditures for |
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operational and development activities. As of December 31, 2009, VOC Operators operated, or operated on a contract basis, approximately 98% of the proved reserves attributable to the Underlying Properties based onPV-10 value. |
• | Experienced Royalty Trust Sponsor. Certain members of VOC Sponsor’s management team were involved in the formation and initial public offering of MV Oil Trust (NYSE: MVO) (“MVO”) a publicly-traded trust that is similar to VOC Energy Trust. In connection with the formation of MVO, the sponsor conveyed an 80% term net profits interest in oil and natural gas properties in the Mid-Continent region in Kansas and Colorado to MVO in exchange for trust units, a portion of which were sold by the sponsor in MVO’s initial public offering in January 2007. The terms of the net profits interest being conveyed in connection with the formation of VOC Energy Trust are similar to those of the net profits interest which was conveyed to MVO. To offset the natural decline in production of the proved developed wells, the sponsor planned and executed a development and workover program. The results of this program have partially mitigated the decline, with average net production being approximately 2,859 Boe per day (or approximately 2,287 Boe per day attributable to MVO’s 80% net profit interest) at the time of the initial public offering and 2,650 Boe per day (or approximately 2,120 Boe per day attributable to MVO’s 80% net profit interest) for the nine months ended September 30, 2010. As a result of differences in pricing, well locations, costs, development schedule, development expenditures and regulatory environment, among other things, the historical results of operations and performance of MVO should not be relied on as an indicator of how the trust will perform. | |
• | Strong oil fundamentals. Substantially all of the production from the Underlying Properties consists of crude oil. According to the US Energy Information Administration (“EIA”) projections, world oil prices are expected to rise gradually. These projections assume that global economic growth results in higher global oil demand, growth in supply from countries who are not members of the Organization of the Petroleum Exporting Countries (“OPEC”) slows in 2011, and members of OPEC continue to support world oil prices and while commercial oil inventories in the Organization for Economic Cooperation and Development (“OECD”) countries begin to decline. | |
• | Downside oil price protection. VOC Sponsor has entered into swap contracts for 2011 with a strike price of $94.90 per barrel of oil that hedge approximately 22% of expected oil production during 2011 from the proved developed producing reserves attributable to the Underlying Properties. These hedge contracts should help mitigate the impact of crude oil price volatility on distributions made with respect to the trust units during 2011. After these contracts expire at various times in 2011, unitholders’ exposure to fluctuations in commodity prices, particularly fluctuations in crude oil prices, will increase significantly. Under the terms of the conveyance, VOC Sponsor will be prohibited from entering into hedging arrangements for the benefit of the trust and the trustee is not empowered to enter into hedge contracts with trust proceeds. For more information on VOC Sponsor’s hedge positions, please see “The Underlying Properties — Hedge contracts.” | |
• | Aligned interests of sponsor. Following the closing of this offering, VOC Sponsor, together with VOC Partners, LLC, will be entitled to receive an aggregate of approximately 48% of the net proceeds attributable to the sale of oil and natural gas produced from the Underlying Properties. This 48% interest will consist of (1) the 20% of the net proceeds from the sale of production of oil and natural gas and attributable to the Underlying Properties that is retained by VOC Sponsor after transferring to the trust the Net Profits |
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Interest and (2) the ownership by VOC Partners, LLC of approximately 35% of the trust units following the closing of this offering. |
Proved Reserves of the Underlying Properties | Undiscounted | |||||||||||||||||||
Oil | Natural Gas | Oil Equivalent | Future Net | PV-10 | ||||||||||||||||
(MBbls ) | (MMcf) | (MBoe) | Revenues | Value | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Underlying Properties (total) (1) | 11,930 | 6,463 | 13,007 | $ | 371,468 | $ | 178,690 | |||||||||||||
Underlying Properties (attributable to the Net Profits Interest) (2) | 7,132 | 4,003 | 7,799 | $ | 238,175 |
(1) | Reflects 100% of the proved reserves attributable to the Underlying Properties. | |
(2) | Reflects 80% of proved reserves attributable to the Underlying Properties expected to be produced during the term of the trust. |
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Attributable to the Net Profits Interest
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Year Ended | Nine Months Ended | |||||||
December 31, 2009 | September 30, 2010 | |||||||
(In thousands) | ||||||||
(Unaudited) | ||||||||
Revenues: | ||||||||
Oil sales | $ | 40,360 | $ | 44,682 | ||||
Natural gas sales | 2,292 | 2,540 | ||||||
Hedge and other derivative activity | 1,477 | (151 | ) | |||||
Total | 44,129 | 47,071 | ||||||
Bad debt recovery | (719 | ) | — | |||||
Direct operating expenses: | ||||||||
Lease operating expenses | 12,757 | 9,919 | ||||||
Production and property taxes | 2,816 | 2,869 | ||||||
Total | 15,573 | 12,788 | ||||||
Excess of revenues over direct operating expenses | $ | 29,275 | $ | 34,283 | ||||
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Year Ended | Nine Months Ended | |||||||
December 31, 2009 | September 30, 2010 | |||||||
(In thousands, except per unit data) | ||||||||
(Unaudited) | ||||||||
Excess of revenues over direct operating expenses | $ | 29,275 | $ | 34,283 | ||||
Less development expenses | 5,129 | 8,829 | ||||||
Excess of revenues over direct operating expenses and development expenses | 24,146 | 25,454 | ||||||
Times Net Profits Interest over the term of the trust | 80 | % | 80 | % | ||||
Income from Net Profits Interest | 19,316 | 20,363 | ||||||
Pro forma adjustments: | ||||||||
Less estimated trust general and administrative expenses | 900 | 675 | ||||||
Distributable income | $ | 18,416 | $ | 19,688 | ||||
Distributable income per trust unit | ||||||||
Nine Months Ended | ||||||||||||||||||||
Year Ended December 31, | September 30, | |||||||||||||||||||
Underlying Properties (1) | 2007 | 2008 | 2009 | 2009 | 2010 | |||||||||||||||
(Unaudited) | ||||||||||||||||||||
Operating data: | ||||||||||||||||||||
Sales volumes: | ||||||||||||||||||||
Oil (MBbls) | 705 | 704 | 732 | 543 | 618 | |||||||||||||||
Natural gas (MMcf) | 738 | 750 | 693 | 525 | 519 | |||||||||||||||
Total sales (MBoe) | 828 | 829 | 847 | 631 | 705 | |||||||||||||||
Average sales prices: | ||||||||||||||||||||
Oil (per Bbl) | $ | 67.15 | $ | 93.67 | $ | 55.16 | $ | 50.01 | $ | 72.25 | ||||||||||
Natural gas (per Mcf) | $ | 5.96 | $ | 7.46 | $ | 3.31 | $ | 3.10 | $ | 4.89 | ||||||||||
Capital expenditures (in thousands): | ||||||||||||||||||||
Property acquisition | $ | 4,463 | $ | 7,899 | $ | 4,134 | $ | 1,981 | $ | 2,884 | ||||||||||
Well development | 2,420 | 2,499 | 2,407 | 1,027 | 6,099 | |||||||||||||||
Total | $ | 6,883 | $ | 10,398 | $ | 6,541 | $ | 3,008 | $ | 8,983 | ||||||||||
(1) | The operating data below includes the effect of the Acquired Underlying Properties for all periods presented. |
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Nine Months Ended | ||||||||||||||||||||
Year Ended December 31, | September 30, | |||||||||||||||||||
Predecessor Underlying Properties | 2007 | 2008 | 2009 | 2009 | 2010 | |||||||||||||||
(Unaudited) | ||||||||||||||||||||
Operating data: | ||||||||||||||||||||
Sales volumes: | ||||||||||||||||||||
Oil (MBbls) | 387 | 389 | 407 | 298 | 374 | |||||||||||||||
Natural gas (MMcf) | 391 | 426 | 415 | 311 | 339 | |||||||||||||||
Total (MBoe) | 452 | 460 | 477 | 350 | 431 | |||||||||||||||
Average sales prices: | ||||||||||||||||||||
Oil (per Bbl) | $ | 67.31 | $ | 94.11 | $ | 55.86 | $ | 50.37 | $ | 73.15 | ||||||||||
Natural gas (per Mcf) | $ | 6.39 | $ | 7.86 | $ | 3.64 | $ | 3.36 | $ | 5.47 | ||||||||||
Capital expenditures (in thousands): | ||||||||||||||||||||
Property acquisition | $ | 3,523 | $ | 6,715 | $ | 2,369 | $ | 1,027 | $ | 2,328 | ||||||||||
Well development | 1,603 | 1,063 | 1,955 | 747 | 5,638 | |||||||||||||||
Total | $ | 5,126 | $ | 7,778 | $ | 4,324 | $ | 1,774 | $ | 7,966 | ||||||||||
Nine Months Ended | ||||||||||||||||||||
Year Ended December 31, | September 30, | |||||||||||||||||||
Acquired Underlying Properties | 2007 | 2008 | 2009 | 2009 | 2010 | |||||||||||||||
(Unaudited) | ||||||||||||||||||||
Operating data: | ||||||||||||||||||||
Sales volumes: | ||||||||||||||||||||
Oil (MBbls) | 319 | 315 | 324 | 245 | 244 | |||||||||||||||
Natural gas (MMcf) | 347 | 324 | 278 | 214 | 180 | |||||||||||||||
Total sales (MBoe) | 376 | 369 | 371 | 281 | 274 | |||||||||||||||
Average sales prices: | ||||||||||||||||||||
Oil (per Bbl) | $ | 66.96 | $ | 93.12 | $ | 54.27 | $ | 49.58 | $ | 70.85 | ||||||||||
Natural gas (per Mcf) | $ | 5.49 | $ | 6.94 | $ | 2.81 | $ | 2.72 | $ | 3.80 | ||||||||||
Capital expenditures (in thousands): | ||||||||||||||||||||
Property acquisition | $ | 940 | $ | 1,184 | $ | 1,765 | $ | 954 | $ | 556 | ||||||||||
Well development | 817 | 1,436 | 452 | 280 | 461 | |||||||||||||||
Total | $ | 1,757 | $ | 2,620 | $ | 2,217 | $ | 1,234 | $ | 1,017 | ||||||||||
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Predecessor Pro Forma for the | Predecessor Pro Forma As | |||||||||||||||||||||||
Acquisition of the Acquired | Adjusted for the Offering | |||||||||||||||||||||||
Predecessor | Underlying Properties | (Including the conveyance of the Net Profits Interest) | ||||||||||||||||||||||
Nine Months | Nine Months | Nine Months | ||||||||||||||||||||||
Year Ended | Ended | Year Ended | Ended | Year Ended | Ended | |||||||||||||||||||
December 31, | September 30, | December 31, | September 30, | December 31, | September 30, | |||||||||||||||||||
2009 | 2010 | 2009 | 2010 | 2009 | 2010 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
(Unaudited) | (Unaudited) | (Unaudited) | ||||||||||||||||||||||
Revenue | $ | 25,750 | $ | 29,091 | $ | 44,133 | $ | 47,073 | $ | 15,836 | $ | 14,633 | ||||||||||||
Net earnings | $ | 10,861 | $ | 16,557 | $ | 17,222 | $ | 25,510 | $ | 9,230 | $ | 9,269 | ||||||||||||
Total assets (at period end) | $ | 101,280 | $ | 109,626 | $ | 173,271 | $ | 85,220 | ||||||||||||||||
Long-term liabilities, excluding current maturities (at period end) | $ | 28,315 | $ | 26,765 | $ | 28,822 | $ | 102,264 | ||||||||||||||||
Partners’ capital/common control owners’ equity (deficit) | $ | 67,512 | $ | 79,932 | $ | 139,876 | $ | (29,581 | ) |
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• | the oil and natural gas production estimates for the year ending December 31, 2011 contained in the reserve reports; | |
• | estimated production and development costs for the year ending December 31, 2011, contained in the reserve reports; | |
• | projected payments made or received pursuant to the hedge contracts for the year ending December 31, 2011; and | |
• | further reduction in estimated general and administrative expenses of $900,000 in 2011. |
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Projection for Twelve Months | ||||
Projected Cash Distributions | Ending December 31, 2011 | |||
(Dollars in thousands, except | ||||
per Bbl, Mcf, MMBtu and per unit | ||||
amounts) | ||||
Underlying Properties sales volumes: | ||||
Oil (MBbls) | ||||
Natural gas (MMcf) | ||||
Total sales (MBoe) | ||||
NYMEX futures price (1): | ||||
Oil (per Bbl) | $ | |||
Natural gas (per MMBtu) | $ | |||
Assumed realized sales price (2): | ||||
Oil (per Bbl) | $ | |||
Natural gas (per Mcf) | $ | |||
Calculation of net proceeds: | ||||
Gross proceeds: | ||||
Oil sales | $ | |||
Natural gas sales | ||||
Total | $ | |||
Costs: | ||||
Production and development costs: | ||||
Lease operating expenses | $ | |||
Production and property taxes | ||||
Development expenses | ||||
Total | $ | |||
Settlement of hedge contracts (payment received) (3) | ||||
Net proceeds | $ | |||
Percentage allocable to Net Profits Interest | 80 | % | ||
Net proceeds to trust from Net Profits Interest | $ | |||
Trust general and administrative expenses (4) | ||||
Cash available for distribution by the trust | $ | |||
Cash distribution per trust unit | $ | |||
(1) | Average NYMEX futures price for 2011, as reported on . For a description of the effect of lower NYMEX prices on projected cash distributions, please read “— Sensitivity of projected cash distributions to oil and natural gas production and prices.” | |
(2) | Sales price net of forecasted gravity, quality, transportation, and marketing costs. For more information about the estimates and hypothetical assumptions made in preparing the table above, see “Projected cash distributions — Significant assumptions used to prepare the projected cash distributions.” | |
(3) | Costs will be reduced by hedge payments received by VOC Sponsor under the hedge contracts. If the hedge payments received by VOC Sponsor under the hedge contracts exceed costs during a quarterly period, the ability to use such excess amounts to offset costs will be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period when the hedge payments are less than such costs. | |
(4) | Total general and administrative expenses of the trust on an annualized basis for 2011 are expected to be $900,000, which includes an annual administrative fee to VOC Sponsor in the amount of $75,000 in 2011, which fee will increase by 4% annually beginning in January 2012, the annual fee to the trustees, accounting fees, engineering fees, printing costs and other expenses properly chargeable to the trust. |
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Trust units offered by VOC Sponsor | trust units or, trust units, if the underwriters exercise their option to purchase additional trust units in full | |
Trust units owned by VOC Partners, LLC after the offering | trust units, if the underwriters exercise their option to purchase additional trust units in full | |
Trust units outstanding after the offering | trust units | |
Use of proceeds | VOC Sponsor is offering all of the trust units to be sold in this offering including, the trust units to be sold upon any exercise of the underwriters’ over-allotment option. The estimated net proceeds of this offering to be received by VOC Sponsor will be approximately $ million, after deducting underwriting discounts and commissions, structuring fees and expenses, and $ million if the underwriters exercise their option to purchase additional trust units in full. VOC Sponsor intends to use the net proceeds from this offering, including any proceeds from the exercise of the underwriters’ option to purchase additional trust units and the sale of the trust units to VOC Partners, LLC to make cash distributions to its limited partners. See “Use of proceeds.” | |
Proposed NYSE symbol | “VOC” | |
Quarterly cash distributions | It is expected that quarterly cash distributions during the term of the trust, other than the first quarterly cash distribution, will be made by the trustee on or about the 45th day following the end of each quarter to the trust unitholders of record on the 30th day following the end of each quarter (or the next succeeding business day). The first distribution from the trust to the trust unitholders will be made on or about August 15, 2011 to trust unitholders owning trust units on or about August 1, 2011. The trust’s first quarterly distribution will consist of an amount in cash paid by VOC Sponsor equal to the amount that would have been payable to the trust had the Net Profits Interest been in effect during the period from January 1, 2011 through June 30, 2011, less any general and administrative expenses and reserves of the trust. | |
Actual cash distributions to the trust unitholders will fluctuate quarterly based upon the quantity of oil and natural gas produced from the Underlying Properties, the prices received for oil and natural gas production and other factors. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the |
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production from the Underlying Properties diminishing over time, a portion of each distribution will represent, in effect, a return of your original investment. Oil and natural gas production from proved reserves attributable to the Underlying Properties is expected to decline over the term of the trust. See “Risk factors.” | ||
Termination of the trust | The Net Profits Interest will terminate on the later to occur of (1) December 31, 2030, or (2) the time when 9.7 MMBoe have been produced from the Underlying Properties and sold (which amount is the equivalent of 7.8 MMBoe in respect of the trust’s right to receive 80% of the net proceeds from the Underlying Properties pursuant to the Net Profits Interest), and the trust will promptly wind up its affairs and terminate thereafter. | |
Summary of income tax consequences | Trust unitholders will be taxed directly on the income from assets of the trust. The Net Profits Interest should be treated as a debt instrument for federal income tax purposes, and a trust unitholder in that event will be required to include in such trust unitholder’s income its share of the interest income on such debt instrument as it accrues in accordance with the rules applicable to contingent payment debt instruments contained in the Internal Revenue Code of 1986, as amended, and the corresponding regulations. If the Net Profits Interest is not treated as a debt instrument, then a trust unitholder should be allowed to recoup its basis in the Net Profits Interest on a schedule that is in proportion to production attributable to the Net Profits Interest and that may be more favorable to a trust unitholder than the schedule on which basis will be recovered if the Net Profits Interest is treated as a debt instrument for federal income tax purposes. See “Federal income tax consequences.” |
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• | regional, domestic and foreign supply and perceptions of supply of oil and natural gas; | |
• | the level of demand and perceptions of demand for oil and natural gas; | |
• | political conditions or hostilities in oil and natural gas producing regions; | |
• | anticipated future prices of oil and natural gas and other commodities; | |
• | weather conditions and seasonal trends; | |
• | technological advances affecting energy consumption and energy supply; | |
• | U.S. and worldwide economic conditions; | |
• | the price and availability of alternative fuels; | |
• | the proximity, capacity, cost and availability of gathering and transportation facilities; | |
• | the volatility and uncertainty of regional pricing differentials; | |
• | governmental regulations and taxation; | |
• | energy conservation and environmental measures; and | |
• | acts of force majeure. |
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• | historical production from the area compared with production rates from other producing areas; | |
• | oil and natural gas prices, production levels, Btu content, production expenses, transportation costs, severance and excise taxes and development expenditures; and | |
• | the effect of expected governmental regulation. |
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• | delays imposed by or resulting from compliance with regulatory requirements, including permitting; | |
• | unusual or unexpected geological formations; | |
• | shortages of or delays in obtaining equipment and qualified personnel; | |
• | equipment malfunctions, failures or accidents; | |
• | unexpected operational events and drilling conditions; | |
• | reductions in oil or natural gas prices; | |
• | market limitations for oil or natural gas; | |
• | pipe or cement failures; | |
• | casing collapses; | |
• | lost or damaged drilling and service tools; | |
• | loss of drilling fluid circulation; | |
• | uncontrollable flows of oil and natural gas; | |
• | fires and natural disasters; | |
• | environmental hazards, such as oil and natural gas leaks, pipeline ruptures and discharges of toxic gases; | |
• | adverse weather conditions; and | |
• | oil or natural gas property title problems. |
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• | VOC Sponsor’s interests may conflict with those of the trust and the trust unitholders in situations involving the development, maintenance, operation or abandonment of the Underlying Properties. VOC Sponsor may also make decisions with respect to development expenditures that adversely affect the Underlying Properties. These decisions include reducing development expenditures on these properties, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the trust in the future. | |
• | VOC Sponsor may sell some or all of the Underlying Properties without taking into consideration the interests of the trust unitholders. Such sales may not be in the best interests of the trust unitholders. These purchasers may lack VOC Sponsor’s experience or its credit worthiness. VOC Sponsor also has the right, under certain circumstances, to cause the trust to release all or a portion of the Net Profits Interest in connection with a sale of a portion of the Underlying Properties to which such Net Profits Interest relates. In such an event, the trust is entitled to receive the fair value (net of sales costs) of the Net Profits Interest released. See “The Underlying Properties — Sale and abandonment of Underlying Properties.” |
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• | MV Purchasing LLC, an affiliate of VOC Sponsor, is expected to marketand/or purchase a substantial portion of the oil produced from the Underlying Properties, and it is expected to profit from this arrangement. Provisions in the Net Profits Interest conveyance, however, require that charges and other terms under contracts with affiliates of VOC Sponsor be comparable to prices and other terms prevailing in the area for similar services or sales. During the nine months ended September 30, 2010, VOC Sponsor has sold approximately 32% of the oil produced from the Underlying Properties to MV Purchasing, LLC, an affiliate of VOC Sponsor. | |
• | VOC Partners, LLC has registration rights and can sell its units without considering the effects such sale may have on trust unit prices or on the trust itself. Additionally, VOC Partners, LLC can vote its trust units in its sole discretion without considering the interests of the other trust unitholders. |
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• | risks incident to the drilling and operation of oil and natural gas wells; | |
• | future production and development costs and plans; | |
• | the effect of existing and future laws and regulatory actions; | |
• | the effect of changes in commodity prices; | |
• | the impact of the hedge contracts; | |
• | conditions in the capital markets; | |
• | competition from others in the energy industry; | |
• | uncertainty of estimates of oil and natural gas reserves and production; and | |
• | inflation. |
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OPERATING AND RESERVE DATA OF VOC SPONSOR
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Predecessor | Predecessor Pro Forma | |||||||||||||||||||||||||||||||||||
Pro Forma for the | As Adjusted for the Offering | |||||||||||||||||||||||||||||||||||
Acquisition of the Acquired | (including the conveyance of | |||||||||||||||||||||||||||||||||||
Underlying Properties | the Net Profits Interest) | |||||||||||||||||||||||||||||||||||
Predecessor | Nine Months | Nine Months | ||||||||||||||||||||||||||||||||||
Nine Months Ended | Year Ended | Ended | Year Ended | Ended | ||||||||||||||||||||||||||||||||
Year Ended December 31, | 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 | $ | 21,290 | $ | 32,198 | $ | 25,750 | $ | 17,949 | $ | 29,091 | $ | 44,133 | $ | 47,073 | $ | 15,836 | $ | 14,633 | ||||||||||||||||||
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 |
Nine Months | ||||||||||||||||||||
Ended | ||||||||||||||||||||
September | ||||||||||||||||||||
Year Ended December 31, | 30, | |||||||||||||||||||
Historical Results | 2007 | 2008 | 2009 | 2009 | 2010 | |||||||||||||||
Production (MBoe) | 828 | 829 | 847 | 631 | 705 | |||||||||||||||
Net proved reserves (MBoe) (at period end) | 13,223 | 10,821 | 13,007 | |||||||||||||||||
Net proved developed reserves (MBoe) (at period end) | 12,603 | 10,046 | 11,536 |
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Name | Age | Title | ||||
J. Michael Vess | 59 | President and Chief Executive Officer | ||||
William R. Horigan | 61 | Vice President of Operations | ||||
Brian Gaudreau | 55 | Vice President of Land | ||||
Barry Hill | 34 | Vice President and Chief Financial Officer | ||||
Alan Howarter | 54 | Vice President of Financial Reporting |
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• | each person who will then beneficially own 5% or more of the outstanding partner interests in VOC Sponsor; | |
• | each member of Vess Oil’s executive management team, who perform management functions on behalf of VOC Sponsor; and | |
• | all members of Vess Oil’s executive management team, who perform management functions on behalf of VOC Sponsor, as a group. |
Percentage of | ||||
Partnership Interests | ||||
Name of Beneficial Owner | Beneficially Owned | |||
L. D. Davis (1) | 25.8 | % | ||
J. Michael Vess (2) | 22.0 | % | ||
CPC Brazos Energy, L.P. (3) | 17.2 | % | ||
William Price (4) | 9.1 | % | ||
C. J. Lett (5) | 8.6 | % | ||
William R. Horigan (6) | 6.1 | % | ||
Brian Gaudreau (7) | 2.2 | % | ||
Barry Hill | * | |||
Alan Howarter (8) | * | |||
Executive Management as a Group (2)(6)(7)(8) | 30.5 | % |
* | less than 1% | |
(1) | Includes interests indirectly beneficially owned in VOC Sponsor through several entities, including through interests in Davis Energy LLC, which entity beneficially owns a 13.3% interest in VOC Sponsor. The address of Mr. Davis is 7 SW 26th Ave., Great Bend, Kansas 67530. | |
(2) | Includes 13.7% of Mr. Vess’ interests in VOC Sponsor indirectly beneficially owned through family trusts. Mr. Vess also has dispositive power over an additional 8.3% of VOC Sponsor. The address of Mr. Vess is 1700 Waterfront Parkway, Building 500, Wichita, Kansas 67206. |
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(3) | The address of CPC Brazos Energy, L.P., an entity sponsored by Carson Private Capital, is 500 Victory Plaza East, 3030 Olive Street, Dallas, Texas 75219. | |
(4) | Includes interests indirectly beneficially owned through several entities. The address of Mr. Price is 1700 Waterfront Parkway, Building 500, Wichita, KS 67206. | |
(5) | Includes interests indirectly beneficially owned through several entities. The address of Mr. Lett is 9320 E. Central, Wichita, Kansas 67206. | |
(6) | Includes interests indirectly beneficially owned through several entities. The address of Mr. Horigan is 1700 Waterfront Parkway, Building 500, Wichita, Kansas 67206. | |
(7) | Includes interests indirectly beneficially owned through several entities. The address of Mr. Gaudreau is 1700 Waterfront Parkway, Building 500, Wichita, Kansas 67206. | |
(8) | Mr. Howarter beneficially owns less than 1% of VOC Brazos through his beneficial ownership of 10% of the membership interests in Vess Oil Company, L.L.C., an indirect subsidiary of VOC Sponsor. The address of Mr. Howarter is 1700 Waterfront Parkway, Building 500, Wichita, Kansas 67206 |
Class of | Percentage | |||
Name of Beneficial Owner | Securities | of Ownership | ||
VOC Partners, LLC (1) | Trust Units | 34.8% (2) |
(1) | The parties who beneficially own VOC Sponsor as set forth in the table above own VOC Partners, LLC in the same proportion as they own VOC Sponsor. However, such ownership percentage described in the table above does not take into account Class B Units of VOC Partners, LLC. Such Class B Units are issuable to VOC Management Group at the discretion of VOC Partners, LLC, and these units may equal up to 1.5% of the outstanding units of VOC Partners, LLC. | |
(2) | VOC Partners, LLC has entered into an agreement to acquire from VOC Sponsor all trust units not sold by VOC Sponsor in this offering at the initial offerings price. The closing of such transaction will occur forty-five days following the closing of this offering. |
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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 |
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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 |
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• | oil sales prices and, to a lesser extent, natural gas sales prices; | |
• | the volume of oil and natural gas produced and sold attributable to the Underlying Properties; | |
• | the payments made or received by VOC Sponsor pursuant to the hedge contracts; | |
• | property and production taxes; | |
• | development expenses; | |
• | lease operating expenses; and | |
• | administrative expenses of the trust. |
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• | the oil and natural gas production estimates for the year ending December 31, 2011 contained in the reserve reports; | |
• | estimated production and development costs for the year ending December 31, 2011, contained in the reserve reports; and | |
• | projected payments made or received pursuant to the hedge contracts, if any, for the year ending December 31, 2011 assuming the hypothetical prices used in the following table and the hedge contracts to be entered into by VOC Sponsor as of the closing of this offering related to production for 2011. |
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Quarter Ending | Projection for Twelve | |||||||||||||||||||
March 31, | June 30, | September 30, | December 31, | Months Ending | ||||||||||||||||
2011 | 2011 | 2011 | 2011 | December 31, 2011 | ||||||||||||||||
(Dollars in thousands, except per Bbl, Mcf, MMBtu and per unit amounts) | ||||||||||||||||||||
Underlying Properties sales volumes: | ||||||||||||||||||||
Oil (MBbls) | ||||||||||||||||||||
Natural gas (MMcf) | ||||||||||||||||||||
Total sales (MBoe) | ||||||||||||||||||||
NYMEX future prices (1): | ||||||||||||||||||||
Oil (per Bbl) | $ | $ | $ | $ | $ | |||||||||||||||
Natural Gas (per MMBtu) | $ | $ | $ | $ | $ | |||||||||||||||
Assumed realized sales price (2): | ||||||||||||||||||||
Oil (per Bbl) | $ | $ | $ | $ | $ | |||||||||||||||
Natural gas (per Mcf) | $ | $ | $ | $ | $ | |||||||||||||||
Calculation of net proceeds: | ||||||||||||||||||||
Gross proceeds: | ||||||||||||||||||||
Oil sales | $ | $ | $ | $ | $ | |||||||||||||||
Natural gas sales | ||||||||||||||||||||
Total | $ | $ | $ | $ | $ | |||||||||||||||
Costs: | ||||||||||||||||||||
Production and development costs: | ||||||||||||||||||||
Lease operating expenses | $ | $ | $ | $ | $ | |||||||||||||||
Production and property taxes | ||||||||||||||||||||
Development expenses | ||||||||||||||||||||
Total | $ | $ | $ | $ | $ | |||||||||||||||
Settlement of hedge contracts (payment received) (3) | ||||||||||||||||||||
Net proceeds | $ | $ | $ | $ | $ | |||||||||||||||
Percentage allocable to Net Profits Interest | 80 | % | 80 | % | 80 | % | 80 | % | 80 | % | ||||||||||
Net proceeds to trust from Net Profits Interest | $ | $ | $ | $ | $ | |||||||||||||||
Trust general and administrative expenses (4) | ||||||||||||||||||||
Cash available for distribution by the trust | $ | $ | $ | $ | $ | |||||||||||||||
Cash distribution per trust unit | $ | $ | $ | $ | $ | |||||||||||||||
(1) | Average NYMEX futures price for 2011, as reported on . For a description of the effect of lower NYMEX prices on projected cash distributions, please read “— Sensitivity of projected cash distributions to oil and natural gas production and prices.” |
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(2) | Sales price net of forecasted gravity, quality, transportation, and marketing costs. For more information about the estimates and hypothetical assumptions made in preparing the table above, see “— Significant assumptions used to prepare the projected cash distributions.” | |
(3) | Costs will be reduced by hedge payments received by VOC Sponsor under the hedge contracts. If the hedge payments received by VOC Sponsor under the hedge contracts exceed costs during a quarterly period, the ability to use such excess amounts to offset costs will be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period when the hedge payments are less than such costs. | |
(4) | Total general and administrative expenses of the trust on an annualized basis for 2011 are expected to be $900,000, which includes an annual administrative fee to VOC Sponsor in the amount of $75,000 in 2011, which fee will increase by 4% annually beginning in January 2012, the annual fee to the trustees, accounting fees, engineering fees, printing costs and other expenses properly chargeable to the trust. |
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to Changes in Estimated Oil and Natural Gas Production and NYMEX Futures Pricing
(1) | Estimated oil and natural gas production is based on the reserve reports, and the sensitivity analysis assumes there will be no variation by location and that oil and natural gas production will continue to represent the same percentage of total production as estimated for 2011 in the reserve report. |
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Nine Months Ended | ||||||||||||||||||||
Year Ended December 31, | September 30, | |||||||||||||||||||
2007 | 2008 | 2009 | 2009 | 2010 | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
(Unaudited) | ||||||||||||||||||||
Predecessor Underlying Properties: | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Oil sales | $ | 26,040 | $ | 36,632 | $ | 22,758 | $ | 15,020 | $ | 27,384 | ||||||||||
Natural gas sales | 2,495 | 3,350 | 1,511 | 1,045 | 1,857 | |||||||||||||||
Hedge and other derivative activity | (7,245 | ) | (7,785 | ) | 1,477 | 1,880 | (151 | ) | ||||||||||||
Total | 21,290 | 32,197 | 25,746 | 17,945 | 29,090 | |||||||||||||||
Bad debt expense (recovery) | — | 1,727 | (719 | ) | (719 | ) | — | |||||||||||||
Direct operating expenses: | ||||||||||||||||||||
Lease operating expenses | 6,586 | 7,667 | 6,788 | 5,053 | 5,229 | |||||||||||||||
Production and property taxes | 1,874 | 2,532 | 1,646 | 1,258 | 1,919 | |||||||||||||||
Total | 8,460 | 10,199 | 8,434 | 6,311 | 7,148 | |||||||||||||||
Excess of revenues over direct operating expenses | $ | 12,830 | $ | 20,271 | $ | 18,031 | $ | 12,353 | $ | 21,942 | ||||||||||
Acquired Underlying Properties: | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Oil sales | $ | 21,328 | $ | 29,298 | $ | 17,602 | $ | 12,158 | $ | 17,298 | ||||||||||
Natural gas sales | 1,904 | 2,248 | 781 | 582 | 683 | |||||||||||||||
Total | 23,232 | 31,545 | 18,383 | 12,740 | 17,981 | |||||||||||||||
Bad debt expense | — | 2,166 | — | — | — | |||||||||||||||
Direct operating expenses: | ||||||||||||||||||||
Lease operating expenses | 5,412 | 6,046 | 5,969 | 4,396 | 4,690 | |||||||||||||||
Production and property taxes | 1,231 | 1,614 | 1,170 | 814 | 950 | |||||||||||||||
Total | 6,643 | 7,660 | 7,139 | 5,210 | 5,640 | |||||||||||||||
Excess of revenues over direct operating expenses | $ | 16,589 | $ | 21,719 | $ | 11,244 | $ | 7,530 | $ | 12,341 | ||||||||||
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Nine Months Ended | ||||||||||||||||||||
Year Ended December 31, | September 30, | |||||||||||||||||||
2007 | 2008 | 2009 | 2009 | 2010 | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
(Unaudited) | ||||||||||||||||||||
Predecessor Pro Forma (unaudited) | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Oil sales | $ | 40,360 | $ | 44,682 | ||||||||||||||||
Natural gas sales | 2,292 | 2,540 | ||||||||||||||||||
Hedge and other derivative activity | 1,477 | (151 | ) | |||||||||||||||||
Total | 44,129 | 47,071 | ||||||||||||||||||
Bad debt recovery | (719 | ) | — | |||||||||||||||||
Direct operating expenses: | ||||||||||||||||||||
Lease operating expenses | 12,757 | 9,919 | ||||||||||||||||||
Production and property taxes | 2,816 | 2,869 | ||||||||||||||||||
Total | 15,573 | 12,788 | ||||||||||||||||||
Excess of revenues over direct operating expenses | $ | 29,275 | $ | 34,283 | ||||||||||||||||
Nine Months Ended | ||||||||||||||||||||
Year Ended December 31, | September 30, | |||||||||||||||||||
Underlying Properties (1) | 2007 | 2008 | 2009 | 2009 | 2010 | |||||||||||||||
(Unaudited) | ||||||||||||||||||||
Operating data: | ||||||||||||||||||||
Sales volumes: | ||||||||||||||||||||
Oil (MBbls) | 705 | 704 | 732 | 543 | 618 | |||||||||||||||
Natural gas (MMcf) | 738 | 750 | 693 | 525 | 519 | |||||||||||||||
Total sales (MBoe) | 828 | 829 | 847 | 631 | 705 | |||||||||||||||
Average sales prices: | ||||||||||||||||||||
Oil (per Bbl) | $ | 67.15 | $ | 93.67 | $ | 55.16 | $ | 50.01 | $ | 72.25 | ||||||||||
Natural gas (per Mcf) | $ | 5.96 | $ | 7.46 | $ | 3.31 | $ | 3.10 | $ | 4.89 | ||||||||||
Capital expenditures (in thousands): | ||||||||||||||||||||
Property acquisition | $ | 4,463 | $ | 7,899 | $ | 4,134 | $ | 1,981 | $ | 2,884 | ||||||||||
Well development | 2,420 | 2,499 | 2,407 | 1,027 | 6,099 | |||||||||||||||
Total | $ | 6,882 | $ | 10,398 | $ | 6,541 | $ | 3,008 | $ | 8,983 | ||||||||||
(1) | The operating data below includes the effect of the Acquired Underlying Properties for all periods presented. |
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Nine Months Ended | ||||||||||||||||||||
Year Ended December 31, | September 30, | |||||||||||||||||||
Predecessor Underlying Properties | 2007 | 2008 | 2009 | 2009 | 2010 | |||||||||||||||
(Unaudited) | ||||||||||||||||||||
Operating data: | ||||||||||||||||||||
Sales volumes: | ||||||||||||||||||||
Oil (MBbls) | 387 | 389 | 407 | 298 | 374 | |||||||||||||||
Natural gas (MMcf) | 391 | 426 | 415 | 311 | 339 | |||||||||||||||
Total (MBoe) | 452 | 460 | 477 | 350 | 431 | |||||||||||||||
Average sales prices: | ||||||||||||||||||||
Oil (per Bbl) | $ | 67.31 | $ | 94.11 | $ | 55.86 | $ | 50.37 | $ | 73.15 | ||||||||||
Natural gas (per Mcf) | $ | 6.39 | $ | 7.86 | $ | 3.64 | $ | 3.36 | $ | 5.47 | ||||||||||
Capital expenditures (in thousands): | ||||||||||||||||||||
Property acquisition | $ | 3,523 | $ | 6,715 | $ | 2,369 | $ | 1,027 | $ | 2,328 | ||||||||||
Well development | 1,603 | 1,063 | 1,955 | 747 | 5,638 | |||||||||||||||
Total | $ | 5,126 | $ | 7,778 | $ | 4,324 | $ | 1,774 | $ | 7,966 | ||||||||||
Nine Months Ended | ||||||||||||||||||||
Year Ended December 31, | September 30, | |||||||||||||||||||
Acquired Underlying Properties | 2007 | 2008 | 2009 | 2009 | 2010 | |||||||||||||||
(Unaudited) | ||||||||||||||||||||
Operating data: | ||||||||||||||||||||
Sales volumes: | ||||||||||||||||||||
Oil (MBbls) | 319 | 315 | 324 | 245 | 244 | |||||||||||||||
Natural gas (MMcf) | 347 | 324 | 278 | 214 | 180 | |||||||||||||||
Total (MBoe) | 376 | 369 | 371 | 281 | 274 | |||||||||||||||
Average sales prices: | ||||||||||||||||||||
Oil (per Bbl) | $ | 66.96 | $ | 93.12 | $ | 54.27 | $ | 49.58 | $ | 70.85 | ||||||||||
Natural gas (per Mcf) | $ | 5.49 | $ | 6.94 | $ | 2.81 | $ | 2.72 | $ | 3.80 | ||||||||||
Capital expenditures (in thousands): | ||||||||||||||||||||
Property acquisition | $ | 940 | $ | 1,184 | $ | 1,765 | $ | 954 | $ | 556 | ||||||||||
Well development | 817 | 1,436 | 452 | 280 | 461 | |||||||||||||||
Total | $ | 1,757 | $ | 2,620 | $ | 2,217 | $ | 1,234 | $ | 1,017 | ||||||||||
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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 |
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Gross | Net | |||||||
(Acres) | ||||||||
Kansas | 76,537 | 45,452.7 | ||||||
Texas | 23,693 | 16,841.3 | ||||||
Total | 100,230 | 62,294.0 | ||||||
Operated Wells | Non-Operated Wells | Total | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Oil | 814 | 516.1 | 34 | 8.4 | 848 | 524.5 | ||||||||||||||||||
Natural gas | 30 | 20.4 | 14 | 5.3 | 44 | 25.7 | ||||||||||||||||||
Total | 844 | 536.5 | 48 | 13.7 | 892 | 550.2 | ||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||
2007 | 2008 | 2009 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Completed: | ||||||||||||||||||||||||
Oil wells | 10 | 6.1 | 13 | 8.3 | 6 | 4.6 | ||||||||||||||||||
Natural gas wells | 2 | 0.8 | — | — | — | — | ||||||||||||||||||
Non-productive | 5 | 2.2 | 4 | 2.4 | — | — | ||||||||||||||||||
Total | 17 | 9.1 | 17 | 10.7 | 6 | 4.6 | ||||||||||||||||||
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Year Ended December 31, | ||||||||||||
2007 | 2008 | 2009 | ||||||||||
Sales prices: | ||||||||||||
Oil (per Bbl) | $ | 67.15 | $ | 93.67 | $ | 55.16 | ||||||
Natural gas (per Mcf) | $ | 5.96 | $ | 7.46 | $ | 3.31 | ||||||
Lease operating expense (per Boe) | $ | 14.49 | $ | 16.54 | $ | 15.06 | ||||||
Production and property taxes (per Boe) | $ | 3.75 | $ | 5.00 | $ | 3.32 |
Nine Months | ||||||||||||||||||||||||||||
Proved Reserves (1) | Ended | |||||||||||||||||||||||||||
% of | September 30, | |||||||||||||||||||||||||||
Total | 2010 Average | |||||||||||||||||||||||||||
Natural | % of | Pre-Tax | Net | |||||||||||||||||||||||||
Oil | Gas | Total | Total | PV-10 | PV-10 | Production | ||||||||||||||||||||||
Operating Area | (MBbls) | (MMcf) | (MBoe) | Reserves | Value (2) | Value | (Boe per day) | |||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||
Kansas (190 Fields) | ||||||||||||||||||||||||||||
Fairport | 799 | — | 799 | 6.1 | % | $ | 10,624 | 5.9 | % | 124 | ||||||||||||||||||
Chase-Silica | 405 | — | 405 | 3.1 | % | 5,508 | 3.1 | % | 86 | |||||||||||||||||||
Bindley | 350 | — | 350 | 2.7 | % | 4,830 | 2.7 | % | 51 | |||||||||||||||||||
Marcotte | 305 | — | 305 | 2.3 | % | 4,783 | 2.7 | % | 94 | |||||||||||||||||||
Moore-Johnson | 353 | — | 353 | 2.7 | % | 4,777 | 2.7 | % | 52 | |||||||||||||||||||
Codell | 137 | — | 137 | 1.1 | % | 3,268 | 1.8 | % | 30 | |||||||||||||||||||
Wesley | 141 | — | 141 | 1.1 | % | 2,604 | 1.5 | % | 35 | |||||||||||||||||||
Mueller | 149 | — | 149 | 1.1 | % | 2,421 | 1.4 | % | 30 | |||||||||||||||||||
Lippoldt | 91 | — | 91 | 0.7 | % | 1,519 | 0.9 | % | 15 | |||||||||||||||||||
Dopita | 99 | — | 99 | 0.8 | % | 1,369 | 0.8 | % | 20 | |||||||||||||||||||
Yaege | 100 | — | 100 | 0.8 | % | 1,354 | 0.8 | % | 18 | |||||||||||||||||||
Monument North | 64 | — | 64 | 0.5 | % | 1,330 | 0.7 | % | 27 | |||||||||||||||||||
Gerberding | 20 | 771 | 148 | 1.1 | % | 1,277 | 0.7 | % | 35 | |||||||||||||||||||
Other | 2,827 | 2,960 | 3,321 | 25.5 | % | 42,838 | 24.0 | % | 943 | |||||||||||||||||||
Kansas Total | 5,840 | 3,731 | 6,462 | 49.7 | % | $ | 88,500 | 49.5 | % | 1,559 | ||||||||||||||||||
Texas (3 Fields) | ||||||||||||||||||||||||||||
Kurten | 3,851 | 2,732 | 4,306 | 33.1 | % | $ | 56,513 | 31.6 | % | 705 | ||||||||||||||||||
Sand Flat | 1,351 | — | 1,351 | 10.4 | % | 18,366 | 10.3 | % | 146 | |||||||||||||||||||
Hitts Lake North | 888 | — | 888 | 6.8 | % | 15,311 | 8.6 | % | 172 | |||||||||||||||||||
Texas Total | 6,090 | 2,732 | 6,545 | 50.3 | % | $ | 90,190 | 50.5 | % | 1,024 | ||||||||||||||||||
Total | 11,930 | 6,463 | 13,007 | 100.0 | % | $ | 178,690 | 100.0 | % | 2,583 | ||||||||||||||||||
(1) | In accordance with the rules and regulations promulgated by the SEC, the proved reserves presented above were determined using the twelve month unweighted arithmetic average of thefirst-day-of-the-month price for the period from January 1, 2009 through December 1, 2009, without giving effect to any hedge transactions, and were held constant for the life of the properties. This yielded a price for oil of $61.18 per barrel and a price for natural gas of $3.83 per MMBtu. |
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(2) | PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted using an annual discount rate of 10%, calculated without deducting future income taxes. Standardized measure of discounted net cash flows is calculated the same asPV-10 except that it deducts future income taxes. Because the trust bears no federal tax expense and taxable income is passed through to the unitholders of the trust, no provision for federal or state income taxes is included in the summary reserve reports and therefore the standardized measure of discounted future net cash flows attributable to the Underlying Properties is equal to the pre-taxPV-10 value. PV-10 may not be considered a GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. The pre-taxPV-10 value and the standardized measure of discounted future net cash flows do not purport to present the fair value of the oil and natural gas reserves attributable to Underlying Properties. |
No. of Wells | Average | |||||||||||||||||||
Operated/ | Average | Net | ||||||||||||||||||
Non- | Productive | Gross/ | Working | Revenue | ||||||||||||||||
Field | Operated | Operator | County | Zones | Net Acres | Interest | Interest | |||||||||||||
Fairport | 56/5 | Vess Oil, Counts Ellis | Russell | Arbuckle, Dodge, LKC, Reagan, Wabaunsee | 1,320/963.5 | 70.9 | % | 61.1 | % | |||||||||||
Chase-Silica | 48/0 | Vess Oil, Davis Petroleum, L D Drilling | Barton, Rice, Stafford | Arbuckle, LKC | 2,760/2,038.1 | 84.0 | % | 69.4 | % | |||||||||||
Bindley | 16/0 | Vess Oil | Hodgeman | Mississippian | 1,360/1,166.0 | 89.0 | % | 77.0 | % | |||||||||||
Marcotte | 22/0 | Vess Oil | Rooks | Arbuckle, LKC | 1,760/1,676.7 | 95.9 | % | 79.7 | % | |||||||||||
Moore-Johnson | 10/0 | Vess Oil | Greeley | Morrow | 1,621/1,292.3 | 79.7 | % | 64.6 | % |
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No. of Wells | Average | |||||||||||||||||||
Operated/ | Average | Net | ||||||||||||||||||
Non- | Productive | Gross/ | Working | Revenue | ||||||||||||||||
Field | Operated | Operator | County | Zones | Net Acres | Interest | Interest | |||||||||||||
Codell | 2/0 | Vess Oil | Rooks | Arbuckle, LKC | 106/100.6 | 95.0 | % | 76.5 | % | |||||||||||
Wesley | 5/0 | L D Drilling, Davis Petroleum | Ness | Mississippian | 480/446.7 | 92.2 | % | 79.9 | % | |||||||||||
Mueller | 13/0 | Vess Oil, L D Drilling | Stafford | Arbuckle, Conglomerate, LKC | 640/497.0 | 86.6 | % | 70.6 | % | |||||||||||
Lippoldt | 6/0 | Vess Oil | Hodgeman | Mississippian | 1,280/604.8 | 47.3 | % | 41.3 | % | |||||||||||
Dopita | 9/0 | Vess Oil | Rooks | Arbuckle, Toronto | 380/357.1 | 93.2 | % | 81.5 | % | |||||||||||
Yaege | 26/0 | Vess Oil | Riley | Hunton | 2,098/1,094.1 | 52.2 | % | 45.6 | % | |||||||||||
Monument North | 11/10 | Vess Oil, McCoy Petroleum | Logan | Cherokee, Johnson | 1,760/601.3 | 24.5 | % | 19.9 | % | |||||||||||
Gerberding | 5/0 | Vess Oil | Sumner | Mississippian, Simpson | 800/570.0 | 71.9 | % | 58.3 | % |
No. of Wells | Average | |||||||||||||||||||
Operated/ | Average | Net | ||||||||||||||||||
Non- | Productive | Gross/ | Working | Revenue | ||||||||||||||||
Field | Operated | Operator | County | Zones | Net Acres | Interest | Interest | |||||||||||||
Kurten | 108/7 | Vess Oil Corp, CML and Ogden Resources | Brazos | Austin Chalk, Woodbine Sand, Buda, Georgetown | 20,908/15,280.4 | 72.5 | % | 58.0 | % | |||||||||||
Sand Flat | 20/1 | Vess Oil Corp., Carrizo | Smith | Paluxy, Rodessa | 2,579/1,418.0 | 55.0 | % | 48.2 | % | |||||||||||
Hitts Lake North | 6/0 | Vess Oil Corp | Smith | Paluxy | 206/142.9 | 59.9 | % | 52.9 | % |
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• | Kansas. VOC Sponsor’s historical development and workover program for the Kansas Underlying Properties has included recompleting certain existing wells, drilling infill development wells, conducting3-D seismic surveys, completing workovers and applying new production technologies. VOC Sponsor intends to continue this program with respect to the Kansas Underlying Properties, and expects to incur total development expenditures for these properties during the next five years of approximately $0.5 million, most of which is expected to be incurred during 2010 by the planned drilling of two vertical development wells. | |
• | Texas. VOC Sponsor’s historical development program for the Texas Underlying Properties has included recompleting certain existing wells, drilling infill development wells, completing workovers and applying new production technologies. In 2009, after an extensive review of horizontal development drilling in the area, VOC Sponsor commenced drilling horizontal wells in the Kurten Woodbine Unit in order to accelerate the development of proved undeveloped reserves. VOC Sponsor has successfully completed each of its first four horizontal wells to the Woodbine C sand in this area with average lateral lengths of approximately 3,000 feet. VOC Sponsor intends to continue developing the Woodbine C sand underlying the Kurten Woodbine Unit, utilizing horizontal wells completed with multiple fracture stimulations together with recompletions of existing vertical wellbores into additional pay intervals. VOC Sponsor expects total development expenditures for the Texas Underlying Properties during the next five years to be approximately $24.8 million. Of this total, VOC Sponsor contemplates spending approximately $21.5 million to drill and complete 11 horizontal wells in the Woodbine C sand and one vertical well in the Sand Flat Unit. The remaining approximate $3.3 million is expected to be used for recompletions and workovers of 13 Woodbine vertical wells to additional Woodbine sands and six existing wells in the Sand Flat Unit. |
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Underlying | Net Profits | |||||||
Properties (1) | Interest (2) | |||||||
(In thousands, except MBbls, MMcf and MBoe amounts) | ||||||||
Proved Reserves: | ||||||||
Oil (MBbls) | 11,930 | 7,132 | ||||||
Natural gas (MMcf) | 6,463 | 4,003 | ||||||
Oil equivalents (MBoe) | 13,007 | 7,799 | ||||||
Future net revenues | $ | 371,468 | $ | 238,175 | ||||
Discounted estimated future net revenues (3) | $ | 178,690 | ||||||
Standardized measure (3) | $ | 178,690 |
(1) | Reserve volumes and estimated future net revenues for Underlying Properties reflect volumes and revenues attributable to VOC Sponsor’s net interests in the properties comprising the Underlying Properties. | |
(2) | Reflects 80% of proved reserves attributable to the Underlying Properties expected to be produced during the term of the trust based on the reserve reports. | |
(3) | The present values of future net revenues for the Underlying Properties and the Net Profits Interest were determined using a discount rate of 10% per annum. As of September 30, 2010, |
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VOC Sponsor was structured as a limited partnership. Accordingly, no provision for federal or state income taxes has been provided because taxable income was passed through to the partners of VOC Sponsor. Therefore, the standardized measure of the Underlying Properties is equal to thePV-10 value, which totaled $178.7 million as of December 31, 2009. |
Oil | ||||||||||||
Oil | Natural Gas | Equivalents | ||||||||||
(MBbls) | (MMcf) | (MBoe) | ||||||||||
Proved Reserves: | ||||||||||||
Balance, December 31, 2006 | 13,031 | 7,927 | 14,352 | |||||||||
Revisions, extensions, discoveries and additions | (333 | ) | 191 | (301 | ) | |||||||
Production | (705 | ) | (738 | ) | (828 | ) | ||||||
Balance, December 31, 2007 | 11,993 | 7,380 | 13,223 | |||||||||
Revisions, extensions, discoveries and additions | (1,611 | ) | 227 | (1,573 | ) | |||||||
Production | (704 | ) | (750 | ) | (829 | ) | ||||||
Balance, December 31, 2008 | 9,678 | 6,857 | 10,821 | |||||||||
Revisions, extensions, discoveries and additions | 2,984 | 298 | 3,032 | |||||||||
Production | (732 | ) | (693 | ) | (847 | ) | ||||||
Balance, December 31, 2009 | 11,930 | 6,463 | 13,007 | |||||||||
Proved Developed Reserves: | ||||||||||||
Balance, December 31, 2006 | 12,355 | 7,596 | 13,621 | |||||||||
Balance, December 31, 2007 | 11,416 | 7,122 | 12,603 | |||||||||
Balance, December 31, 2008 | 8,952 | 6,562 | 10,046 | |||||||||
Balance, December 31, 2009 | 10,567 | 5,813 | 11,536 | |||||||||
Proved Undeveloped Reserves: | ||||||||||||
Balance, December 31, 2006 | 677 | 330 | 732 | |||||||||
Balance, December 31, 2007 | 577 | 258 | 620 | |||||||||
Balance, December 31, 2008 | 726 | 295 | 775 | |||||||||
Balance, December 31, 2009 | 1,363 | 649 | 1,471 | |||||||||
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• | royalties, overriding royalties and other burdens, express and implied, under oil and natural gas leases; | |
• | overriding royalties, production payments and similar interests and other burdens created by VOC Sponsor’s predecessors in title; | |
• | a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect the Underlying Properties or their title; | |
• | liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings; | |
• | pooling, unitization and communitization agreements, declarations and orders; | |
• | easements, restrictions,rights-of-way and other matters that commonly affect property; | |
• | conventional rights of reassignment that obligate VOC Sponsor to reassign all or part of a property to a third party if VOC Sponsor intends to release or abandon such property; and |
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• | rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties and the Net Profits Interest therein. |
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• | obtain permits to conduct regulated activities; | |
• | limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; | |
• | restrict the types, quantities and concentration of materials that can be released into the environment in the performance of drilling and production activities; | |
• | initiate remedial activities or corrective actions to mitigate pollution from former or current operations, such as restoration of drilling pits and plugging of abandoned wells; | |
• | apply specific health and safety criteria addressing worker protection; and | |
• | impose substantial liabilities on VOC Sponsor for pollution resulting from VOC Sponsor’s operations. |
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• | all payments to mineral or landowners, such as royalties, overriding royalties or other burdens against production, delay rentals, shut-in oil and natural gas payments, minimum royalty or other payments for drilling or deferring drilling; | |
• | any taxes paid by the owner of an Underlying Property to the extent not deducted in calculating gross proceeds, including estimated and accrued general property (ad valorem), production, severance, sales, gathering, excise and other taxes; | |
• | the aggregate amount paid by VOC Sponsor upon settlement of hedge contracts on a quarterly basis, as specified in the hedge contracts; | |
• | any extraordinary taxes or windfall profits taxes that may be assessed in the future that are based on profits realized or prices received for production from the Underlying Properties; | |
• | costs paid by an owner of a property comprising the Underlying Properties under any joint operating agreement pursuant to the terms of the conveyance; | |
• | all other costs and expenses, development costs and liabilities of exploring for, drilling, recompleting, workovers, operating and producing oil and natural gas, including allocated expenses such as labor, vehicle and travel costs and materials and any plugging and abandonment liabilities (net of any development costs for which a reserve had already |
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been made to the extent such development costs are incurred during the computation period) other than costs and expenses for certain future non-consent operations; |
• | costs or charges associated with gathering, treating and processing oil and natural gas, (provided, however, that any proceeds attributable to treatment or processing will offset such costs or changes, if any); | |
• | any overhead charge incurred pursuant to any operating agreement or other arrangement relating to an Underlying Property as permitted under the applicable conveyance, including the overhead fees payable by VOC Sponsor to VOC Operators and Vess Texas LLC as described in “Certain relationship and related party transactions”; | |
• | costs for recording the conveyance and costs estimated to record the termination and for release of the conveyance; | |
• | costs paid to counterparties under the hedge contracts or to the persons that provide credit to maintain any hedge contracts, excluding any hedge settlement amounts; | |
• | amounts previously included in gross proceeds but subsequently paid as a refund, interest or penalty; | |
• | costs and expenses for renewals or extensions of leases; and | |
• | at the option of VOC Sponsor (or any subsequent owner of the Underlying Properties), amounts reserved for approved development expenditure projects, including well drilling, recompletion and workover costs, which amounts will at no time exceed $1.0 million in the aggregate, and will be subject to the limitations described below (provided that such costs shall not be debited from gross proceeds when actually incurred). |
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• | amounts withheld or placed in escrow by a purchaser are not considered to be received by the owner of the Underlying Property until actually collected; | |
• | amounts received by the owner of the Underlying Property and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until disbursed to it by the escrow agent; and | |
• | amounts received by the owner of the Underlying Property and not deposited with an escrow agent will be considered to have been received. |
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• | increase the power of the trustee or the Delaware trustee to engage in business or investment activities; or | |
• | alter the rights of the trust unitholders as among themselves. |
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• | collecting cash attributable to the Net Profits Interest; | |
• | paying expenses, charges and obligations of the trust from the trust’s assets; | |
• | distributing distributable cash to the trust unitholders; | |
• | causing to be prepared and distributed a tax information report for each trust unitholder and to prepare and file tax returns on behalf of the trust; | |
• | causing to be prepared and filed reports required to be filed under the Securities Exchange Act of 1934 and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading; | |
• | establishing, evaluating and maintaining a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002; | |
• | enforcing the rights under certain agreements entered into in connection with this offering; and | |
• | taking any action it deems necessary and advisable to best achieve the purposes of the trust. |
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• | interest bearing obligations of the United States government; | |
• | money market funds that invest only in United States government securities; | |
• | repurchase agreements secured by interest-bearing obligations of the United States government; or | |
• | bank certificates of deposit. |
• | the sale does not involve a material part of the trust’s assets and is in the judgment of VOC sponsor in the best interests of the trust unitholders; or | |
• | the sale constitutes a material part of the trust’s assets and is in the best interests of the trust unitholders, subject to the holders representing a majority of the outstanding trust units approving the sale. |
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• | charge for its services as trustee; | |
• | retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the trustee to the extent permitted by law); | |
• | lend funds at commercial rates to the trust to pay the trust’s expenses; and | |
• | seek reimbursement from the trust for itsout-of-pocket expenses. |
• | the trust sells the Net Profits Interest; | |
• | annual cash available for distribution to the trust is less than $1 million for each of two consecutive years; | |
• | the holders of a majority of the outstanding trust units vote in favor of dissolution; or | |
• | the trust is judicially dissolved. |
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• | dissolve the trust; | |
• | remove the trustee or the Delaware trustee; | |
• | amend the trust agreement (except with respect to certain matters that do not adversely affect the rights of trust unitholders in any material respect); | |
• | merge or consolidate the trust with or into another entity; or | |
• | approve the sale of all or any material part of the assets of the trust. |
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Trust Units | Common Stock | |||
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. | ||
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. | ||
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. | ||
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. | ||
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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• | 1.0% of the total number of the securities outstanding, or | |
• | the average weekly reported trading volume of the trust units for the four calendar weeks prior to the sale. |
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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; | |
• | 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 | |
• | 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: |
• | have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities;” | |
• | 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 | |
• | become eligible for resale pursuant to Rule 144 (or any similar rule then in effect under the Securities Act). |
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• | banks, insurance companies or other financial institutions; | |
• | trust unitholders subject to the alternative minimum tax; | |
• | tax-exempt organizations; | |
• | dealers in securities or commodities; | |
• | regulated investment companies; | |
• | traders in securities that elect to use amark-to-market method of accounting for their securities holdings; | |
• | non-U.S. trust unitholders (as defined below) that are “controlled foreign corporations” or “passive foreign investment companies”; | |
• | persons that are S-corporations, partnerships or other pass-through entities; | |
• | persons that own their interest in the trust units through S-corporations, partnerships or other pass-through entities; | |
• | persons that at any time own more than 5% of the aggregate fair market value of the trust units; | |
• | expatriates and certain former citizens or long-term residents of the United States; | |
• | 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 | |
• | persons deemed to sell the trust units under the constructive sale provisions of the Code. |
• | 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, | |
• | 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, | |
• | an estate the income of which is subject to U.S. federal income taxation regardless of its source, or | |
• | a trust if it is subject to the primary supervision of a U.S. court and the control of one or more United States persons (as defined for U.S. federal income tax purposes) or that has a valid election in effect under applicable U.S. Treasury regulations to be treated as a United States person. |
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103
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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; | |
• | divided by the number of days in the accrual period; and | |
• | multiplied by the number of days during the accrual period that the trust unitholder held the trust units. |
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106
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• | 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; | |
• | 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 | |
• | 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. |
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• | is a United States person; | |
• | derives 50% or more of its gross income for certain periods from the conduct of a trade or business in the United States; | |
• | is a controlled foreign corporation for U.S. federal income tax purposes; or | |
• | is a foreign partnership that, at any time during its taxable year, has more than 50% of its income or capital interests owned by United States persons or is engaged in the conduct of a U.S. trade or business. |
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• | whether the investment satisfies the prudence requirements of Section 404(a)(1)(B) of ERISA; | |
• | whether the investment satisfies the diversification requirements of Section 404(a)(1)(C) of ERISA; and | |
• | whether the investment is in accordance with the documents and instruments governing the plan as required by Section 404(a)(1)(D) of ERISA. |
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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 | % | — | — |
(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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Number of | ||||
Underwriter | Trust Units | |||
Raymond James & Associates, Inc. | ||||
Total |
Per Unit | No Exercise | Full Exercise | ||||||||||
Public offering price | $ | $ | $ | |||||||||
Underwriting discounts and commissions | ||||||||||||
Proceeds, before expenses, to VOC Sponsor |
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• | not to offer, sell, contract to sell, announce the intention to sell or pledge any of the trust units; | |
• | not to grant or sell any option or contract to purchase any of the trust units; | |
• | 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 | |
• | 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. |
• | 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 | |
• | 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 |
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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. |
• | short sales, | |
• | syndicate covering transactions, | |
• | imposition of penalty bids, and | |
• | purchases to cover positions created by short sales. |
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• | estimates of distributions to trust unitholders, | |
• | overall quality of the oil and natural gas properties attributable to the Underlying Properties, | |
• | industry and market conditions prevalent in the energy industry, | |
• | the information set forth in this prospectus and otherwise available to the representatives; and | |
• | the general conditions of the securities markets at the time of this offering. |
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117
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118
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119
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120
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121
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122
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PREDECESSOR UNDERLYING PROPERTIES: | ||||
F-2 | ||||
F-3 | ||||
F-4 | ||||
ACQUIRED UNDERLYING PROPERTIES: | ||||
F-10 | ||||
F-11 | ||||
F-12 | ||||
F-18 | ||||
F-19 | ||||
VOC ENERGY TRUST: | ||||
F-20 | ||||
F-21 | ||||
F-22 | ||||
F-24 | ||||
F-25 | ||||
F-26 | ||||
F-27 |
F-1
Table of Contents
F-2
Table of Contents
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 | ||||||||||
F-3
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
F-4
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
F-5
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
F-6
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
Oil | Gas | |||||||
(Bbls) | (Mcf) | |||||||
Proved reserves: | ||||||||
Balance at December 31, 2006 | 8,174,154 | 4,573,914 | ||||||
Revisions, extensions, discoveries and additions | (332,769 | ) | 190,995 | |||||
Production | (386,879 | ) | (390,593 | ) | ||||
Balance at December 31, 2007 | 7,454,506 | 4,374,316 | ||||||
Revisions, extensions, discoveries and additions | (569,089 | ) | 276,043 | |||||
Production | (389,268 | ) | (426,326 | ) | ||||
Balance at December 31, 2008 | 6,496,149 | 4,224,033 | ||||||
Revisions, extensions, discoveries and additions | 2,003,848 | 693,788 | ||||||
Production | (407,415 | ) | (414,730 | ) | ||||
Balance at December 31, 2009 | 8,092,582 | 4,503,091 | ||||||
Proved developed reserves: | ||||||||
December 31, 2006 | 7,497,626 | 4,243,531 | ||||||
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 | ||||||
FROM PROVED OIL AND GAS RESERVES
F-7
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
F-8
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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 | ||||||
FLOWS FROM PROVED OIL AND GAS RESERVES
2007 | 2008 | 2009 | ||||||||||
Standardized measure at beginning of year | $ | 151,282,536 | $ | 206,509,831 | $ | 59,940,454 | ||||||
Sales of oil and gas produced, net of production costs | (20,049,955 | ) | (29,744,163 | ) | (15,788,110 | ) | ||||||
Net changes in price and production costs | 68,207,350 | (154,948,134 | ) | 41,400,518 | ||||||||
Changes in estimated future development costs | 222,643 | (2,726,749 | ) | (14,381,027 | ) | |||||||
Development costs incurred during the period which reduce future development costs | 1,200,100 | 52,800 | 2,700,100 | |||||||||
Revisions of quantity estimates | (8,530,591 | ) | (5,476,929 | ) | 32,773,504 | |||||||
Accretion of discount | 15,128,254 | 20,650,983 | 5,994,045 | |||||||||
Change in production rates, timing and other | (950,506 | ) | 25,622,815 | 7,742,421 | ||||||||
Standardized measure at end of year | $ | 206,509,831 | $ | 59,940,454 | $ | 120,381,905 | ||||||
F-9
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F-10
Table of Contents
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 | ||||||||||
F-11
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
F-12
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
F-13
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
F-14
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
Oil | Gas | |||||||
(Bbls) | (Mcf) | |||||||
Proved reserves: | ||||||||
Balance at December 31, 2006 | 4,857,130 | 3,352,686 | ||||||
Revisions, extensions, discoveries and additions | — | — | ||||||
Production | (318,523 | ) | (347,057 | ) | ||||
Balance at December 31, 2007 | 4,538,607 | 3,005,629 | ||||||
Revisions, extensions, discoveries and additions | (1,041,821 | ) | (48,799 | ) | ||||
Production | (314,620 | ) | (323,964 | ) | ||||
Balance at December 31, 2008 | 3,182,166 | 2,632,866 | ||||||
Revisions, extensions, discoveries and additions | 979,834 | (395,370 | ) | |||||
Production | (324,329 | ) | (278,022 | ) | ||||
Balance at December 31, 2009 | 3,837,671 | 1,959,474 | ||||||
Proved developed reserves: | ||||||||
December 31, 2006 | 4,857,130 | 3,352,686 | ||||||
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 | — | — | ||||||
FROM PROVED OIL AND GAS RESERVES
F-15
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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 | ||||||
F-16
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
FLOWS FROM PROVED OIL AND GAS RESERVES
2007 | 2008 | 2009 | ||||||||||
Standardized measure at beginning of year | $ | 129,328,212 | $ | 133,461,982 | $ | 34,675,250 | ||||||
Sales of oil and gas produced, net of production costs | (16,588,154 | ) | (23,885,512 | ) | (11,244,020 | ) | ||||||
Net changes in price and production costs | 7,789,103 | (104,299,841 | ) | 13,586,121 | ||||||||
Changes in estimated future development costs | — | — | (123,046 | ) | ||||||||
Revisions of quantity estimates | — | (10,865,844 | ) | 15,494,644 | ||||||||
Accretion of discount | 12,932,821 | 13,346,198 | 3,467,525 | |||||||||
Change in production rates, timing and other | — | 26,918,267 | 2,451,480 | |||||||||
Standardized measure at end of year | $ | 133,461,982 | $ | 34,675,250 | $ | 58,307,954 | ||||||
F-17
Table of Contents
DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES
F-18
Table of Contents
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 | ||||||||||||
(a) | Pro forma adjustment to give effect to the acquisition of the Acquired Properties as if the acquisition had occurred on January 1, 2009. |
F-19
Table of Contents
F-20
Table of Contents
December 17, | ||||
2010 | ||||
ASSETS | ||||
Cash | $ | 1,000 | ||
TRUST CORPUS | ||||
Trust Corpus | $ | 1,000 | ||
F-21
Table of Contents
F-22
Table of Contents
NOTE C — | INCOME TAXES |
NOTE D — | DISTRIBUTIONS TO UNITHOLDERS |
NOTE E — | SUBSEQUENT EVENTS |
F-23
Table of Contents
F-24
Table of Contents
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 | ||||||
(a) | VOC Energy Trust was formed in November, 2010 and capitalized on December 17, 2010. |
F-25
Table of Contents
Year Ended | Nine Months Ended | |||||||
December 31, 2009 | September 30, 2010 | |||||||
Historical Results | ||||||||
Income from the net profits interest (See Note D) | $ | 19,316,462 | $ | 20,363,174 | ||||
Pro Forma Adjustments | ||||||||
Less trust general and administrative expenses (See Note E(a)) | 900,000 | 675,000 | ||||||
Distributable income | $ | 18,416,462 | $ | 19,688,174 | ||||
Distributable income per unit | $ | $ | ||||||
F-26
Table of Contents
F-27
Table of Contents
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 | ||||
(1) | Per terms of the net profits interest development costs are to be deducted when calculating the distributable income to the Trust. |
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 | ||
(1) | See Note F below for a description of asset retirement obligation. |
F-28
Table of Contents
F-29
Table of Contents
VOC BRAZOS ENERGY PARTNERS, L.P.
(VOC SPONSOR)
The trust units are not interests in or obligations of
VOC Sponsor
VOC-1
Table of Contents
VOC-2
Table of Contents
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 | 34 | Vice President and Chief Financial Officer | ||||
Alan Howarter | 54 | Vice President of Financial Reporting |
VOC-3
Table of Contents
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 |
VOC-4
Table of Contents
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 |
VOC-5
Table of Contents
FINANCIAL DATA OF VOC SPONSOR
VOC-6
Table of Contents
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 | ) |
VOC-7
Table of Contents
AND RESULTS OF OPERATIONS OF VOC SPONSOR
VOC-8
Table of Contents
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 | ||||||||||
VOC-9
Table of Contents
VOC-10
Table of Contents
VOC-11
Table of Contents
VOC-12
Table of Contents
VOC-13
Table of Contents
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 |
VOC-14
Table of Contents
VOC-15
Table of Contents
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 | ||||||||||
(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. |
VOC-16
Table of Contents
VOC-17
Table of Contents
VOC-18
Table of Contents
VOC-19
Table of Contents
VOC-20
Table of Contents
VOC-21
Table of Contents
VOC-22
Table of Contents
VOC-23
Table of Contents
VOC-24
Table of Contents
VOC-25
Table of Contents
PREDECESSOR: | ||||
VOC F-2 | ||||
VOC F-3 | ||||
VOC F-4 | ||||
VOC F-5 | ||||
VOC F-6 | ||||
VOC F-7 | ||||
Introduction | VOC F-27 | |||
VOC F-28 | ||||
VOC F-29 | ||||
VOC F-30 |
VOC F-1
Table of Contents
VOC F-2
Table of Contents
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 | |||||||
VOC F-3
Table of Contents
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 | ||||||||||
VOC F-4
Table of Contents
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 | ||||||||||||
VOC F-5
Table of Contents
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 | $ | — | $ | — | $ | — |
VOC F-6
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
VOC F-7
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
VOC F-8
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
VOC F-9
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
VOC F-10
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
VOC F-11
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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, | 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 | ||||||||||
VOC F-13
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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 | |||||||
VOC F-14
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
2010 | $ | 1,531,276 | ||
2011 | 1,330,221 | |||
2012 | 298,880 | |||
2013 | 24,031,910 | |||
$ | 27,192,287 | |||
VOC F-15
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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
Table of Contents
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. |
VOC F-17
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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 | $ | — | $ | — | $ | — |
* | 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
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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 |
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
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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 | ) |
VOC F-21
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
VOC F-22
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
VOC F-23
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
Oil | Gas | |||||||
(Bbls) | (Mcf) | |||||||
Proved reserves: | ||||||||
Balance at December 31, 2006 | 8,174,154 | 4,573,914 | ||||||
Revisions, extensions, discoveries and additions | (332,769 | ) | 190,995 | |||||
Production | (386,879 | ) | (390,593 | ) | ||||
Balance at December 31, 2007 | 7,454,506 | 4,374,316 | ||||||
Revisions, extensions, discoveries and additions | (569,089 | ) | 276,043 | |||||
Production | (389,268 | ) | (426,326 | ) | ||||
Balance at December 31, 2008 | 6,496,149 | 4,224,033 | ||||||
Revisions, extensions, discoveries and additions | 2,003,848 | 693,788 | ||||||
Production | (407,415 | ) | (414,730 | ) | ||||
Balance at December 31, 2009 | 8,092,582 | 4,503,091 | ||||||
Proved developed reserves: | ||||||||
December 31, 2006 | 7,497,626 | 4,243,531 | ||||||
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 | ||||||
FROM PROVED OIL AND GAS RESERVES
VOC F-24
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
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 | ||||||
VOC F-25
Table of Contents
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009 and 2010 is unaudited)
FLOWS FROM PROVED OIL AND GAS RESERVES
2007 | 2008 | 2009 | ||||||||||
Standardized measure at beginning of year | $ | 151,282,536 | $ | 206,509,831 | $ | 59,940,454 | ||||||
Sales of oil and gas produced, net of production costs | (20,049,955 | ) | (29,744,163 | ) | (15,788,110 | ) | ||||||
Net changes in price and production costs | 68,207,350 | (154,948,134 | ) | 41,400,518 | ||||||||
Changes in estimated future development costs | 222,643 | (2,726,749 | ) | (14,381,027 | ) | |||||||
Development costs incurred during the period which reduce future development costs | 1,200,100 | 52,800 | 2,700,100 | |||||||||
Revisions of quantity estimates | (8,530,591 | ) | (5,476,929 | ) | 32,773,504 | |||||||
Accretion of discount | 15,128,254 | 20,650,983 | 5,994,045 | |||||||||
Change in production rates, timing and other | (950,506 | ) | 25,622,815 | 7,742,421 | ||||||||
Standardized measure at end of year | $ | 206,509,831 | $ | 59,940,454 | $ | 120,381,905 | ||||||
VOC F-26
Table of Contents
VOC F-27
Table of Contents
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 | ||||||||||
VOC F-28
Table of Contents
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 | |||||||||||||||||||
VOC F-29
Table of Contents
VOC F-30
Table of Contents
(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), liabilities, owners’ equity and oil and gas revenues and related expenses. |
September 30, 2010 | ||||||
(b) | Gross cash proceeds from the sale of the trust units | $ | 174,000,000 | |||
Cash down payment on related party note | 9,287,116 | |||||
Payment of estimated remaining transaction fees and costs from the sale of trust units | (13,829,684 | ) | ||||
Distribution to members | (169,457,432 | ) | ||||
$ | — | |||||
(c) | Receivable from related party for sale of 34.8% of trust units at historical value | $ | 42,384,338 | |||
Cash down payment on receivable | 9,287,116 | |||||
Remaining receivable from related party for sale of 34.8% of trust units | $ | 33,097,222 | ||||
(d) | Current payable for conveyance of oil swap agreements to the Trust | $ | 729,353 | |||
Long-term payable for conveyance of oil swap agreements to the Trust | 266,960 | |||||
$ | 996,313 | |||||
Reduction of oil and gas properties due to conveyance of net profits interest | $ | (144,145,310 | ) | |||
Reduction of associated accumulated depreciation, depletion, and amortization | 21,065,438 | |||||
$ | (123,079,872 | ) | ||||
Current receivable from Trust for conveyance of asset retirement obligation | $ | 339,234 | ||||
Long-term receivable from Trust for conveyance of asset retirement obligation | 1,942,872 | |||||
$ | 2,282,106 | |||||
Net oil and gas properties and equipment | $ | 153,849,839 | ||||
Asset retirement obligation liability | (2,852,632 | ) | ||||
Oil swap agreements | 1,245,391 | |||||
152,242,598 | ||||||
80% Net Profits Interest | $ | 121,794,078 | ||||
(e) | 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 | ||||
Less: Net book value of conveyed net profits interests | (79,409,741 | ) | ||||
Deferred transaction fees and costs incurred as of September 30, 2010 | (350,316 | ) | ||||
Payment of Underwriting discounts, structuring fees and other offering expenses | (13,829,684 | ) | ||||
Deferred gain on sale | $ | 80,410,259 | ||||
Current portion of deferred gain | $ | 7,235,963 | ||||
Long-term portion of deferred gain | $ | 73,174,296 | ||||
(f) | To record distribution of remaining cash to general partner | $ | (1,349,220 | ) | ||
(g) | To record distribution of remaining cash to limited partner | $ | (66,121,443 | ) | ||
(h) | To record distribution of remaining cash to common control owners | $ | (101,986,769 | ) | ||
VOC F-31
Table of Contents
Year Ended | Nine Months Ended | |||||||||
December 31, 2009 | September 30, 2010 | |||||||||
(i) | Decrease in oil and gas sales attributable to net profits interest | $ | (35,303,040 | ) | $ | (37,656,677 | ) | |||
(j) | To record amortization of gain on sale of trust units over the life of the trust | $ | 7,005,413 | $ | 5,216,956 | |||||
(k) | Decrease in lease operating expenses attributable to the net profits interest | $ | (10,205,654 | ) | $ | (7,935,024 | ) | |||
(l) | Decrease in production and property taxes attributable to the net profits interest | $ | (2,252,681 | ) | $ | (2,295,274 | ) | |||
(m) | Reduce depreciation on assets sold to Trust | $ | (7,847,694 | ) | $ | (5,968,621 | ) | |||
VOC F-32
Table of Contents
Re: | Evaluation Summary VOC Brazos Energy Partners, L.P. Interests Total Proved Reserves Brazos and Smith Counties, Texas As of January 1, 2010 |
Proved | Proved | |||||||||||||||||
Developed | Developed | Proved | Total | |||||||||||||||
Producing | Non-Producing | Undeveloped | Proved | |||||||||||||||
Net Reserves | ||||||||||||||||||
Oil | — Mbbl | 3,836.3 | 378.1 | 1,363.0 | 5,577.4 | |||||||||||||
Gas | — MMcf | 1,902.0 | 180.4 | 649.1 | 2,731.5 | |||||||||||||
Revenue | ||||||||||||||||||
Oil | — M$ | 219,756.3 | 21,937.3 | 80,222.0 | 321,915.5 | |||||||||||||
Gas | — M$ | 12,897.5 | 1,135.6 | 3,164.4 | 17,197.5 | |||||||||||||
Severance Taxes | — M$ | 10,447.4 | 1,094.3 | 3,927.5 | 15,469.2 | |||||||||||||
Ad Valorem Taxes | — M$ | 6,378.4 | 658.0 | 2,480.1 | 9,516.5 | |||||||||||||
Operating Expenses | — M$ | 81,383.0 | 3,847.0 | 8,268.8 | 93,498.6 | |||||||||||||
Workover Expenses | — M$ | 3,725.5 | 0.0 | 0.0 | 3,725.5 | |||||||||||||
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 | |||||||||||||
Investments | — M$ | 0.0 | 3,344.8 | 21,448.6 | 24,793.3 | |||||||||||||
Net Operating Income | — M$ | 128,238.0 | 14,028.1 | 47,057.9 | 189,323.9 | |||||||||||||
Discounted @ 10% | — M$ | 56,090.4 | 7,286.6 | 18,253.6 | 81,630.5 |
Annex A-1
Table of Contents
March 22, 2010
WTI Cushing | Henry Hub | |||||||
Crude Oil | Natural Gas | |||||||
Year | $/STB | $/MMBTU | ||||||
2010 | 61.18 | 3.833 | ||||||
Thereafter | 61.18 | 3.833 |
Annex A-2
Table of Contents
March 22, 2010
Texas Registered Engineering Firm (F-693)
Annex A-3
Table of Contents
Mr. Bill Horigan Vess Oil Corporation 1700 Waterfront Pkwy, Bldg 500 Wichita, Kansas 67206 |
Re: | Evaluation Summary | |||||
VOC Kansas Energy Partners, LLC | ||||||
Composite of Various Interest Groups | ||||||
Certain Properties in Kansas & Texas | ||||||
Total Proved Reserves | ||||||
As of December 31, 2009 |
Proved | Proved | |||||||||||
Developed | Developed | Total | ||||||||||
Producing | Non-Producing | Proved | ||||||||||
Net Reserves | ||||||||||||
Oil | 6,209.9 | 143.0 | 6,352.9 | |||||||||
Gas | 3,731.0 | 0.0 | 3,731.0 | |||||||||
Revenue | ||||||||||||
Oil | 334,898.6 | 7,713.1 | 342,611.8 | |||||||||
Gas | 10,666.6 | 0.0 | 10,666.6 | |||||||||
Severance Taxes | 3,469.9 | 0.0 | 3,469.9 | |||||||||
Ad Valorem Taxes | 11,541.8 | 388.5 | 11,930.4 | |||||||||
Operating Expenses | 128,561.1 | 1,358.5 | 129,919.6 | |||||||||
Workover Expenses | 0.0 | 0.0 | 0.0 | |||||||||
COPAS | 25,024.1 | 266.5 | 25,290.6 | |||||||||
Investments | 0.0 | 523.6 | 523.6 | |||||||||
Net Operating Income | 176,968.3 | 5,176.0 | 182,144.3 | |||||||||
Discounted @ 10% | 94,549.7 | 2,509.7 | 97,059.3 |
Annex A-4
Table of Contents
October 20, 2010
WTI Cushing | Henry Hub | |||||||
Crude Oil | Natural Gas | |||||||
Year | $/STB | $/MMBTU | ||||||
2009 | 61.18 | 3.833 | ||||||
Thereafter | 61.18 | 3.833 |
Annex A-5
Table of Contents
October 20, 2010
Texas Registered Engineering Firm (F-693)
Annex A-6
Table of Contents
Table of Contents
Item 13. | Other Expenses of Issuance and Distribution. |
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 | $ | * | ||
* | To be provided by amendment |
Item 14. | Indemnification of Directors and Officers. |
II-1
Table of Contents
Item 15. | Recent Sales of Unregistered Securities. |
Item 16. | Exhibits and Financial Statement Schedules. |
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) |
* | Filed herewith. |
II-2
Table of Contents
Item 17. | Undertakings. |
II-3
Table of Contents
By: | Vess Texas Partners, LLC, its General Partner | |
By: | Vess Holding Corporation, its Manager |
II-4
Table of Contents
By: | VOC Brazos Energy Partners, L.P. | |
By: | Vess Texas Partners, LLC, its General Partner | |
By: | Vess Holding Corporation, its Manager |
II-5
Table of Contents
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). |
* | Filed herewith. |