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to
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 |
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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. |
• | Prices of oil and natural gas fluctuate and lower prices could reduce proceeds to the trust and cash distributions to unitholders. | |
• | An increase in the differential between the price realized by VOC Sponsor for oil or natural gas produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the proceeds to the trust and therefore the cash distributions by the trust and the value of trust units. | |
• | Estimates of future cash distributions to unitholders are based on assumptions that are inherently subjective. | |
• | Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the trust and the value of the trust units. | |
• | The processes of drilling and completing wells are high risk activities. | |
• | Neither the trust nor the trust’s unitholders will have the ability to influence VOC Sponsor or control the operations or development of the Underlying Properties. | |
• | The trust is managed by a trustee who cannot be replaced except by a majority vote of the unitholders at a special meeting, which may make it difficult for unitholders to remove or replace the trustee. | |
• | The tax treatment of an investment in trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis. | |
• | The trust has not requested a ruling from the IRS regarding the tax treatment of ownership of the trust units. If the IRS were to determine (and be sustained in that determination) that the trust is not a “grantor trust” for federal income tax purposes, or that the Net Profits Interest is not properly treated as a production payment (and thus would fail to qualify as a debt instrument) for federal income tax purposes, the trust unitholders may receive different and potentially less advantageous tax treatment from that described in this prospectus. |
Per | ||||||||
Trust | ||||||||
Unit | Total | |||||||
Initial public offering price | $ | $ | ||||||
Underwriting discounts and commissions (1) | $ | $ | ||||||
Proceeds, before expenses, to VOC Sponsor | $ | $ |
(1) | Excludes a structuring fee of 0.50% of the gross proceeds of the offering payable to Raymond James & Associates, Inc. by VOC Sponsor for the evaluation, analysis and structuring of the trust. |
RAYMOND JAMES | MORGAN STANLEY |
OPPENHEIMER & CO. |
RBC CAPITAL MARKETS |
BAIRD |
JANNEY MONTGOMERY SCOTT |
MORGAN KEEGAN |
WUNDERLICH SECURITIES |
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of the Underlying Properties in the States of Kansas and Texas
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Annex C-1 | ||||||||
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EX-3.6 | ||||||||
EX-5.1 | ||||||||
EX-8.1 | ||||||||
EX-10.3 | ||||||||
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EX-10.5 | ||||||||
EX-23.1 | ||||||||
EX-23.4 |
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• | VOC Brazos will acquire all of the membership interests in KEP in exchange for newly issued limited partner interests in VOC Brazos pursuant to a Contribution and Exchange Agreement dated August 30, 2010, resulting in KEP becoming a wholly-owned subsidiary of VOC Brazos. KEP was formed in November 2009 to engage in the production and development of oil and natural gas primarily within the state of Kansas. 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 in exchange for 16,540,000 trust units in the aggregate, representing all of the outstanding trust units of the trust. | |
• | VOC Sponsor will sell the 10,785,000 trust units offered hereby, representing a 65.2% interest in the trust. VOC Sponsor will also make available during the30-day option period up to 1,617,750 trust units for the underwriters to purchase at the initial offering price to cover over-allotments. VOC Sponsor intends to use the proceeds of the offering as disclosed under “Use of Proceeds.” | |
• | Forty-five days following the closing of this offering, VOC Sponsor will sell the remaining trust units which it holds to VOC Partners, LLC, an affiliate of VOC Sponsor, at the initial offering price. | |
• | 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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Year Ended | ||||||||||||||||||||||||||||||||||||||||
Number | December 31, | |||||||||||||||||||||||||||||||||||||||
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 | 742 | 6,535 | 3,550 | 7,127 | 91.7 | % | 94.8 | % | $ | 134.8 | 74.4 | % | 61.8 | % | 1,536 | |||||||||||||||||||||||||
Texas | 139 | 6,007 | 3,399 | 6,573 | 91.4 | % | 72.6 | % | $ | 133.5 | 68.0 | % | 56.1 | % | 1,011 | |||||||||||||||||||||||||
Total | 881 | 12,542 | 6,949 | 13,700 | 91.5 | % | 84.1 | % | $ | 268.3 | 71.2 | % | 58.9 | % | 2,547 | |||||||||||||||||||||||||
(1) | In accordance with the rules and regulations promulgated by the SEC, the proved reserves presented above were determined using the twelve month unweighted arithmetic average of thefirst-day-of-the-month price for the period from January 1, 2010 through December 1, 2010, without giving effect to any hedge transactions, and were held constant for the life of the properties. This yielded a price for oil of $79.43 per Bbl and a price for natural gas of $4.37 per MMBtu. | |
(2) | Oil equivalents in the table are the sum of the Bbls of oil and the Boe of the stated Mcfs of natural gas, calculated on the basis that six Mcfs of natural gas is the energy equivalent of one Bbl of oil. | |
(3) | PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted using an annual discount rate of 10%, calculated without deducting future income taxes. Standardized |
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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. |
• | 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 through December 31, 2015 of approximately $3.2 million. Of this total, VOC Sponsor contemplates spending approximately $2.5 million to drill and complete 13 vertical wells. The remaining approximate $0.7 million is expected to be used for recompletions and workovers of 12 wells. | |
• | Texas. VOC 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 through December 31, 2015 to be approximately $24.0 million. Of this total, VOC Sponsor contemplates spending approximately $22.5 million to drill and complete 11 horizontal wells in the Woodbine C sand. The remaining approximate $1.5 million is expected to be used for recompletions and workovers of 12 Woodbine vertical wells to additional Woodbine sands and seven existing wells in the Sand Flat Unit. |
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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. VOC Sponsor acquired interests in the Texas Underlying Properties through various acquisitions that have occurred since the inception of VOC Brazos in 2003 and in the Kansas Underlying Properties through the contribution to KEP by its members in December 2010 of properties obtained through various acquisitions and drilling activities since 1979. Proved reserves attributable to the Underlying Properties have remained relatively stable, with proved reserves of approximately 10.8 MMBoe as of December 31, 2008 (based on ayear-end oil price of $44.60 per Bbl), 13.0 MMBoe as of December 31, 2009 (based on average oil prices of $61.18 per Bbl) and 13.7 MMBoe as of December 31, 2010 (based on average oil prices of $79.43 per Bbl). Based on the reserve reports and assuming for purposes of this calculation that no additional development drilling or other development expenditures are made on the Underlying Properties after 2014, production |
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from the Underlying Properties is expected to decline at an average annual rate of approximately 6.2% over the next 20 years. VOC Sponsor may continue to drill beyond 2014, and such drilling may reduce the anticipated decline rate if successful. |
• | Substantial proved developed producing reserves. Proved developed producing reserves are the lowest risk category of reserves because production has already commenced, and VOC Sponsor does not expect the proved developed producing reserves attributable to the Underlying Properties to require significant future development costs. Proved developed producing reserves attributable to the Underlying Properties represented approximately 84% of the proved reserves attributable to the Underlying Properties as of December 31, 2010. | |
• | Near term development activities. VOC Sponsor has identified multiple locations on the Underlying Properties on which it intends to drill new infill wells and recomplete existing wells into new horizons over the next several years. See “— Planned development and workover program” for a summary of VOC 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. No assurance can be given, however, that any development well will produce in commercially paying quantities or that the characteristics of any development well will match the characteristics of VOC Sponsor’s existing wells or VOC Sponsor’s historical drilling success rate. | |
• | Operational control. The right to operate an oil and natural gas lease is important because the operator can control the timing and amount of discretionary expenditures for operational and development activities. As of December 31, 2010, the VOC Operators operated, or operated on a contract basis, approximately 98% of the proved reserves attributable to the Underlying Properties based 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 2,621 Boe per day (or approximately 2,097 Boe per day attributable to MVO’s 80% net profit interest) for the year ended December 31, 2010. As a result of differences in pricing, well locations, costs, development schedule, development expenditures and regulatory environment, among other things, the historical results of operations and performance of MVO should not be relied on as an indicator of how the trust will perform. The final prospectus relating to the initial public offering of MVO set forth a projection for the twelve months ended December 31, 2007 that totaled $3.02 per MVO trust unit. Actual distributions for each of the second, third and fourth quarters of 2007 |
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• | Strong oil fundamentals. Substantially all of the production from the Underlying Properties consists of crude oil. According to the US Energy Information Administration (“EIA”) projections, world oil prices are expected to rise gradually. These projections assume that global economic growth results in higher global oil demand, growth in supply from countries who are not members of the Organization of the Petroleum Exporting Countries (“OPEC”) slows in 2011, and members of OPEC continue to support world oil prices while commercial oil inventories in the Organization for Economic Cooperation and Development (“OECD”) countries begin to decline. |
• | Downside oil price protection. For the years 2011, 2012 and 2013, VOC Sponsor has entered into swap contracts, which we refer to as the “hedge contracts,” at weighted average prices ranging from $94.90 to $100.87 per barrel of oil that hedge approximately 66% of expected oil production for such years from the proved developed producing reserves attributable to the Underlying Properties in the summary reserve reports. The hedge contracts should help mitigate the impact of any crude oil price volatility on distributions made on the trust units during the term of the hedge contracts. Upon expiration in 2013, unitholder exposure to fluctuations in crude oil prices will increase significantly. Under the terms of the conveyance, VOC Sponsor will be prohibited from entering into hedging arrangements for the benefit of the trust and, under the terms of the trust agreement, the trustee is not empowered to enter into hedge contracts with trust proceeds. For more information on VOC 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 Interest and (2) the ownership by VOC Partners, LLC of approximately 35% of the trust units following the closing of this offering. |
• | Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the trust and cash distributions to unitholders. | |
• | An increase in the differential between the price realized by VOC Sponsor for oil or natural gas produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the proceeds to the trust and therefore the cash distributions by the trust and the value of trust units. |
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• | Estimates of future cash distributions to unitholders are based on assumptions that are inherently subjective. | |
• | Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the trust and the value of the trust units. | |
• | The processes of drilling and completing wells are high risk activities. | |
• | Risks associated with the production, gathering, transportation and sale of oil and natural gas could adversely affect cash distributions by the trust. | |
• | VOC Sponsor does not have any long term contracts related to the sale of production of oil and natural gas from the Underlying Properties and may be unable to find purchasers. | |
• | Neither the trust nor the trust’s unitholders will have the ability to influence VOC Sponsor or control the operations or development of the Underlying Properties. | |
• | Shortages or increases in costs of equipment, services and qualified personnel could result in a reduction in the amount of cash available for distribution to the trust unitholders. | |
• | The trust units may lose value as a result of title deficiencies with respect to the Underlying Properties. | |
• | VOC Sponsor may transfer all or a portion of the Underlying Properties at any time without trust unitholder consent, subject to specified limitations. | |
• | The reserves attributable to the Underlying Properties are depleting assets and production from those properties will diminish over time. | |
• | The amount of cash available for distribution by the trust will be reduced by the amount of any costs and expenses related to the Underlying Properties and other costs and expenses incurred by the trust. | |
• | The trustee may, under certain circumstances, sell the Net Profits Interest and dissolve the trust prior to the expected termination of the trust. As a result, trust unitholders may not recover their investment. | |
• | VOC Partners, LLC may sell trust units in the public or private markets, and such sales could have an adverse impact on the trading price of the trust units. | |
• | There has been no public market for the trust units and no independent appraisal of the value of the Net Profits Interest has been performed. | |
• | The trading price for the trust units may not reflect the value of the Net Profits Interest held by the trust. | |
• | Conflicts of interest could arise between VOC Sponsor and its affiliates, on the one hand, and the trust unitholders, on the other hand. | |
• | The trust is managed by a trustee who cannot be replaced except by a majority vote of the unitholders at a special meeting, which may make it difficult for unitholders to remove or replace the trustee. |
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• | Trust unitholders have limited ability to enforce provisions of the Net Profits Interest, and VOC Sponsor’s liability to the trust is limited. | |
• | Courts outside of Delaware may not recognize the limited liability of the trust unitholders provided under Delaware law. | |
• | The operations of the Underlying Properties are subject to environmental laws and regulations that may result in significant costs and liabilities, which could reduce the amount of cash available for distribution to trust unitholders. | |
• | The operations of the Underlying Properties are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting its operations or expose VOC Sponsor to significant liabilities, which could reduce the amount of cash available for distribution to trust unitholders. | |
• | Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that VOC Sponsor produces while the physical effects of climate change could disrupt VOC Sponsor’s production and cause VOC Sponsor to incur significant costs in preparing for or responding to those effects. | |
• | Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect VOC Sponsor’s services. | |
• | The bankruptcy of VOC Sponsor or any of the VOC Operators could impede the operation of the wells and the development of the proved undeveloped reserves. | |
• | The trust may be treated as an unsecured creditor with respect to the Net Profits Interest attributable to properties in Kansas in the event of the bankruptcy of VOC Sponsor if a court were to hold that the conveyance and recording of the Net Profits Interest was not a conveyance of a fully vested real property interest or an interest in hydrocarbons in place or to be produced. | |
• | Due to lack of geographic diversification of the Underlying Properties, adverse developments in Kansas or Texas could adversely impact the results of operations and cash flows of the Underlying Properties and reduce the amount of cash available for distributions to trust unitholders. | |
• | The receipt of payments by VOC Sponsor based on the hedge contracts depends upon the financial position of the hedge contract counterparties. A default by any of the hedge contract counterparties could reduce the amount of cash available for distribution to the trust unitholders. | |
• | VOC Sponsor’s performance of its obligations to the trust and the financial results of the trust may differ from the drilling and financial results of MVO. | |
• | The tax treatment of an investment in trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis. | |
• | The trust has not requested a ruling from the IRS regarding the tax treatment of ownership of the trust units. If the IRS were to determine (and be sustained in that determination) that the trust is not a “grantor trust” for federal income tax purposes, or |
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that the Net Profits Interest is not properly treated as a production payment (and thus would fail to qualify as a debt instrument) for federal income tax purposes, the trust unitholders may receive different and potentially less advantageous tax treatment from that described in this prospectus. |
Proved Reserves of the Underlying Properties | Undiscounted | |||||||||||||||||||
Oil | Natural Gas | Oil Equivalent | Future Net | PV-10 | ||||||||||||||||
(MBbls ) | (MMcf) | (MBoe) | Revenues | Value (3) | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Underlying Properties (total) (1) | 12,542 | 6,949 | 13,700 | $ | 569,829 | $ | 268,283 | |||||||||||||
Underlying Properties (attributable to the Net Profits Interest) (2) | 7,712 | 4,819 | 8,515 | $ | 379,296 | $ | 208,552 |
(1) | Reflects 100% of the proved reserves attributable to the Underlying Properties. | |
(2) | Reflects 80% of proved reserves attributable to the Underlying Properties expected to be produced during the term of the trust. | |
(3) | PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted using an annual discount rate of 10%, calculated without deducting future income taxes. Standardized measure of discounted net cash flows is calculated the same 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 thepre-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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Attributable to the Net Profits Interest
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Year Ended | ||||
December 31, 2010 | ||||
(In thousands) | ||||
(Unaudited) | ||||
Revenues: | ||||
Oil sales | $ | 60,187 | ||
Natural gas sales | 3,239 | |||
Hedge and other derivative activity | (707 | ) | ||
Total | 62,719 | |||
Direct operating expenses: | ||||
Lease operating expenses | 13,727 | |||
Production and property taxes | 4,137 | |||
Total | 17,864 | |||
Excess of revenues over direct operating expenses | $ | 44,855 | ||
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Year Ended | ||||||||
December 31, 2010 | ||||||||
(In thousands, | ||||||||
except per unit data) | ||||||||
(Unaudited) | ||||||||
Excess of revenues over direct operating expenses | $ | 44,855 | ||||||
Less development expenses | 10,492 | |||||||
Excess of revenues over direct operating expenses and development expenses | 34,363 | |||||||
Times Net Profits Interest over the term of the trust | 80 | % | ||||||
Income from Net Profits Interest | 27,490 | |||||||
Pro forma adjustments: | ||||||||
Less estimated trust general and administrative expenses | 900 | |||||||
Distributable income (1) | $ | 26,590 | ||||||
Distributable income per trust unit (2) | $ | 1.61 | ||||||
(1) | Per the terms of the Net Profits Interest, development costs are to be deducted when calculating the distributable income to the trust. |
(2) | Due to the timing of the payment of production proceeds to the trust, the production and costs attributable to the available distributions for the twelve months ended December 31, 2010 would have been for the eleven months ended November 30, 2010, if the pro forma available cash for distribution were calculated based on a modified cash basis. As a result, the pro forma distributable income per trust unit for the twelve months ended December 31, 2010 would have been $1.43. |
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Year Ended December 31, | ||||||||||||
Underlying Properties (1) | 2008 | 2009 | 2010 | |||||||||
(Unaudited) | ||||||||||||
Operating data: | ||||||||||||
Sales volumes: | ||||||||||||
Oil (MBbls) | 704 | 732 | 817 | |||||||||
Natural gas (MMcf) | 750 | 693 | 679 | |||||||||
Total sales (MBoe) | 829 | 847 | 930 | |||||||||
Average sales prices: | ||||||||||||
Oil (per Bbl) | $ | 93.67 | $ | 55.16 | $ | 73.71 | ||||||
Natural gas (per Mcf) | $ | 7.46 | $ | 3.31 | $ | 4.77 | ||||||
Capital expenditures (in thousands): | ||||||||||||
Property acquisition | $ | 7,899 | $ | 4,134 | $ | 3,262 | ||||||
Well development | 2,499 | 2,407 | 7,230 | |||||||||
Total | $ | 10,398 | $ | 6,541 | $ | 10,492 | ||||||
(1) | The operating data below includes the effect of the Acquired Underlying Properties for all periods presented. |
Year Ended December 31, | ||||||||||||
Predecessor Underlying Properties | 2008 | 2009 | 2010 | |||||||||
(Unaudited) | ||||||||||||
Operating data: | ||||||||||||
Sales volumes: | ||||||||||||
Oil (MBbls) | 389 | 407 | 495 | |||||||||
Natural gas (MMcf) | 426 | 415 | 447 | |||||||||
Total (MBoe) | 460 | 477 | 569 | |||||||||
Average sales prices: | ||||||||||||
Oil (per Bbl) | $ | 94.11 | $ | 55.86 | $ | 74.59 | ||||||
Natural gas (per Mcf) | $ | 7.86 | $ | 3.64 | $ | 5.36 | ||||||
Capital expenditures (in thousands): | ||||||||||||
Property acquisition | $ | 6,715 | $ | 2,369 | $ | 2,606 | ||||||
Well development | 1,063 | 1,955 | 6,766 | |||||||||
Total | $ | 7,778 | $ | 4,324 | $ | 9,372 | ||||||
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Year Ended December 31, | ||||||||||||
Acquired Underlying Properties | 2008 | 2009 | 2010 | |||||||||
(Unaudited) | ||||||||||||
Operating data: | ||||||||||||
Sales volumes: | ||||||||||||
Oil (MBbls) | 315 | 324 | 322 | |||||||||
Natural gas (MMcf) | 324 | 278 | 232 | |||||||||
Total sales (MBoe) | 369 | 371 | 360 | |||||||||
Average sales prices: | ||||||||||||
Oil (per Bbl) | $ | 93.12 | $ | 54.27 | $ | 72.35 | ||||||
Natural gas (per Mcf) | $ | 6.94 | $ | 2.81 | $ | 3.63 | ||||||
Capital expenditures (in thousands): | ||||||||||||
Property acquisition | $ | 1,184 | $ | 1,765 | $ | 655 | ||||||
Well development | 1,436 | 452 | 464 | |||||||||
Total | $ | 2,620 | $ | 2,217 | $ | 1,119 | ||||||
Predecessor Pro Forma | Predecessor Pro Forma As | |||||||||||
for the Acquisition | Adjusted for the Offering | |||||||||||
of the Acquired | (Including the conveyance | |||||||||||
Predecessor | Underlying Properties | of the Net Profits Interest) | ||||||||||
Year Ended | Year Ended | Year Ended | ||||||||||
December 31, | December 31, | December 31, | ||||||||||
2010 | 2010 | 2010 | ||||||||||
(In thousands) | ||||||||||||
(Unaudited) | (Unaudited) | |||||||||||
Revenue | $ | 38,635 | $ | 62,750 | $ | 21,998 | ||||||
Net earnings | $ | 20,911 | $ | 30,624 | $ | 14,020 | ||||||
Total assets (at year end) | $ | 109,038 | $ | 202,171 | $ | 96,358 | ||||||
Long-term liabilities, excluding current maturities (at year end) | $ | 26,241 | $ | 27,805 | $ | 99,392 | ||||||
Partners’ capital/common control owners’ equity (deficit) | $ | 70,936 | $ | 159,559 | $ | (26,746 | ) |
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Projection for Twelve Months | ||||
Projected Cash Distributions | Ending December 31, 2011 (1) | |||
(Dollars in thousands, except | ||||
per Bbl, Mcf, MMBtu and | ||||
per unit | ||||
amounts) | ||||
Underlying Properties sales volumes: | ||||
Oil (MBbls) | 716.5 | |||
Natural gas (MMcf) | 506.3 | |||
Total sales (MBoe) | 800.9 | |||
NYMEX futures price (2): | ||||
Oil (per Bbl) | $ | 102.07 | ||
Natural gas (per MMBtu) | $ | 4.07 | ||
Assumed realized sales price (3): | ||||
Oil (per Bbl) | $ | 96.42 | ||
Natural gas (per Mcf) | $ | 4.84 | ||
Calculation of net proceeds: | ||||
Gross proceeds: | ||||
Oil sales | $ | 69,092 | ||
Natural gas sales | 2,452 | |||
Total | $ | 71,544 | ||
Costs: | ||||
Production and development costs: | ||||
Lease operating expenses | $ | 11,239 | ||
Production and property taxes | 4,409 | |||
Development expenses | 8,171 | |||
Total | $ | 23,819 | ||
Settlement of hedge contracts (payment received) (4) | $ | 1,562 | ||
Net proceeds | $ | 46,163 | ||
Percentage allocable to Net Profits Interest | 80 | % | ||
Net proceeds to trust from Net Profits Interest | $ | 36,930 | ||
Trust general and administrative expenses (5) | 900 | |||
Cash reserve | 1,000 | |||
Cash available for distribution by the trust | $ | 35,030 | ||
Cash distribution per trust unit | $ | 2.12 | ||
(1) | Only includes proceeds attributable from production from January 1, 2011 through November 30, 2011 as the trust will not receive a cash payment for December 2010 in January 2011, and the payment for December 2011 production will be received in 2012. |
(2) | The assumed oil and natural gas prices utilized for purposes of preparing the projections are based on spot prices for January, February and March 2011 and NYMEX futures pricing for April through November 2011 as reported on March 10, 2011. For a description of the effect of lower NYMEX prices on projected cash distributions, please read “Projected cash distributions— Projected cash distributions for the year ending December 31, 2011 — Sensitivity of projected cash distributions to oil and natural gas production and prices.” |
(3) | Sales price net of forecasted gravity, quality, transportation, and marketing costs. For more information about the estimates and hypothetical assumptions made in preparing the table above, see “Projected cash distributions — |
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Projected cash distributions— Projected cash distributions for the twelve months ending December 31, 2011 — Significant assumptions used to prepare the projected cash distributions.” | ||
(4) | Costs will be reduced by hedge payments received by VOC Sponsor under the hedge contracts. If the hedge payments received by VOC Sponsor under the hedge contracts exceed costs during a quarterly period, the ability to use such excess amounts to offset costs will be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period when the current and deferred hedge payments are less than such costs. | |
(5) | Total general and administrative expenses of the trust on an annualized basis for 2011 are expected to be $900,000, which includes an annual administrative fee to VOC Sponsor in the amount of $75,000 in 2011, which fee will increase by 4% annually beginning in January 2012, the annual fee to the trustees, accounting fees, engineering fees, printing costs and other expenses properly chargeable to the trust. |
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Trust units offered by VOC Sponsor | 10,785,000 trust units, or 12,402,750 trust units if the underwriters exercise their option to purchase additional trust units in full | |
Trust units owned by VOC Partners, LLC after the offering | 5,755,000 trust units, or 4,137,250 trust units if the underwriters exercise their option to purchase additional trust units in full | |
Trust units outstanding after the offering | 16,540,000 trust units |
Use of proceeds | VOC Sponsor is offering all of the trust units to be sold in this offering including, the trust units to be sold upon any exercise of the underwriters’ over-allotment option. The estimated net proceeds of this offering to be received by VOC Sponsor will be approximately $198.3 million, after deducting underwriting discounts and commissions, structuring fees and expenses, and $228.4 million if the underwriters exercise their option to purchase additional trust units in full. VOC Sponsor intends to use the net proceeds from this offering, including any proceeds from the exercise of the underwriters’ option to purchase additional trust units and the sale of the trust units to VOC Partners, LLC to repay approximately $24.0 million of outstanding borrowings under its credit facility, to repurchase certain outstanding equity interests in VOC Sponsor for approximately $63.4 million and to make cash distributions to its remaining limited partners. See “Use of proceeds.” |
Proposed NYSE symbol | “VOC” | |
Quarterly cash distributions | It is expected that quarterly cash distributions during the term of the trust, other than the first quarterly cash distribution, will be made by the trustee on or about the 45th day following the end of each quarter to the trust unitholders of record on the 30th day following the end of each quarter (or the next succeeding business day). The first distribution from the trust to the trust unitholders will be made on or about August 15, 2011 to trust unitholders owning trust units on or about August 1, 2011. The 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 |
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natural gas produced from the Underlying Properties, the prices received for oil and natural gas production and other factors. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent, in effect, a return of your original investment. Oil and natural gas production from proved reserves attributable to the Underlying Properties is expected to decline over the term of the trust. See “Risk factors.” | ||
Termination of the trust | The Net Profits Interest will terminate on the later to occur of (1) December 31, 2030, or (2) the time from and after January 1, 2011 when 10.6 MMBoe have been produced from the Underlying Properties and sold (which amount is the equivalent of 8.5 MMBoe in respect of the 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, such as the recent geopolitical turmoil in North Africa and the Middle East; | |
• | anticipated future prices of oil and natural gas and other commodities; | |
• | weather conditions and seasonal trends; | |
• | technological advances affecting energy consumption and energy supply; | |
• | U.S. and worldwide economic conditions; | |
• | the price and availability of alternative fuels; | |
• | the proximity, capacity, cost and availability of gathering and transportation facilities; | |
• | 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 |
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decisions include reducing development expenditures on these properties, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the trust in the future. |
• | 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 limited circumstances, to cause the trust to release all or a portion of the Net Profits Interest in connection with a sale of a portion of the Underlying Properties to which such Net Profits Interest relates. See “The Underlying Properties — Sale and abandonment of Underlying Properties.” |
• | 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 year ended December 31, 2010, VOC Sponsor sold approximately 32% of the oil produced from the Underlying Properties to MV Purchasing, LLC. |
• | 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, including changes as a result of political conditions or hostilities in oil and natural gas producing regions such as the recent geopolitical turmoil in North Africa and the Middle East; | |
• | 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
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 | Year Ended | Year Ended | ||||||||||||||||||
Year Ended December 31, | December 31, | December 31, | ||||||||||||||||||
2008 | 2009 | 2010 | 2010 | 2010 | ||||||||||||||||
(In thousands) | (Unaudited) | (Unaudited) | ||||||||||||||||||
Revenue | $ | 32,198 | $ | 25,750 | $ | 38,635 | $ | 62,750 | $ | 21,998 | ||||||||||
Net earnings | $ | 12,839 | $ | 10,861 | $ | 20,911 | $ | 30,624 | $ | 14,020 | ||||||||||
Total assets (at year end) | $ | 108,830 | $ | 101,280 | $ | 109,038 | $ | 202,171 | $ | 96,358 | ||||||||||
Long-term liabilities, excluding current maturities (at year end) | $ | 37,018 | $ | 28,315 | $ | 26,241 | $ | 27,805 | $ | 99,392 |
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Year Ended December 31, | ||||||||||||||||
Historical Results | 2008 | 2009 | 2010 | |||||||||||||
Production (MBoe) | 829 | 847 | 930 | |||||||||||||
Net proved reserves (MBoe) (at year end) | 10,821 | 13,007 | 13,700 | |||||||||||||
Net proved developed reserves (MBoe) (at year end) | 10,046 | 11,536 | 11,945 |
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 | 35 | Vice President and Chief Financial Officer | ||||
Alan Howarter | 55 | 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) | 31.8 | % | ||
J. Michael Vess (2) | 27.9 | % | ||
Will Price (3) | 11.8 | % | ||
C. J. Lett (4) | 10.7 | % | ||
William R. Horigan (5) | 7.2 | % | ||
Brian Gaudreau (6) | 2.6 | % | ||
Barry Hill (7) | * | |||
Alan Howarter (8) | * | |||
Executive Management as a Group (2)(5)(6)(7)(8) | 38.2 | % |
* | 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 13.7% interest in VOC Sponsor. The address of Mr. Davis is 7 SW 26th Ave., Great Bend, Kansas 67530. |
(2) | Includes 13.6% of Mr. Vess’ interests in VOC Sponsor indirectly beneficially owned through family trusts. Mr. Vess also has dispositive power over an additional 14.3% of VOC Sponsor. The address of Mr. Vess is 1700 Waterfront Parkway, Building 500, Wichita, Kansas 67206. |
(3) | Includes interests indirectly beneficially owned through several entities. The address of Mr. Price is 1700 Waterfront Parkway, Building 500, Wichita, KS 67206. |
(4) | Includes interests indirectly beneficially owned through several entities. The address of Mr. Lett is 9320 E. Central, Wichita, Kansas 67206. |
(5) | Includes interests indirectly beneficially owned through several entities. The address of Mr. Horigan is 1700 Waterfront Parkway, Building 500, Wichita, Kansas 67206. |
(6) | Includes interests indirectly beneficially owned through several entities. The address of Mr. Gaudreau is 1700 Waterfront Parkway, Building 500, Wichita, Kansas 67206. |
(7) | Mr. Hill beneficially owns less than 1% of VOC Brazos through his beneficial ownership of a 0.5% membership interest in VOC Acquisition Partners, LLC, an indirect subsidiary of VOC Sponsor. The address of Mr. Hill is 1700 Waterfront Parkway, Building 500, Wichita, Kansas 67206. |
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(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, and his beneficial ownership of a 0.5% membership interest in VOC Acquisition Partners, LLC, an indirect subsidiary of VOC Sponsor. The address of Mr. Howarter is 1700 Waterfront Parkway, Building 500, Wichita, Kansas 67206. |
Class of | Percentage | |||
Name of Beneficial Owner | Securities | of Ownership (1) | ||
VOC Partners, LLC (2) | Trust Units | 34.8% (3) |
(1) | Does not include any trust units that may be purchased in the directed unit program. Please see “Underwriting — Directed Unit Program” on page 120. |
(2) | The parties who beneficially own VOC Sponsor as set forth in the table above own VOC Partners, LLC in the same proportion as they own VOC Sponsor. However, such ownership percentage described in the table above does not take into account Class B Units of VOC Partners, LLC. Such Class B Units are issuable to VOC Management Group at the discretion of VOC Partners, LLC, and these units may equal up to 1.5% of the outstanding units of VOC Partners, LLC. As of April 13, 2011, VOC Partners, LLC has not issued any Class B units and has no current plans to do so. |
(3) | VOC Partners, LLC has entered into an agreement to acquire from VOC Sponsor all trust units not sold by VOC Sponsor in this offering at the initial offering price. The closing of such transaction will occur forty-five days following the closing of this offering. |
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Year Ended December 31, | ||||||||||||
2008 | 2009 | 2010 | ||||||||||
(In thousands) | ||||||||||||
Lease operating expenses incurred: | ||||||||||||
Vess Oil Corporation | $ | 10,314 | $ | 9,334 | $ | 10,053 | ||||||
LD Drilling | 768 | 685 | 605 | |||||||||
Davis Petroleum | 652 | 704 | 756 | |||||||||
Total | $ | 11,734 | $ | 10,723 | $ | 11,414 | ||||||
Overhead costs included in lease operating expenses incurred: | ||||||||||||
Vess Oil Corporation | $ | 1,098 | $ | 1,232 | $ | 1,314 | ||||||
LD Drilling | 91 | 97 | 100 | |||||||||
Davis Petroleum | 64 | 72 | 72 | |||||||||
Total | $ | 1,253 | $ | 1,401 | $ | 1,486 | ||||||
Capitalized lease equipment and producing leasehold costs incurred: | ||||||||||||
Vess Oil Corporation | $ | 1,402 | $ | 1,937 | $ | 3,246 | ||||||
LD Drilling | 304 | 154 | (8 | ) | ||||||||
Davis Petroleum | 220 | 3 | 14 | |||||||||
Total | $ | 1,926 | $ | 2,094 | $ | 3,252 | ||||||
Payment of well development costs: | ||||||||||||
Vess Oil Corporation | $ | 1,709 | $ | 2,269 | $ | 7,149 | ||||||
LD Drilling | 509 | 137 | — | |||||||||
Davis Petroleum | 168 | — | 81 | |||||||||
Total | $ | 2,386 | $ | 2,406 | $ | 7,230 | ||||||
Payment of management fees: | ||||||||||||
Vess Oil Corporation | $ | 447 | $ | 447 | $ | 447 | ||||||
LD Drilling | — | — | — | |||||||||
Davis Petroleum | — | — | — | |||||||||
Total | $ | 447 | $ | 447 | $ | 447 | ||||||
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Year Ended December 31, | ||||||||||||
2008 | 2009 | 2010 | ||||||||||
Sales | $ | 1,207,358 | $ | 13,482,074 | $ | 19,125,260 | ||||||
Trade Receivables | $ | 319,109 | $ | 1,359,842 | $ | 1,760,141 |
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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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Quarter Ended | Year Ended | |||||||||||||||||||
March 31, | June 30, | September 30, | December 31, | December 31, | ||||||||||||||||
2010 | 2010 | 2010 | 2010 | 2010 | ||||||||||||||||
(Dollars in thousands, except per Bbl, Mcf, MMBtu and per unit amounts) | ||||||||||||||||||||
Underlying Properties sales volumes: | ||||||||||||||||||||
Oil (MBbls) | 202 | 212 | 206 | 197 | 817 | |||||||||||||||
Natural gas (MMcf) | 178 | 173 | 170 | 158 | 679 | |||||||||||||||
Total sales (MBoe) | 232 | 241 | 234 | 223 | 930 | |||||||||||||||
Average realized sales price(1): | ||||||||||||||||||||
Oil (per Bbl) | $ | 72.82 | $ | 72.75 | $ | 70.67 | $ | 78.65 | $ | 73.67 | ||||||||||
Natural gas (per Mcf) | $ | 5.03 | $ | 4.76 | $ | 4.79 | $ | 4.46 | $ | 4.77 | ||||||||||
Calculation of net proceeds: | ||||||||||||||||||||
Gross proceeds: | ||||||||||||||||||||
Oil sales | $ | 14,710 | $ | 15,423 | $ | 14,559 | $ | 15,495 | $ | 60,187 | ||||||||||
Natural gas sales | 896 | 824 | 815 | 704 | 3,239 | |||||||||||||||
Total | $ | 15,606 | $ | 16,247 | $ | 15,374 | $ | 16,199 | $ | 63,426 | ||||||||||
Costs: | ||||||||||||||||||||
Production and development costs: | ||||||||||||||||||||
Lease operating expenses | $ | 3,217 | $ | 3,119 | $ | 3,612 | $ | 3,778 | $ | 13,726 | ||||||||||
Production and property taxes | 1,015 | 994 | 1,037 | 1,091 | 4,137 | |||||||||||||||
Development expenses | 2,788 | 2,671 | 3,285 | 1,748 | 10,492 | |||||||||||||||
Total | $ | 7,020 | $ | 6,784 | $ | 7,934 | $ | 6,617 | $ | 28,355 | ||||||||||
Settlement of hedge contracts (payment received)(2) | 252 | 107 | (208 | ) | 557 | 708 | ||||||||||||||
Net proceeds | $ | 8,334 | $ | 9,356 | $ | 7,648 | $ | 9,025 | $ | 34,363 | ||||||||||
Percentage allocable to Net Profits Interest | 80% | 80% | 80% | 80% | 80% | |||||||||||||||
Net proceeds to trust from Net Profits Interest | $ | 6,667 | $ | 7,485 | $ | 6,118 | $ | 7,220 | $ | 27,490 | ||||||||||
Trust general and administrative expenses | 225 | 225 | 225 | 225 | 900 | |||||||||||||||
Cash available for distribution by the trust | $ | 6,442 | $ | 7,260 | $ | 5,893 | $ | 6,995 | $ | 26,590 | ||||||||||
Cash distribution per trust unit | $ | 0.39 | $ | 0.44 | $ | 0.36 | $ | 0.42 | $ | 1.61 | (3) | |||||||||
(1) | Sales price net of forecasted gravity, quality, transportation, and marketing costs. | |
(2) | Costs are reduced by hedge payments received by VOC Sponsor under the hedge contracts in existence during the year ended December 31, 2010. If the hedge payments received by VOC Sponsor under the hedge contracts exceed costs during a quarterly period, the ability to use such excess amounts to offset costs will be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period when the hedge payments are less than such costs. During the year ended December 31, 2010, KEP was not a party to any hedge contracts. |
(3) | Due to the timing of the payment of production proceeds to the trust, the production and costs attributable to the available distributions for the twelve months ended December 31, 2010 would have been for the eleven months ended November 30, 2010, if the pro forma available cash for distribution were calculated based on a modified cash basis. As a result, the pro forma distributable income per trust unit for the twelve months ended December 31, 2010 would have been $1.43. |
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DECEMBER 31, 2011
• | preliminary estimates of realized oil and natural gas production for January and February 2011 and oil and natural gas production estimates for March through November 2011 contained in the reserve reports; |
• | estimated production and development costs for the year ending December 31, 2011, contained in the reserve reports; and | |
• | projected payments made or received pursuant to the hedge contracts, if any, for the year ending December 31, 2011 assuming the hypothetical prices used in the following table and the hedge contracts to be entered into by VOC Sponsor as of the closing of this offering related to production for 2011. |
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Six | Projection for | |||||||||||||||||||
Months | Twelve Months | |||||||||||||||||||
Ending | Three Months Ending | Ending | ||||||||||||||||||
June 30, | September 30, | December 31, | December 31, | |||||||||||||||||
2011 (1) | 2011 (2) | 2011 (3) | 2011 (4) | |||||||||||||||||
(Dollars in thousands, except per Bbl, | ||||||||||||||||||||
Mcf, MMBtu and per unit amounts) | ||||||||||||||||||||
Underlying Properties sales volumes: | ||||||||||||||||||||
Oil (MBbls) | 307.2 | 198.5 | 210.9 | 716.5 | ||||||||||||||||
Natural gas (MMcf) | 207.5 | 146.8 | 152.0 | 506.3 | ||||||||||||||||
Total sales (MBoe) | 341.8 | 222.9 | 236.3 | 800.9 | ||||||||||||||||
NYMEX future prices (5): | ||||||||||||||||||||
Oil (per Bbl) | $ | 97.87 | $ | 104.90 | $ | 105.54 | $ | 102.07 | ||||||||||||
Natural gas (per MMBtu) | $ | 4.01 | $ | 4.02 | $ | 4.19 | $ | 4.07 | ||||||||||||
Assumed realized sales price (6): | ||||||||||||||||||||
Oil (per Bbl) | $ | 92.03 | $ | 99.35 | $ | 100.06 | $ | 96.42 | ||||||||||||
Natural gas (per Mcf) | $ | 4.55 | $ | 4.89 | $ | 5.20 | $ | 4.84 | ||||||||||||
Calculation of net proceeds: | ||||||||||||||||||||
Gross proceeds: | ||||||||||||||||||||
Oil sales | $ | 28,270 | $ | 19,717 | $ | 21,104 | $ | 69,092 | ||||||||||||
Natural gas sales | 945 | 717 | 790 | 2,452 | ||||||||||||||||
Total | $ | 29,215 | $ | 20,434 | $ | 21,894 | $ | 71,544 | ||||||||||||
Costs: | ||||||||||||||||||||
Production and development costs: | ||||||||||||||||||||
Lease operating expenses | $ | 5,159 | $ | 3,026 | $ | 3,054 | $ | 11,239 | ||||||||||||
Production and property taxes | 1,800 | 1,257 | 1,352 | 4,409 | ||||||||||||||||
Development expenses | 2,594 | 2,905 | 2,673 | 8,171 | ||||||||||||||||
Total | $ | 9,553 | $ | 7,188 | $ | 7,079 | $ | 23,819 | ||||||||||||
Settlement of hedge contracts (payment received) (7) | $ | 267 | $ | 618 | $ | 677 | $ | 1,562 | ||||||||||||
Net proceeds | $ | 19,395 | $ | 12,628 | $ | 14,138 | $ | 46,163 | ||||||||||||
Percentage allocable to Net Profits Interest | 80% | 80% | 80% | 80% | ||||||||||||||||
Net proceeds to trust from Net Profits Interest | $ | 15,516 | $ | 10,103 | $ | 11,311 | $ | 36,930 | ||||||||||||
Trust general and administrative expenses (8) | 450 | 225 | 225 | 900 | ||||||||||||||||
Cash reserve | 1,000 | 1,000 | ||||||||||||||||||
Cash available for distribution by the trust | $ | 14,066 | $ | 9,878 | $ | 11,086 | $ | 35,030 | ||||||||||||
Cash distribution per trust unit | $ | 0.85 | $ | 0.60 | $ | 0.67 | $ | 2.12 | ||||||||||||
(1) | Includes proceeds and costs attributable to production from January 1, 2011 through May 31, 2011. | |
(2) | Includes proceeds and costs attributable to production from June 1, 2011 through August 31, 2011. | |
(3) | Includes proceeds and costs attributable to production from September 1, 2011 through November 30, 2011. | |
(4) | Includes proceeds and costs attributable to production from January 1, 2011 through November 30, 2011. |
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(5) | The assumed oil and natural gas prices utilized for purposes of preparing the projections are based on spot prices for January, February and March 2011 and NYMEX futures pricing for April through November 2011 as reported on March 10, 2011. For a description of the effect of lower NYMEX prices on projected cash distributions, please read “— Sensitivity of projected cash distributions to oil and natural gas production and prices.” |
(6) | Assumed realized sales price net of forecasted gravity, quality, transportation, and marketing costs. For more information about the estimates and hypothetical assumptions made in preparing the table above, see “— Significant assumptions used to prepare the projected cash distributions.” | |
(7) | Costs will be reduced by hedge payments received by VOC Sponsor under the hedge contracts. If the hedge payments received by VOC Sponsor under the hedge contracts exceed costs during a quarterly period, the ability to use such excess amounts to offset costs will be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period when the hedge payments are less than such costs. | |
(8) | Total general and administrative expenses of the trust on an annualized basis for 2011 are expected to be $900,000, which includes an annual administrative fee to VOC Sponsor in the amount of $75,000 in 2011, which fee will increase by 4% annually beginning in January 2012, the annual fee to the trustees, accounting fees, engineering fees, printing costs and other expenses properly chargeable to the trust. |
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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 the first 11 months of 2011 in the reserve report. |
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Year Ended December 31, | ||||||||||||
2008 | 2009 | 2010 | ||||||||||
(In thousands) | ||||||||||||
Predecessor Underlying Properties: | ||||||||||||
Revenues: | ||||||||||||
Oil sales | $ | 36,632 | $ | 22,758 | $ | 36,914 | ||||||
Natural gas sales | 3,350 | 1,511 | 2,396 | |||||||||
Hedge and other derivative income (expense) | (7,784 | ) | 1,477 | (707 | ) | |||||||
Total | $ | 32,198 | $ | 25,746 | $ | 38,603 | ||||||
Bad debt expense (recovery) | $ | 1,727 | $ | (719 | ) | — | ||||||
Direct operating expenses: | ||||||||||||
Lease operating expenses | 7,667 | 6,788 | 7,325 | |||||||||
Production and property taxes | 2,532 | 1,646 | 2,720 | |||||||||
Total | 10,199 | 8,434 | 10,045 | |||||||||
Excess of revenues over direct operating expenses | $ | 20,272 | $ | 18,031 | $ | 28,558 | ||||||
Acquired Underlying Properties: | ||||||||||||
Revenues: | ||||||||||||
Oil sales | $ | 29,297 | $ | 17,602 | $ | 23,273 | ||||||
Natural gas sales | 2,248 | 781 | 842 | |||||||||
Total | $ | 31,545 | $ | 18,383 | $ | 24,115 | ||||||
Bad debt expense | $ | 2,166 | $ | — | $ | — | ||||||
Direct operating expenses: | ||||||||||||
Lease operating expenses | 6,046 | 5,969 | 6,402 | |||||||||
Production and property taxes | 1,614 | 1,170 | 1,417 | |||||||||
Total | 7,660 | 7,139 | 7,819 | |||||||||
Excess of revenues over direct operating expenses | $ | 21,719 | $ | 11,244 | $ | 16,296 | ||||||
Year Ended | ||||
December 31, | ||||
2010 | ||||
(In thousands) | ||||
Predecessor Pro Forma (unaudited) | ||||
Revenues: | ||||
Oil sales | $ | 60,187 | ||
Natural gas sales | 3,239 | |||
Hedge and other derivative income (expense) | (707 | ) | ||
Total | $ | 62,719 | ||
Direct operating expenses: | ||||
Lease operating expenses | $ | 13,727 | ||
Production and property taxes | 4,137 | |||
Total | 17,864 | |||
Excess of revenues over direct operating expenses | $ | 44,855 | ||
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Year Ended December 31, | ||||||||||||
Underlying Properties (1) | 2008 | 2009 | 2010 | |||||||||
(Unaudited) | ||||||||||||
Operating data: | ||||||||||||
Sales volumes: | ||||||||||||
Oil (MBbls) | 704 | 732 | 817 | |||||||||
Natural gas (MMcf) | 750 | 693 | 679 | |||||||||
Total sales (MBoe) | 829 | 847 | 930 | |||||||||
Average sales prices: | ||||||||||||
Oil (per Bbl) | $ | 93.67 | $ | 55.16 | $ | 73.71 | ||||||
Natural gas (per Mcf) | $ | 7.46 | $ | 3.31 | $ | 4.77 | ||||||
Capital expenditures (in thousands): | ||||||||||||
Property acquisition | $ | 7,899 | $ | 4,134 | $ | 3,262 | ||||||
Well development | 2,499 | 2,407 | 7,230 | |||||||||
Total | $ | 10,398 | $ | 6,541 | $ | 10,492 | ||||||
(1) | The operating data includes the effect of the Acquired Underlying Properties for all periods presented. |
Year Ended December 31, | ||||||||||||
Predecessor Underlying Properties | 2008 | 2009 | 2010 | |||||||||
(Unaudited) | ||||||||||||
Operating data: | ||||||||||||
Sales volumes: | ||||||||||||
Oil (MBbls) | 389 | 407 | 495 | |||||||||
Natural gas (MMcf) | 426 | 415 | 447 | |||||||||
Total (MBoe) | 460 | 477 | 569 | |||||||||
Average sales prices: | ||||||||||||
Oil (per Bbl) | $ | 94.11 | $ | 55.86 | $ | 74.59 | ||||||
Natural gas (per Mcf) | $ | 7.86 | $ | 3.64 | $ | 5.36 | ||||||
Capital expenditures (in thousands): | ||||||||||||
Property acquisition | $ | 6,715 | $ | 2,369 | $ | 2,606 | ||||||
Well development | 1,063 | 1,955 | 6,766 | |||||||||
Total | $ | 7,778 | $ | 4,324 | $ | 9,372 | ||||||
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Year Ended December 31, | ||||||||||||
Acquired Underlying Properties | 2008 | 2009 | 2010 | |||||||||
(Unaudited) | ||||||||||||
Operating data: | ||||||||||||
Sales volumes: | ||||||||||||
Oil (MBbls) | 315 | 324 | 322 | |||||||||
Natural gas (MMcf) | 324 | 278 | 232 | |||||||||
Total (MBoe) | 369 | 371 | 360 | |||||||||
Average sales prices: | ||||||||||||
Oil (per Bbl) | $ | 93.12 | $ | 54.27 | $ | 72.35 | ||||||
Natural gas (per Mcf) | $ | 6.94 | $ | 2.81 | $ | 3.63 | ||||||
Capital expenditures (in thousands): | ||||||||||||
Property acquisition | $ | 1,184 | $ | 1,765 | $ | 655 | ||||||
Well development | 1,436 | 452 | 464 | |||||||||
Total | $ | 2,620 | $ | 2,217 | $ | 1,119 | ||||||
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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 | 20,014 | $ | 96.77 | |||||||||
April 2011 | 43,407 | $ | 99.99 | |||||||||
May 2011 | 42,828 | $ | 99.98 | |||||||||
June 2011 | 42,285 | $ | 99.98 | |||||||||
July 2011 | 41,766 | $ | 99.97 | |||||||||
August 2011 | 41,271 | $ | 99.96 | |||||||||
September 2011 | 40,796 | $ | 99.95 | |||||||||
October 2011 | 40,337 | $ | 99.94 | |||||||||
November 2011 | 39,898 | $ | 99.94 | |||||||||
December 2011 | 39,476 | $ | 99.93 | |||||||||
January 2012 | 39,038 | $ | 100.84 | |||||||||
February 2012 | 38,631 | $ | 100.84 | |||||||||
March 2012 | 38,251 | $ | 100.85 | |||||||||
April 2012 | 37,882 | $ | 100.85 | |||||||||
May 2012 | 37,523 | $ | 100.85 | |||||||||
June 2012 | 37,176 | $ | 100.85 | |||||||||
July 2012 | 36,839 | $ | 100.86 | |||||||||
August 2012 | 36,513 | $ | 100.86 | |||||||||
September 2012 | 36,194 | $ | 100.86 | |||||||||
October 2012 | 35,883 | $ | 100.86 | |||||||||
November 2012 | 35,562 | $ | 100.87 | |||||||||
December 2012 | 35,268 | $ | 100.87 | |||||||||
January 2013 | 34,975 | $ | 99.01 | |||||||||
February 2013 | 34,686 | $ | 99.01 | |||||||||
March 2013 | 34,406 | $ | 99.01 | |||||||||
April 2013 | 34,166 | $ | 99.01 | |||||||||
May 2013 | 33,959 | $ | 99.01 | |||||||||
June 2013 | 33,727 | $ | 99.01 | |||||||||
July 2013 | 33,526 | $ | 99.01 | |||||||||
August 2013 | 33,317 | $ | 99.01 | |||||||||
September 2013 | 33,122 | $ | 99.01 | |||||||||
October 2013 | 32,929 | $ | 99.01 | |||||||||
November 2013 | 32,741 | $ | 99.01 | |||||||||
December 2013 | 32,554 | $ | 99.01 |
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Gross | Net | |||||||
(Acres) | ||||||||
Kansas | 76,217 | 45,326.1 | ||||||
Texas | 23,693 | 16,841.3 | ||||||
Total | 99,910 | 62,167.4 | ||||||
Operated Wells | Non-Operated Wells | Total | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Oil | 805 | 512.7 | 31 | 7.3 | 836 | 520.0 | ||||||||||||||||||
Natural gas | 31 | 21.1 | 14 | 4.6 | 45 | 25.7 | ||||||||||||||||||
Total | 836 | 533.8 | 45 | 11.9 | 881 | 545.7 | ||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||
2008 | 2009 | 2010 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Completed: | ||||||||||||||||||||||||
Oil wells | 13 | 8.3 | 6 | 4.6 | 7 | 5.3 | ||||||||||||||||||
Natural gas wells | — | — | — | — | — | — | ||||||||||||||||||
Non-productive | 4 | 2.4 | — | — | 2 | 1.3 | ||||||||||||||||||
Total | 17 | 10.7 | 6 | 4.6 | 9 | 6.6 | ||||||||||||||||||
Year Ended December 31, | ||||||||||||
2008 | 2009 | 2010 | ||||||||||
Sales prices: | ||||||||||||
Oil (per Bbl) | $ | 93.67 | $ | 55.16 | $ | 73.71 | ||||||
Natural gas (per Mcf) | $ | 7.46 | $ | 3.31 | $ | 4.77 | ||||||
Lease operating expense (per Boe) | $ | 16.54 | $ | 15.06 | $ | 14.76 | ||||||
Production and property taxes (per Boe) | $ | 5.00 | $ | 3.32 | $ | 4.45 |
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Year Ended | ||||||||||||||||||||||||||||
Proved Reserves (1) | December 31, | |||||||||||||||||||||||||||
% of | 2010 Average | |||||||||||||||||||||||||||
Natural | % of | Pre-Tax | Pre-Tax | Net | ||||||||||||||||||||||||
Oil | Gas | Total | Total | PV-10% | PV-10% | Production | ||||||||||||||||||||||
Operating Area | (MBbls) | (MMcf) | (MBoe) | Reserves | Value | Value | (Boe per day) | |||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Kansas (188 Fields) | ||||||||||||||||||||||||||||
Fairport | 889 | 0 | 889 | 6.5 | % | $ | 17,334 | 6.5 | % | 123 | ||||||||||||||||||
Marcotte | 474 | 0 | 474 | 3.5 | % | 10,638 | 4.0 | % | 94 | |||||||||||||||||||
Chase-Silica | 434 | 0 | 434 | 3.2 | % | 8,075 | 3.0 | % | 85 | |||||||||||||||||||
Bindley | 365 | 0 | 365 | 2.7 | % | 7,097 | 2.6 | % | 53 | |||||||||||||||||||
Moore-Johnson | 351 | 0 | 351 | 2.6 | % | 6,853 | 2.6 | % | 52 | |||||||||||||||||||
Griston SW | 121 | 0 | 121 | 0.9 | % | 4,164 | 1.6 | % | 36 | |||||||||||||||||||
Wesley | 169 | 0 | 169 | 1.2 | % | 3,979 | 1.5 | % | 34 | |||||||||||||||||||
Mueller | 175 | 0 | 175 | 1.3 | % | 3,947 | 1.5 | % | 32 | |||||||||||||||||||
Codell | 145 | 0 | 145 | 1.1 | % | 3,757 | 1.4 | % | 65 | |||||||||||||||||||
Adell Northwest | 104 | 0 | 104 | 0.8 | % | 2,211 | 0.8 | % | 19 | |||||||||||||||||||
Dopita | 110 | 0 | 110 | 0.8 | % | 2,157 | 0.8 | % | 19 | |||||||||||||||||||
Yaege | 110 | 0 | 110 | 0.8 | % | 2,153 | 0.8 | % | 19 | |||||||||||||||||||
Spivey-Grabs-Basil | 59 | 891 | 207 | 1.5 | % | 2,075 | 0.8 | % | 39 | |||||||||||||||||||
Other | 3,029 | 2,660 | 3,473 | 25.3 | % | 60,333 | 22.5 | % | 863 | |||||||||||||||||||
Kansas Total | 6,535 | 3,550 | 7,127 | 52.0 | % | $ | 134,772 | 50.2 | % | 1,536 | ||||||||||||||||||
Texas (3 Fields) | ||||||||||||||||||||||||||||
Kurten | 4,054 | 3,398 | 4,620 | 33.7 | % | 91,880 | 34.2 | % | 695 | |||||||||||||||||||
Sand Flat | 927 | 0 | 927 | 6.8 | % | 23,067 | 8.6 | % | 169 | |||||||||||||||||||
Hitts Lake North | 1,026 | 1 | 1,026 | 7.5 | % | 18,564 | 6.9 | % | 147 | |||||||||||||||||||
Texas Total | 6,007 | 3,399 | 6,573 | 48.0 | % | $ | 133,511 | 49.8 | % | 1,011 | ||||||||||||||||||
Total | 12,542 | 6,949 | 13,700 | 100 | % | $ | 268,283 | 100.0 | % | 2,547 | ||||||||||||||||||
(1) | In accordance with the rules and regulations promulgated by the SEC, the proved reserves presented above were determined using the twelve month unweighted arithmetic average of thefirst-day-of-the-month price for the period from January 1, 2010 through December 1, 2010, without giving effect to any hedge transactions, and were held constant for the life of the properties. This yielded a price for oil of $79.43 per barrel and a price for natural gas of $4.37 per MMBtu. | |
(2) | PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted using an annual discount rate of 10%, calculated without deducting future income taxes. Standardized measure of discounted net cash flows is calculated the same 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. |
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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 | |||||||||||||
Fairport | 59/5 | Vess Oil, Counts Kellis | Russell | Arbuckle, LKC, Dodge, Reagan, Wabaunsee | 1,320/963.5 | 73.6 | % | 63.3 | % | |||||||||||
Marcotte | 25/0 | Vess Oil | Rooks | Arbuckle, LKC | 1,760/1,676.7 | 95.4 | % | 79.5 | % | |||||||||||
Chase-Silica | 48/0 | Vess Oil, Davis Petroleum Inc, L D Drilling | Barton, Rice, Stafford | Arbuckle, LKC | 2,760/2,038.1 | 82.0 | % | 67.0 | % | |||||||||||
Bindley | 18/0 | Vess Oil | Hodgeman | Mississippian | 1,360/1,166.0 | 85.5 | % | 73.8 | % | |||||||||||
Moore-Johnson | 10/0 | Vess Oil | Greeley | Morrow | 1,621/1,292.3 | 79.7 | % | 64.6 | % | |||||||||||
Griston SW | 7/0 | Vess Oil | Scott | LKC, Mississippian | 160/82.7 | 50.3 | % | 40.2 | % | |||||||||||
Wesley | 5/0 | Davis Petroleum Inc, L D Drilling | Ness | Mississippian | 480/444.5 | 92.2 | % | 80.1 | % | |||||||||||
Mueller | 14/0 | Vess Oil, L D Drilling | Stafford | Arbuckle, Conglomerate, LKC | 640/497.0 | 85.2 | % | 69.4 | % | |||||||||||
Codell | 3/0 | Vess Oil | Rooks | Arbuckle, LKC | 106/100.6 | 95.0 | % | 76.5 | % | |||||||||||
Adell Northwest | 7/0 | Vess Oil | Decatur | LKC | 800/797.6 | 99.7 | % | 86.7 | % | |||||||||||
Dopita | 9/0 | Vess Oil | Rooks | Arbuckle, Toronto | 380/357.1 | 93.5 | % | 81.8 | % | |||||||||||
Yaege | 26/0 | Vess Oil | Riley | Hunton | 2,098/1,094.1 | 52.2 | % | 45.6 | % | |||||||||||
Spivey-Grabs-Basil | 10/1 | Vess Oil | Harper, Kingman | Mississippian | 1,470/1,123.7 | 86.6 | % | 72.5 | % |
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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 | |||||||||||||
Kurten | 108/7 | Vess Oil, CML, Ogden Resources | Brazos | Austin Chalk, Woodbine Sand, Buda- Georgetown | 20,908/15,280.4 | 72.7 | % | 58.6 | % | |||||||||||
Sand Flat | 18/1 | Vess Oil, Carrizo | Smith | Paluxy, Rodessa | 2,579/1,418.0 | 54.9 | % | 48.1 | % | |||||||||||
Hitts Lake North | 5/0 | Vess Oil | Smith | Paluxy | 206/142.9 | 59.6 | % | 52.5 | % |
• | 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 through December 31, 2015 of approximately $3.2 million, of which VOC Sponsor contemplates spending approximately $2.5 million to drill and complete 13 vertical wells. The remaining approximate $0.7 million is expected to be used for recompletions and workovers of 12 wells. | |
• | Texas. VOC 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 through December 31, 2015 to be approximately $24.0 million. Of this total, VOC Sponsor |
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contemplates spending approximately $22.5 million to drill and complete 11 horizontal wells in the Woodbine C sand. The remaining approximate $1.5 million is expected to be used for recompletions and workovers of 12 Woodbine vertical wells to additional Woodbine sands and seven existing wells in the Sand Flat Unit. |
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Assumed HHUB Price ($/MMBTU) | $ | 3.833 | ||
x BTU Adjustment Factor | 1.3218 | |||
$ | 5.066 | |||
x POP Factor | 1.2376 | |||
Realized Price ($/Mcf) | $ | 6.270 | ||
Underlying | Net Profits | |||||||
Properties (1) | Interest (2) | |||||||
(In thousands, except MBbls, MMcf and MBoe amounts) | ||||||||
Proved Reserves: | ||||||||
Oil (MBbls) | 12,542 | 7,712 | ||||||
Natural gas (MMcf) | 6,949 | 4,819 | ||||||
Oil equivalents (MBoe) | 13,700 | 8,515 | ||||||
Future net revenues | $ | 569,829 | $ | 379,296 | ||||
Discounted estimated future net revenues (3) | $ | 268,283 | $ | 208,552 | ||||
Standardized measure (3)(4) | $ | 268,283 | $ | 208,552 |
(1) | Reserve volumes and estimated future net revenues for Underlying Properties reflect volumes and revenues attributable to VOC Sponsor’s net interests in the properties comprising the Underlying Properties. |
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(2) | Reflects 80% of proved reserves attributable to the Underlying Properties expected to be produced during the term of the trust based on the reserve reports. | |
(3) | The present values of future net revenues for the Underlying Properties and the Net Profits Interest were determined using a discount rate of 10% per annum. As of December 31, 2010, VOC Sponsor was structured as a limited partnership. Accordingly, no provision for federal or state income taxes has been provided because taxable income was passed through to the partners of VOC Sponsor. Therefore, the standardized measure of the Underlying Properties is equal to thePV-10 value, which totaled $268.3 million as of December 31, 2010. | |
(4) | 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 pretaxPV-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. |
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Oil | ||||||||||||
Oil | Natural Gas | Equivalents | ||||||||||
(MBbls) | (MMcf) | (MBoe) | ||||||||||
Proved Reserves: | ||||||||||||
Balance, December 31, 2007 | 11,993 | 7,380 | 13,223 | |||||||||
Revisions of previous estimates | (1,834 | ) | (151 | ) | (1,859 | ) | ||||||
Purchases of minerals in place | 222 | 378 | 285 | |||||||||
Extensions and discoveries | 1 | — | 1 | |||||||||
Production | (704 | ) | (750 | ) | (829 | ) | ||||||
Balance, December 31, 2008 | 9,678 | 6,857 | 10,821 | |||||||||
Revisions of previous estimates | 2,640 | 173 | 2,668 | |||||||||
Purchases of minerals in place | 129 | 126 | 150 | |||||||||
Extensions and discoveries | 215 | — | 215 | |||||||||
Production | (732 | ) | (693 | ) | (847 | ) | ||||||
Balance, December 31, 2009 | 11,930 | 6,463 | 13,007 | |||||||||
Revisions of previous estimates | 1,429 | 1,165 | 1,623 | |||||||||
Production | (817 | ) | (679 | ) | (930 | ) | ||||||
Balance, December 31, 2010 | 12,542 | 6,949 | 13,700 | |||||||||
Proved Developed Reserves: | ||||||||||||
Balance, December 31, 2007 | 11,416 | 7,122 | 12,603 | |||||||||
Balance, December 31, 2008 | 8,952 | 6,562 | 10,046 | |||||||||
Balance, December 31, 2009 | 10,567 | 5,813 | 11,536 | |||||||||
Balance, December 31, 2010 | 10,971 | 5,844 | 11,945 | |||||||||
Proved Undeveloped Reserves: | ||||||||||||
Balance, December 31, 2007 | 577 | 258 | 620 | |||||||||
Balance, December 31, 2008 | 726 | 295 | 775 | |||||||||
Balance, December 31, 2009 | 1,363 | 650 | 1,471 | |||||||||
Balance, December 31, 2010 | 1,570 | 1,106 | 1,754 | |||||||||
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FROM PROVED OIL AND GAS RESERVES
December 31, | ||||||||||||
2008 | 2009 | 2010 | ||||||||||
(in thousands) | ||||||||||||
Future cash inflows | $ | 415,644 | $ | 692,391 | $ | 967,223 | ||||||
Future costs | ||||||||||||
Production | (221,761 | ) | (295,606 | ) | (370,260 | ) | ||||||
Development | (12,501 | ) | (25,317 | ) | (27,134 | ) | ||||||
Future net cash flows | 181,382 | 371,468 | 569,829 | |||||||||
Less 10% discount factor | (86,766 | ) | (192,778 | ) | (301,546 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 94,616 | $ | 178,690 | $ | 268,283 | ||||||
FLOWS FROM PROVED OIL AND GAS RESERVES
December 31, | ||||||||||||
2008 | 2009 | 2010 | ||||||||||
(in thousands) | ||||||||||||
Standardized measure at beginning of year | $ | 339,972 | $ | 94,616 | $ | 178,690 | ||||||
Sales of oil and gas produced, net of production costs | (53,630 | ) | (27,032 | ) | (45,562 | ) | ||||||
Net changes in price and production costs | (259,275 | ) | 55,081 | 74,089 | ||||||||
Extensions, discoveries and improved recovery, net of future production, and development costs | 42 | 8,592 | — | |||||||||
Changes in estimated future development costs | (2,727 | ) | (14,504 | ) | (16,114 | ) | ||||||
Development costs incurred during the period which reduce future development costs | 53 | 2,700 | 7,733 | |||||||||
Revisions of quantity estimates | (18,877 | ) | 42,950 | 31,795 | ||||||||
Accretion of discount | 33,997 | 9,462 | 17,869 | |||||||||
Purchase of reserves in place | 4,832 | 3,150 | — | |||||||||
Change in production rates and other | 50,229 | 3,675 | 19,783 | |||||||||
Standardized measure at end of year | $ | 94,616 | $ | 178,690 | $ | 268,283 | ||||||
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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; |
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• | a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect the Underlying Properties or their title; | |
• | liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings; | |
• | pooling, unitization and communitization agreements, declarations and orders; | |
• | easements, restrictions,rights-of-way and other matters that commonly affect property; | |
• | conventional rights of reassignment that obligate VOC Sponsor to reassign all or part of a property to a third party if VOC Sponsor intends to release or abandon such property; and | |
• | rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties and the Net Profits Interest therein. |
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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 drilling, recompleting, workovers, operating and producing oil and natural gas, including allocated expenses such as labor, vehicle and travel costs and materials and any plugging and abandonment liabilities (net of any development costs for which a reserve had already been made to the |
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extent such development costs are incurred during the computation period) other than costs and expenses for certain future non-consent operations; |
• | 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; | |
• | causing to be prepared and filed a reserve report by or for the trust by independent reserve engineers as of December 31 of each year in accordance with criteria established by the SEC; | |
• | 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. |
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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. |
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• | 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 use commercially reasonable efforts to maintain the effectiveness of the registration statement under the Securities Act for 90 days (or for three years if a shelf registration statement is requested) after the effectiveness thereof or until the trust units covered by the registration statement have been sold pursuant to such registration statement or until all registrable trust units: |
• | 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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• | 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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• | 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 | 16,540,000 | 100 | % | 12,402,750 | (2) | — | — |
(1) | Gives effect to the sale of trust units to VOC Partners, LLC 45 days following the closing of the offering. | |
(2) | Includes 1,617,750 trust units subject to purchase by the underwriters’ pursuant to their 30-day option to purchase additional trust units. |
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Number of | ||||
Underwriter | Trust Units | |||
Raymond James & Associates, Inc. | ||||
Morgan Stanley & Co. Incorporated | ||||
Oppenheimer & Co. Inc. | ||||
RBC Capital Markets, LLC | ||||
Robert W. Baird & Co. Incorporated | ||||
Janney Montgomery Scott LLC | ||||
Morgan Keegan & Company, Inc. | ||||
Wunderlich Securities, Inc. | ||||
Total | 10,785,000 | |||
• | the accuracy of representations and warranties made by VOC Sponsor and the trust to the underwriters; |
• | there having been no material adverse change in financial markets or in the condition (financial or otherwise), business, prospects, management or results of operations of VOC Sponsor or the trust; and |
• | VOC Sponsor’s and the trust’s delivery of customary closing documents, and the delivery of legal opinions, to the underwriters. |
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Per Unit | No Exercise | Full Exercise | ||||||||||
Public offering price | $ | $ | $ | |||||||||
Underwriting discounts and commissions | ||||||||||||
Proceeds, before expenses, to VOC Sponsor |
• | 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. |
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• | during the last 17 days of the180-day period, the trust issues a release concerning earnings or announces material news or a material event relating to the trust occurs; or | |
• | prior to the expiration of the180-day period, the trust announces that it will release distributable cash during the16-day period beginning on the last day of the180-day period, in which case the restrictions described in the preceding paragraphs will continue to apply until the expiration of the18-day period beginning on the issuance of the earnings release, the announcement of the material news or the occurrence of the material event. |
• | 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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PREDECESSOR UNDERLYING PROPERTIES: | ||||
F-2 | ||||
F-3 | ||||
F-4 | ||||
ACQUIRED UNDERLYING PROPERTIES: | ||||
F-10 | ||||
F-11 | ||||
F-12 | ||||
UNAUDITED PRO FORMA UNDERLYING PROPERTIES: | ||||
F-17 | ||||
F-18 | ||||
VOC ENERGY TRUST: | ||||
F-19 | ||||
F-20 | ||||
F-21 | ||||
Unaudited Pro Forma Financial Information: | ||||
F-24 | ||||
F-25 | ||||
F-26 | ||||
F-27 |
F-1
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F-2
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Year Ended December 31, | ||||||||||||
2008 | 2009 | 2010 | ||||||||||
Revenues: | ||||||||||||
Oil sales | $ | 36,632,381 | $ | 22,757,639 | $ | 36,914,333 | ||||||
Natural gas sales | 3,349,695 | 1,510,884 | 2,396,637 | |||||||||
Hedge and other derivative income (expense) | (7,784,517 | ) | 1,477,248 | (707,371 | ) | |||||||
Total | 32,197,559 | 25,745,771 | 38,603,599 | |||||||||
Bad debt expense (recovery) | 1,726,655 | (719,061 | ) | — | ||||||||
Direct operating expenses: | ||||||||||||
Lease operating expenses | 7,667,332 | 6,787,857 | 7,325,042 | |||||||||
Production and property taxes | 2,531,660 | 1,646,052 | 2,720,313 | |||||||||
Total | 10,198,992 | 8,433,909 | 10,045,355 | |||||||||
Excess of revenues over direct operating expenses | $ | 20,271,912 | $ | 18,030,923 | $ | 28,558,244 | ||||||
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Oil | Gas | |||||||
(Bbls) | (Mcf) | |||||||
Proved reserves: | ||||||||
Balance at December 31, 2007 | 7,454,506 | 4,374,316 | ||||||
Revisions of previous estimates | (790,795 | ) | (101,844 | ) | ||||
Purchase of minerals in place | 221,536 | 377,887 | ||||||
Extensions and discoveries | 170 | — | ||||||
Production | (389,268 | ) | (426,326 | ) | ||||
Balance at December 31, 2008 | 6,496,149 | 4,224,033 | ||||||
Revisions of previous estimates | 1,790,387 | 634,099 | ||||||
Purchase of minerals in place | 63,928 | 59,689 | ||||||
Extensions and discoveries | 149,533 | — | ||||||
Production | (407,415 | ) | (414,730 | ) | ||||
Balance at December 31, 2009 | 8,092,582 | 4,503,091 | ||||||
Revisions of previous estimates | 659,977 | 1,041,826 | ||||||
Production | (494,876 | ) | (446,979 | ) | ||||
Balance at December 31, 2010 | 8,257,683 | 5,097,938 | ||||||
Proved developed reserves: | ||||||||
December 31, 2007 | 6,877,406 | 4,116,158 | ||||||
December 31, 2008 | 5,770,190 | 3,928,995 | ||||||
December 31, 2009 | 6,729,632 | 3,854,008 | ||||||
December 31, 2010 | 6,799,873 | 3,992,358 | ||||||
Proved undeveloped reserves: | ||||||||
December 31, 2007 | 577,100 | 258,158 | ||||||
December 31, 2008 | 725,959 | 295,038 | ||||||
December 31, 2009 | 1,362,950 | 649,083 | ||||||
December 31, 2010 | 1,457,810 | 1,105,580 | ||||||
FROM PROVED OIL AND GAS RESERVES
F-7
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2008 | 2009 | 2010 | ||||||||||
Future cash inflows | $ | 285,599,020 | $ | 479,804,227 | $ | 648,185,108 | ||||||
Future costs | ||||||||||||
Production | (152,898,120 | ) | (192,121,342 | ) | (223,916,334 | ) | ||||||
Development | (12,501,184 | ) | (25,183,887 | ) | (25,384,253 | ) | ||||||
Future net cash flows | 120,199,716 | 262,498,998 | 398,884,521 | |||||||||
Less 10% discount factor | (60,259,262 | ) | (142,117,093 | ) | (218,408,117 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 59,940,454 | $ | 120,381,905 | $ | 180,476,404 | ||||||
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FLOWS FROM PROVED OIL AND GAS RESERVES
2008 | 2009 | 2010 | ||||||||||
Standardized measure at beginning of year | $ | 206,509,831 | $ | 59,940,454 | $ | 120,381,905 | ||||||
Sales of oil and gas produced, net of production costs | (29,744,163 | ) | (15,788,110 | ) | (29,265,616 | ) | ||||||
Net changes in price and production costs | (154,951,804 | ) | 41,451,566 | 52,703,598 | ||||||||
Extensions, discoveries and improved recovery, net of future production and development costs | 5,822 | 5,890,961 | — | |||||||||
Changes in estimated future development costs | (2,726,749 | ) | (14,381,027 | ) | (14,568,030 | ) | ||||||
Development costs incurred during the period which reduce future development costs | 52,800 | 2,700,100 | 7,599,939 | |||||||||
Revisions of quantity estimates | (7,982,910 | ) | 29,413,203 | 15,664,245 | ||||||||
Accretion of discount | 20,650,983 | 5,994,045 | 12,038,190 | |||||||||
Purchase of reserves in place | 4,831,610 | 1,567,625 | — | |||||||||
Change in production rates, timing and other | 23,295,034 | 3,593,088 | 15,922,173 | |||||||||
Standardized measure at end of year | $ | 59,940,454 | $ | 120,381,905 | $ | 180,476,404 | ||||||
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F-10
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Year Ended December 31, | ||||||||||||
2008 | 2009 | 2010 | ||||||||||
Revenues: | ||||||||||||
Oil sales | $ | 29,297,334 | $ | 17,602,148 | $ | 23,272,803 | ||||||
Natural gas sales | 2,248,210 | 780,880 | 842,035 | |||||||||
Total | 31,545,544 | 18,383,028 | 24,114,838 | |||||||||
Bad debt expense | 2,165,663 | — | — | |||||||||
Direct operating expenses: | ||||||||||||
Lease operating expenses | 6,046,131 | 5,969,209 | 6,401,987 | |||||||||
Production and property taxes | 1,613,900 | 1,169,798 | 1,416,534 | |||||||||
Total | 7,660,031 | 7,139,007 | 7,818,521 | |||||||||
Excess of revenues over direct operating expenses | $ | 21,719,850 | $ | 11,244,021 | $ | 16,296,317 | ||||||
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F-12
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F-13
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Oil | Gas | |||||||
(Bbls) | (Mcf) | |||||||
Proved reserves: | ||||||||
Balance at December 31, 2007 | 4,538,607 | 3,005,629 | ||||||
Revisions of previous estimates | (1,042,884 | ) | (48,799 | ) | ||||
Extensions and discoveries | 1,063 | — | ||||||
Production | (314,620 | ) | (323,964 | ) | ||||
Balance at December 31, 2008 | 3,182,166 | 2,632,866 | ||||||
Revisions of previous estimates | 849,297 | (461,342 | ) | |||||
Purchase of minerals in places | 64,733 | 65,972 | ||||||
Extensions and discoveries | 65,804 | — | ||||||
Production | (324,329 | ) | (278,022 | ) | ||||
Balance at December 31, 2009 | 3,837,671 | 1,959,474 | ||||||
Revisions of previous estimates | 767,948 | 124,153 | ||||||
Production | (321,661 | ) | (232,254 | ) | ||||
Balance at December 31, 2010 | 4,283,958 | 1,851,373 | ||||||
Proved developed reserves: | ||||||||
December 31, 2007 | 4,538,607 | 3,005,629 | ||||||
December 31, 2008 | 3,182,166 | 2,632,866 | ||||||
December 31, 2009 | 3,837,671 | 1,959,474 | ||||||
December 31, 2010 | 4,171,465 | 1,851,373 | ||||||
Proved undeveloped reserves: | ||||||||
December 31, 2007 | — | — | ||||||
December 31, 2008 | — | — | ||||||
December 31, 2009 | — | — | ||||||
December 31, 2010 | 112,493 | — | ||||||
F-14
Table of Contents
FROM PROVED OIL AND GAS RESERVES
F-15
Table of Contents
2008 | 2009 | 2010 | ||||||||||
Future cash inflows | $ | 130,045,214 | $ | 212,587,116 | $ | 319,037,861 | ||||||
Future costs | ||||||||||||
Production | (68,863,533 | ) | (103,484,949 | ) | (146,343,958 | ) | ||||||
Development | — | (133,055 | ) | (1,749,143 | ) | |||||||
Future net cash flows | 61,181,681 | 108,969,112 | 170,944,760 | |||||||||
Less 10% discount factor | (26,506,431 | ) | (50,661,158 | ) | (83,138,265 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 34,675,250 | $ | 58,307,954 | $ | 87,806,495 | ||||||
FLOWS FROM PROVED OIL AND GAS RESERVES
2008 | 2009 | 2010 | ||||||||||
Standardized measure at beginning of year | $ | 133,461,982 | $ | 34,675,250 | $ | 58,307,954 | ||||||
Sales of oil and gas produced, net of production costs | (23,885,512 | ) | (11,244,020 | ) | (16,296,317 | ) | ||||||
Net changes in price and production costs | (104,323,038 | ) | 13,629,634 | 21,385,452 | ||||||||
Extensions, discoveries and improved recovery, net of future production and development costs | 36,385 | 2,700,702 | — | |||||||||
Changes in estimated future development costs | — | (123,046 | ) | (1,545,676 | ) | |||||||
Development costs incurred during the period which reduce future development costs | — | — | 133,055 | |||||||||
Revisions of quantity estimates | (10,894,366 | ) | 13,536,403 | 16,130,251 | ||||||||
Accretion of discount | 13,346,198 | 3,467,525 | 5,830,796 | |||||||||
Purchase of reserves in place | — | 1,582,671 | — | |||||||||
Change in production rates, timing and other | 26,933,601 | 82,835 | 3,860,980 | |||||||||
Standardized measure at end of year | $ | 34,675,250 | $ | 58,307,954 | $ | 87,806,495 | ||||||
F-16
Table of Contents
DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES
F-17
Table of Contents
AND DIRECT OPERATING EXPENSES OF THE UNDERLYING PROPERTIES
Year Ended December 31, 2010 | ||||||||||||
Historical | Adjustments | Pro Forma | ||||||||||
(a) | ||||||||||||
Revenues: | ||||||||||||
Oil sales | $ | 36,914,333 | $ | 23,272,803 | $ | 60,187,136 | ||||||
Natural gas sales | 2,396,637 | 842,035 | 3,238,672 | |||||||||
Hedge activity | (707,371 | ) | — | (707,371 | ) | |||||||
Total | 38,603,599 | 24,114,838 | 62,718,437 | |||||||||
Direct operating expenses: | ||||||||||||
Lease operating expenses | 7,325,042 | 6,401,987 | 13,727,029 | |||||||||
Production and property taxes | 2,720,313 | 1,416,534 | 4,136,847 | |||||||||
Total | 10,045,355 | 7,818,521 | 17,863,876 | |||||||||
Excess of revenues over direct operating expenses | $ | 28,558,244 | $ | 16,296,317 | $ | 44,854,561 | ||||||
(a) | Pro forma adjustment to give effect to the acquisition of the Acquired Properties as if the acquisition had occurred on January 1, 2010. |
F-18
Table of Contents
F-19
Table of Contents
December 31, | ||||
2010 | ||||
ASSETS | ||||
Cash | $ | 1,000 | ||
TRUST CORPUS | ||||
Trust Corpus | $ | 1,000 | ||
F-20
Table of Contents
F-21
Table of Contents
NOTE C — | INCOME TAXES |
F-22
Table of Contents
NOTE D — | DISTRIBUTIONS TO UNITHOLDERS |
NOTE E — | SUBSEQUENT EVENTS |
F-23
Table of Contents
F-24
Table of Contents
December 31, 2010 | ||||||||||||
Historical | Adjustments | Pro Forma | ||||||||||
(a) | ||||||||||||
ASSETS | ||||||||||||
Cash | $ | 1,000 | $ | — | $ | 1,000 | ||||||
Investment in Net Profits Interest (See Note E) | — | 144,536,661 | 144,536,661 | |||||||||
$ | 1,000 | $ | 144,536,661 | $ | 144,537,661 | |||||||
TRUST CORPUS | ||||||||||||
16,540,000 trust units issued and outstanding | $ | 1,000 | $ | 144,536,661 | $ | 144,537,661 | ||||||
(a) | VOC Energy Trust was formed in November, 2010 and capitalized on December 17, 2010. |
F-25
Table of Contents
Year Ended | ||||
December 31, 2010 | ||||
Historical Results | ||||
Income from the Net Profits Interest (See Note D) | $ | 27,489,986 | ||
Pro Forma Adjustments | ||||
Less trust general and administrative expenses (See Note E(a)) | 900,000 | |||
Distributable income | $ | 26,589,986 | ||
Distributable income per unit | $ | 1.61 | ||
F-26
Table of Contents
F-27
Table of Contents
Year Ended | ||||
December 31, 2010 | ||||
Excess of revenues over direct operating expenses of Underlying Properties | $ | 44,854,562 | ||
Development expenses (1) | 10,492,080 | |||
Excess of revenues over direct operating expenses and development expenses | 34,362,482 | |||
Times Net Profits Interest over the term of the Trust | 80 | % | ||
Trust Income from Net Profits Interest | $ | 27,489,986 | ||
(1) | Per terms of the Net Profits Interest development costs are to be deducted when calculating the distributable income to the Trust. |
Oil and gas properties consisting of the Underlying Properties | $ | 210,789,946 | ||
Less accumulated depreciation, depletion and amortization | (28,174,233 | ) | ||
Net Property Value | 182,615,713 | |||
Plus hedge asset | 182,817 | |||
Less asset retirement obligation (1) | (4,242,466 | ) | ||
Net property to be conveyed | 178,556,064 | |||
Times 80% Net Profits Interest to Trust with the asset retirement obligation limited to the life of the Trust | $ | 144,536,661 | ||
(1) | See Note F below for a description of asset retirement obligation. |
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 | 35 | Vice President and Chief Financial Officer | ||||
Alan Howarter | 55 | Vice President of Financial Reporting |
VOC-3
Table of Contents
VOC-4
Table of Contents
Year Ended December 31, | ||||||||||||
2008 | 2009 | 2010 | ||||||||||
(In thousands) | ||||||||||||
Lease operating expenses incurred: | ||||||||||||
Vess Oil Corporation | $ | 10,314 | $ | 9,334 | $ | 10,053 | ||||||
LD Drilling | 768 | 685 | 605 | |||||||||
Davis Petroleum | 652 | 704 | 756 | |||||||||
Total | $ | 11,734 | $ | 10,723 | $ | 11,414 | ||||||
Overhead costs included in lease operating expenses incurred: | ||||||||||||
Vess Oil Corporation | $ | 1,098 | $ | 1,232 | $ | 1,314 | ||||||
LD Drilling | 91 | 97 | 100 | |||||||||
Davis Petroleum | 64 | 72 | 72 | |||||||||
Total | $ | 1,253 | $ | 1,401 | $ | 1,486 | ||||||
Capitalized lease equipment and producing leasehold costs incurred: | ||||||||||||
Vess Oil Corporation | $ | 1,402 | $ | 1,937 | $ | 3,246 | ||||||
LD Drilling | 304 | 154 | (8 | ) | ||||||||
Davis Petroleum | 220 | 3 | 14 | |||||||||
Total | $ | 1,926 | $ | 2,094 | $ | 3,252 | ||||||
Payment of well development costs: | ||||||||||||
Vess Oil Corporation | $ | 1,709 | $ | 2,269 | $ | 7,149 | ||||||
LD Drilling | 509 | 137 | — | |||||||||
Davis Petroleum | 168 | — | 81 | |||||||||
Total | $ | 2,386 | $ | 2,406 | $ | 7,230 | ||||||
Payment of management fees: | ||||||||||||
Vess Oil Corporation | $ | 447 | $ | 447 | $ | 447 | ||||||
LD Drilling | — | — | — | |||||||||
Davis Petroleum | — | — | — | |||||||||
Total | $ | 447 | $ | 447 | $ | 447 | ||||||
VOC-5
Table of Contents
Year Ended December 31, | ||||||||||||||||||||
2008 | 2009 | 2010 | ||||||||||||||||||
Sales | $ | 1,207,358 | $ | 13,482,074 | $ | 19,125,260 | ||||||||||||||
Trade Receivables | $ | 319,109 | $ | 1,359,842 | $ | 1,760,141 |
VOC-6
Table of Contents
FINANCIAL DATA OF VOC SPONSOR
VOC-7
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) | |||||||||||||||||||
Predecessor | Year Ended | Year Ended | ||||||||||||||||||
Year Ended December 31, | December 31, | December 31, | ||||||||||||||||||
2008 | 2009 | 2010 | 2010 | 2010 | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||||||
Revenue | ||||||||||||||||||||
Oil and gas sales | $ | 32,198 | $ | 25,746 | $ | 38,603 | $ | 62,718 | $ | 12,543 | ||||||||||
Interest income | — | — | — | — | — | |||||||||||||||
Gain on sales of assets | — | — | — | — | 9,423 | |||||||||||||||
Other | — | 4 | 32 | 32 | 32 | |||||||||||||||
Total revenue | 32,198 | 25,750 | 38,635 | 62,750 | 21,998 | |||||||||||||||
Costs and expenses | ||||||||||||||||||||
Lease operating | 7,667 | 6,788 | 7,325 | 13,727 | 2,745 | |||||||||||||||
Production and property taxes | 2,532 | 1,646 | 2,720 | 4,137 | 827 | |||||||||||||||
Depreciation, depletion, amortization and accretion | 5,781 | 5,210 | 6,253 | 12,836 | 2,979 | |||||||||||||||
Bad debt expense (recovery) | 1,727 | (719 | ) | — | — | — | ||||||||||||||
General and administrative | 269 | 463 | 205 | 205 | 205 | |||||||||||||||
Interest | 1,383 | 1,501 | 1,221 | 1,221 | 1,221 | |||||||||||||||
Total costs and expenses | 19,359 | 14,889 | 17,724 | 32,126 | 7,977 | |||||||||||||||
Net earnings | $ | 12,839 | $ | 10,861 | 20,911 | 30,624 | 14,021 | |||||||||||||
Total assets (at year end) | $ | 108,830 | $ | 101,280 | 109,038 | 202,171 | 96,358 | |||||||||||||
Long-term liabilities, excluding current maturities (at year end) | $ | 37,018 | $ | 28,315 | 26,241 | 27,805 | 99,392 | |||||||||||||
Partners’ capital/Common Control owners’ equity (deficit) | $ | 67,865 | $ | 67,512 | 70,936 | 159,559 | (26,746 | ) |
VOC-8
Table of Contents
AND RESULTS OF OPERATIONS OF VOC SPONSOR
VOC-9
Table of Contents
Years Ended December 31, | ||||||||||||
2008 | 2009 | 2010 | ||||||||||
(In thousands) | ||||||||||||
Revenue | ||||||||||||
Oil and gas sales | $ | 32,198 | $ | 25,746 | $ | 38,603 | ||||||
Interest income | — | 4 | 32 | |||||||||
Total revenue | $ | 32,198 | $ | 25,750 | $ | 38,635 | ||||||
Costs and expenses | ||||||||||||
Lease operating | 7,667 | 6,788 | 7,325 | |||||||||
Production and property taxes | 2,532 | 1,646 | 2,720 | |||||||||
Depreciation, depletion, amortization and accretion | 5,781 | 5,210 | 6,253 | |||||||||
Bad debt expense (recovery) | 1,727 | (719 | ) | — | ||||||||
General and administrative | 269 | 463 | 205 | |||||||||
Interest | 1,383 | 1,501 | 1,221 | |||||||||
Total costs and expenses | $ | 19,359 | $ | 14,889 | $ | 17,724 | ||||||
Net earnings | $ | 12,839 | $ | 10,861 | $ | 20,911 | ||||||
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 | 20,014 | $ | 96.77 | |||||||||
April 2011 | 43,407 | $ | 99.99 | |||||||||
May 2011 | 42,828 | $ | 99.98 | |||||||||
June 2011 | 42,285 | $ | 99.98 | |||||||||
July 2011 | 41,766 | $ | 99.97 | |||||||||
August 2011 | 41,271 | $ | 99.96 | |||||||||
September 2011 | 40,796 | $ | 99.95 | |||||||||
October 2011 | 40,337 | $ | 99.94 | |||||||||
November 2011 | 39,898 | $ | 99.94 | |||||||||
December 2011 | 39,476 | $ | 99.93 | |||||||||
January 2012 | 39,038 | $ | 100.84 | |||||||||
February 2012 | 38,631 | $ | 100.84 | |||||||||
March 2012 | 38,251 | $ | 100.85 | |||||||||
April 2012 | 37,882 | $ | 100.85 | |||||||||
May 2012 | 37,523 | $ | 100.85 | |||||||||
June 2012 | 37,176 | $ | 100.85 | |||||||||
July 2012 | 36,839 | $ | 100.86 | |||||||||
August 2012 | 36,513 | $ | 100.86 | |||||||||
September 2012 | 36,194 | $ | 100.86 | |||||||||
October 2012 | 35,883 | $ | 100.86 | |||||||||
November 2012 | 35,562 | $ | 100.87 | |||||||||
December 2012 | 35,268 | $ | 100.87 | |||||||||
January 2013 | 34,975 | $ | 99.01 | |||||||||
February 2013 | 34,686 | $ | 99.01 | |||||||||
March 2013 | 34,406 | $ | 99.01 | |||||||||
April 2013 | 34,166 | $ | 99.01 | |||||||||
May 2013 | 33,959 | $ | 99.01 | |||||||||
June 2013 | 33,727 | $ | 99.01 | |||||||||
July 2013 | 33,526 | $ | 99.01 | |||||||||
August 2013 | 33,317 | $ | 99.01 | |||||||||
September 2013 | 33,122 | $ | 99.01 | |||||||||
October 2013 | 32,929 | $ | 99.01 | |||||||||
November 2013 | 32,741 | $ | 99.01 | |||||||||
December 2013 | 32,554 | $ | 99.01 |
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 (1) | $ | 24,000 | $ | — | $ | 24,000 | $ | — | $ | — | ||||||||||
Asset retirement obligations | 4,243 | 437 | 163 | 133 | 3,510 | |||||||||||||||
Total | $ | 28,243 | $ | 437 | $ | 24,163 | $ | 133 | $ | 3,510 | ||||||||||
(1) | The amounts included in the table above represent principal maturities only. See “Management’s discussion and analysis of financial condition and results of operations of VOC Sponsor — Quantitative and qualitative disclosure about market risk — Interest rate risk” for information regarding interest payment obligations under long-term debt obligations. |
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-24 | |||
VOC F-25 | ||||
VOC F-26 | ||||
VOC F-27 |
VOC F-1
Table of Contents
VOC F-2
Table of Contents
December 31, | ||||||||
2009 | 2010 | |||||||
ASSETS | ||||||||
CURRENT ASSETS | ||||||||
Cash and cash equivalents | $ | 4,931,842 | $ | 11,594,345 | ||||
Accounts receivable — oil and gas sales | 1,090,371 | 1,091,745 | ||||||
Accounts receivable — oil and gas sales — related parties, net of allowance for doubtful accounts of $1,007,594 in 2009 and $0 in 2010 | 3,622,470 | 3,645,127 | ||||||
Oil swap agreements | — | 182,817 | ||||||
Prepaid expenses | 68,828 | 84,627 | ||||||
Total current assets | 9,713,511 | 16,598,661 | ||||||
OIL AND GAS PROPERTIES | 111,171,636 | 119,848,855 | ||||||
Less accumulated depreciation, depletion and amortization | 22,098,350 | 28,174,233 | ||||||
89,073,286 | 91,674,622 | |||||||
OTHER ASSETS | ||||||||
Oil swap agreements | 1,371,351 | — | ||||||
Deferred loan costs, net of accumulated amortization of $855,173 in 2009, and $1,403,726 in 2010 | 1,121,357 | 555,155 | ||||||
Deferred offering costs | — | 209,272 | ||||||
2,492,708 | 764,427 | |||||||
$ | 101,279,505 | $ | 109,037,710 | |||||
LIABILITIES AND PARTNERS’ CAPITAL/COMMON CONTROL OWNERS’ EQUITY | ||||||||
CURRENT LIABILITIES | ||||||||
Accounts payable | ||||||||
Trade | $ | 46,517 | $ | 68,854 | ||||
Related parties | 1,285,891 | 770,513 | ||||||
Accrued interest | 146,839 | 63,742 | ||||||
Settlement payable on oil swap agreements | 106,139 | 228,961 | ||||||
Distributions payable | — | 9,995,900 | ||||||
Accrued ad valorem taxes | 378,040 | 499,596 | ||||||
Other accrued liabilities | 377,411 | 233,531 | ||||||
Current maturities of notes payable | 1,531,276 | — | ||||||
Oil swap agreements | 1,580,850 | — | ||||||
Total current liabilities | 5,452,963 | 11,861,097 | ||||||
LONG-TERM LIABILITIES, less current maturities | ||||||||
Notes payable | 25,661,011 | 24,000,000 | ||||||
Asset retirement obligation | 2,653,676 | 2,240,501 | ||||||
28,314,687 | 26,240,501 | |||||||
COMMITMENTS AND CONTINGENCIES | ||||||||
PARTNERS’CAPITAL/COMMON CONTROL OWNERS’ EQUITY | ||||||||
General partner capital account | 483,527 | 571,419 | ||||||
Limited partners capital account | 48,246,417 | 51,213,862 | ||||||
Common control owners’ equity | 18,991,410 | 19,228,511 | ||||||
Accumulated other comprehensive loss | (209,499 | ) | (77,680 | ) | ||||
67,511,855 | 70,936,112 | |||||||
$ | 101,279,505 | $ | 109,037,710 | |||||
VOC F-3
Table of Contents
Year Ended December 31, | ||||||||||||
2008 | 2009 | 2010 | ||||||||||
Revenues | ||||||||||||
Oil and gas sales | $ | 32,197,559 | $ | 25,745,771 | $ | 38,603,599 | ||||||
Other | — | 4,452 | 31,749 | |||||||||
32,197,559 | 25,750,223 | 38,635,348 | ||||||||||
Costs and expenses | ||||||||||||
Lease operating | 7,667,332 | 6,787,857 | 7,325,042 | |||||||||
Production and property taxes | 2,531,660 | 1,646,052 | 2,720,313 | |||||||||
Depreciation, depletion, amortization and accretion | 5,780,829 | 5,210,212 | 6,252,676 | |||||||||
Interest expense | 1,382,725 | 1,500,647 | 1,221,373 | |||||||||
Bad debt expense (recovery) | 1,726,655 | (719,061 | ) | — | ||||||||
General and administrative | 269,139 | 463,295 | 204,575 | |||||||||
Total costs and expenses | 19,358,340 | 14,889,002 | 17,723,979 | |||||||||
Net earnings | $ | 12,839,219 | $ | 10,861,221 | $ | 20,911,369 | ||||||
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, 2008 | $ | 269,208 | $ | 26,651,545 | $ | — | $ | 11,176,005 | $ | (9,993,411 | ) | $ | 28,103,347 | |||||||||||
Partners’ capital contributions | — | — | 40,000,000 | — | — | 40,000,000 | ||||||||||||||||||
Partners’ distributions | (33,350 | ) | (73,301,650 | ) | — | — | — | (73,335,000 | ) | |||||||||||||||
Common control owners’ contributions | — | — | — | 5,128,500 | — | 5,128,500 | ||||||||||||||||||
Common control owners’ distributions | — | — | — | (5,169,277 | ) | — | (5,169,277 | ) | ||||||||||||||||
Comprehensive income | ||||||||||||||||||||||||
Net earnings for the year | 100,064 | 4,372,524 | 2,073,523 | 6,293,108 | 12,839,219 | |||||||||||||||||||
Reclassification adjustment for realized losses on swap transactions | — | — | — | — | 5,939,518 | 5,939,518 | ||||||||||||||||||
Change in fair value of swap agreements | — | — | — | — | 12,081,071 | 12,081,071 | ||||||||||||||||||
Total comprehensive income | 30,859,808 | |||||||||||||||||||||||
Step-up in basis of leasehold costs and lease equipment equal to the limited partner’s liquidating distribution in excess of the partner’s capital account | — | 42,277,581 | — | — | — | 42,277,581 | ||||||||||||||||||
Balance at December 31, 2008 | 335,922 | — | 42,073,523 | 17,428,336 | 8,027,178 | 67,864,959 | ||||||||||||||||||
Common control owners’ contributions | — | — | — | 400,000 | — | 400,000 | ||||||||||||||||||
Common control owners’ distributions | — | — | — | (3,377,648 | ) | — | (3,377,648 | ) | ||||||||||||||||
Comprehensive income (loss) | ||||||||||||||||||||||||
Net earnings for the year | 147,605 | — | 6,172,894 | 4,540,722 | — | 10,861,221 | ||||||||||||||||||
Reclassification adjustment for realized gains on swap transactions | — | — | — | — | (1,347,010 | ) | (1,347,010 | ) | ||||||||||||||||
Change in fair value of swap agreements | — | — | — | — | (6,889,667 | ) | (6,889,667 | ) | ||||||||||||||||
Total comprehensive income | 2,624,544 | |||||||||||||||||||||||
Balance at December 31, 2009 | 483,527 | — | 48,246,417 | 18,991,410 | (209,499 | ) | 67,511,855 | |||||||||||||||||
Partner’s distributions | (186,500 | ) | — | (9,138,500 | ) | — | — | (9,325,000 | ) | |||||||||||||||
Common control owners’ distributions | — | — | — | (8,293,931 | ) | — | (8,293,931 | ) | ||||||||||||||||
Comprehensive income | ||||||||||||||||||||||||
Net earnings for the year | 274,392 | — | 12,105,945 | 8,531,032 | — | 20,911,369 | ||||||||||||||||||
Reclassification adjustment for realized losses on swap transactions | — | — | — | — | 1,123,965 | 1,123,965 | ||||||||||||||||||
Change in fair value of swap agreements | — | — | — | — | (992,146 | ) | (992,146 | ) | ||||||||||||||||
Total comprehensive income | 21,043,188 | |||||||||||||||||||||||
Balance at December 31, 2010 | $ | 571,419 | $ | — | $ | 51,213,862 | $ | 19,228,511 | $ | (77,680 | ) | $ | 70,936,112 | |||||||||||
VOC F-5
Table of Contents
Year Ended December 31, | ||||||||||||
2008 | 2009 | 2010 | ||||||||||
Cash flows from operating activities | ||||||||||||
Net earnings | $ | 12,839,219 | $ | 10,861,221 | $ | 20,911,369 | ||||||
Adjustments to reconcile net earnings to net cash provided by operating activities | ||||||||||||
Depreciation, depletion, amortization and accretion | 5,780,829 | 5,210,212 | 6,252,676 | |||||||||
Amortization of deferred loan costs | 285,154 | 565,909 | 566,202 | |||||||||
Bad debt expense | 1,726,655 | — | — | |||||||||
Unrealized derivative (gain) loss | (3,581,995 | ) | 333,695 | (260,497 | ) | |||||||
Settlements of asset retirement obligations | (25,143 | ) | (27,149 | ) | (245,649 | ) | ||||||
Change in operating assets and liabilities | ||||||||||||
Accounts receivable | (1,306,761 | ) | (1,208,820 | ) | (24,031 | ) | ||||||
Settlement receivable on swap agreements | (513,751 | ) | 513,751 | — | ||||||||
Prepaid expenses | 5,432 | 1,974 | (15,799 | ) | ||||||||
Accounts payable | (132,958 | ) | (109,862 | ) | 254,496 | |||||||
Accrued liabilities | 228,828 | (205,242 | ) | 167,986 | ||||||||
Accrued interest payable | 382,102 | (253,982 | ) | (83,097 | ) | |||||||
Settlement payable on swap agreements | (713,268 | ) | 106,139 | 122,822 | ||||||||
Net cash provided by operating activities | 14,974,343 | 15,787,846 | 27,646,478 | |||||||||
Cash flows from investing activities | ||||||||||||
Purchase of oil and gas properties and equipment | (6,675,201 | ) | (2,151,315 | ) | (2,729,757 | ) | ||||||
Well development cost | (1,245,986 | ) | (1,582,563 | ) | (7,229,628 | ) | ||||||
Net cash used in investing activities | (7,921,187 | ) | (3,733,878 | ) | (9,959,385 | ) | ||||||
Cash flows from financing activities | ||||||||||||
Proceeds from issuance of notes payable | 32,622,900 | — | — | |||||||||
Payments on notes payable | (1,293,757 | ) | (7,824,980 | ) | (3,192,287 | ) | ||||||
Payment of deferred loan costs | (1,958,881 | ) | (118 | ) | — | |||||||
Payment of deferred offering costs | — | — | (209,272 | ) | ||||||||
Partners’ contributions | 40,000,000 | — | — | |||||||||
Partners’ distributions | (73,335,000 | ) | — | (325,000 | ) | |||||||
Common control owners’ contributions | 5,128,500 | 400,000 | — | |||||||||
Common control owners’ distributions | (5,169,277 | ) | (3,377,648 | ) | (7,298,031 | ) | ||||||
Net cash used in financing activities | (4,005,515 | ) | (10,802,746 | ) | (11,024,590 | ) | ||||||
Net increase in cash and cash equivalents | 3,047,641 | 1,251,222 | 6,662,503 | |||||||||
Cash and cash equivalents, beginning of period | 632,979 | 3,680,620 | 4,931,842 | |||||||||
Cash and cash equivalents, end of period | $ | 3,680,620 | $ | 4,931,842 | $ | 11,594,345 | ||||||
Supplemental cash flow information | ||||||||||||
Cash paid during the period for interest | $ | 715,469 | $ | 1,188,720 | 738,268 | |||||||
Noncash investing and financing activities | ||||||||||||
Asset retirement costs and obligation recorded upon drilling of new oil and gas wells | $ | 238,516 | $ | 77,632 | 33,879 | |||||||
Increase (decrease) in asset retirement cost and obligation due to changes in timing and estimated cash flows | $ | 1,067,315 | $ | (1,331,472 | ) | (553,292 | ) | |||||
Purchases of oil and gas properties and equipment and well development costs included in accounts payable at year end | $ | 227,927 | $ | 794,935 | 47,398 | |||||||
Step-up in basis of oil and gas properties as a result of redemption of limited partners interest | $ | 42,277,581 | $ | — | — | |||||||
Partners’ and common control owners’ distributions included in distributions payable at year end | $ | — | $ | — | $ | 9,995,900 |
VOC F-6
Table of Contents
VOC F-7
Table of Contents
VOC F-8
Table of Contents
VOC F-9
Table of Contents
VOC F-10
Table of Contents
VOC F-11
Table of Contents
December 31, | ||||||||
2009 | 2010 | |||||||
Producing leaseholds | $ | 72,230,517 | $ | 71,617,828 | ||||
Lease equipment | 23,820,846 | 26,344,965 | ||||||
Well development costs | 15,120,273 | 21,886,062 | ||||||
111,171,636 | 119,848,855 | |||||||
Less accumulated depreciation, depletion and amortization | 22,098,350 | 28,174,233 | ||||||
Net oil and gas properties | $ | 89,073,286 | $ | 91,674,622 | ||||
December 31, | ||||||||||||
2008 | 2009 | 2010 | ||||||||||
Property acquisition costs | $ | 6,913,717 | $ | 2,228,947 | $ | 2,446,059 | ||||||
Development costs | 1,245,986 | 1,582,563 | 6,765,789 | |||||||||
Total | $ | 8,159,703 | $ | 3,811,510 | $ | 9,211,848 | ||||||
December 31, | ||||||||||||||||||||
2008 | 2009 | 2010 | ||||||||||||||||||
Revenues from oil and gas sales | $ | 32,197,559 | $ | 25,745,771 | $ | 38,603,599 | ||||||||||||||
Less: | ||||||||||||||||||||
Lease operating expenses | 7,667,332 | 6,787,857 | 7,325,042 | |||||||||||||||||
Production and property taxes | 2,531,660 | 1,646,052 | 2,720,313 | |||||||||||||||||
Depreciation, depletion and amortization | 5,780,829 | 5,210,212 | 6,252,676 | |||||||||||||||||
Bad debt expense (recovery) | 1,726,655 | (719,061 | ) | — | ||||||||||||||||
Income from oil and gas operations | $ | 14,491,083 | $ | 12,820,711 | $ | 22,305,568 | ||||||||||||||
VOC F-12
Table of Contents
December 31, | ||||||||||||
2009 | 2010 | |||||||||||
Credit facility — see details below | $ | 24,000,000 | $ | 24,000,000 | ||||||||
Note payable to bank in monthly installments of $25,443 including interest at prime (prime was 3.25% at December 31, 2009), with final payment due in May 2013, collateralized by mortgages on oil and gas properties and guaranteed by two members of the Common Control Properties. Note was paid in full in November 2010 | 876,964 | — | ||||||||||
Note payable to bank in monthly installments of $23,000 including interest at prime (with a floor of 4.50% which was the effective interest rate at December 31, 2009), with final payment due in July 2011, collateralized by mortgages on oil and gas properties and paid in full in August 2010 | 831,563 | — | ||||||||||
Note payable to bank in monthly installments of $89,329 including interest at prime (with a floor of 4.00% which was the effective interest rate at December 31, 2009), with final payment due August 2011, collateralized by mortgages on oil and gas properties and paid in full in August 2010 | 1,483,760 | — | ||||||||||
27,192,287 | 24,000,000 | |||||||||||
Less current maturities | 1,531,276 | — | ||||||||||
$ | 25,661,011 | $ | 24,000,000 | |||||||||
VOC F-13
Table of Contents
2011 | $ | — | ||
2012 | — | |||
2013 | 24,000,000 | |||
$ | 24,000,000 | |||
VOC F-14
Table of Contents
2009 | Year | Notional Volume | Fixed Price | Fair Value | ||||||||||||
2010 | 174,571 bbls | 73.06 | $ | (1,580,850 | ) | |||||||||||
2011 | 159,894 bbls | 94.90 | 1,371,351 | |||||||||||||
$ | (209,499 | ) | ||||||||||||||
2010 | Year | Notional Volume | Fixed Price | Fair Value | ||||||||||||
2011 | 159,894 bbls | 94.90 | $ | 182,817 | ||||||||||||
VOC F-15
Table of Contents
December 31, | ||||||||||||
2008 | 2009 | 2010 | ||||||||||
With operator/new revenue intermediary | ||||||||||||
Lease operating expense incurred | $ | 6,705,544 | $ | 5,770,203 | $ | 6,066,454 | ||||||
Overhead costs included in lease operating expense | $ | 466,796 | $ | 548,873 | $ | 586,776 | ||||||
Reimbursement of overhead costs* | $ | (355,235 | ) | $ | (353,020 | ) | $ | (345,485 | ) | |||
Capitalized lease equipment and producing leaseholds costs incurred | $ | 794,822 | $ | 1,394,856 | $ | 2,591,138 | ||||||
Payment of well development costs | $ | 1,004,078 | $ | 1,953,828 | $ | 6,765,790 | ||||||
Revenue receipts | $ | 7,447,596 | $ | 8,151,559 | $ | 18,087,204 | ||||||
With General Partner | ||||||||||||
Overhead costs incurred* | $ | 447,000 | $ | 447,000 | $ | 447,000 | ||||||
With former revenue intermediary | ||||||||||||
Revenue receipts | $ | 5,963,891 | $ | — | $ | — |
* | Upon dissolution of the former partnership (see Note A2), an agreement was reached between the former partners and operator with Predecessor and new operator. The agreement provided that the existing overhead agreement would continue to apply to all working interest owners other than Predecessor. Predecessor negotiated a new overhead arrangement with lower rates with the new operator, which includes a reimbursement to Predecessor for overhead amounts paid by the other working interest owners. The overhead charges, net of the reimbursement for the amounts paid by the other working interest owners, is included in operating expenses in the statements of earnings. |
Crude Oil | ||||||||||||
Operator | Purchasers | Total | ||||||||||
December 31, 2009 | ||||||||||||
Accounts receivable | $ | 2,167,284 | $ | 2,462,780 | $ | 4,630,064 | ||||||
Accounts payable | $ | 1,285,891 | $ | — | $ | 1,285,891 | ||||||
December 31, 2010 | ||||||||||||
Accounts receivable | $ | 2,878,164 | $ | 766,963 | $ | 3,645,127 | ||||||
Accounts payable | $ | 770,513 | $ | — | $ | 770,513 |
VOC F-16
Table of Contents
Year Ended December 31, | ||||||||||||
2008 | 2009 | 2010 | ||||||||||
Sales | $ | 646,957 | $ | 5,993,119 | $ | 8,526,840 | ||||||
Trade Receivables | $ | 180,841 | $ | 610,191 | $ | 766,963 |
VOC F-17
Table of Contents
December 31, | ||||||||||||
2008 | 2009 | 2010 | ||||||||||
Asset retirement obligations — beginning of year | $ | 2,641,033 | $ | 4,075,952 | $ | 3,019,115 | ||||||
Liabilities incurred during the year | 238,516 | 77,632 | 33,879 | |||||||||
Liabilities settled during the year | (25,143 | ) | (27,149 | ) | (245,649 | ) | ||||||
Accretion expense | 154,231 | 224,152 | 161,577 | |||||||||
Increase (decrease) in asset retirement obligations due to changes in timing and changes in estimated cash flows | 1,067,315 | (1,331,472 | ) | (553,292 | ) | |||||||
Asset retirement obligations — end of year | 4,075,952 | 3,019,115 | 2,415,630 | |||||||||
Less current portion included in other accrued liabilities | 272,037 | 365,439 | 175,129 | |||||||||
Long-term portion | $ | 3,803,915 | $ | 2,653,676 | $ | 2,240,501 | ||||||
VOC F-18
Table of Contents
Quoted Prices in | Significant Other | Unobservable | ||||||||||
Active Markets | Observable Inputs | Inputs | ||||||||||
(Level 1) | (Level 2) | (Level 3) | ||||||||||
Financial assets (liabilities): | ||||||||||||
2009 Hedge agreements, net | $ | — | $ | (209,499 | ) | $ | — | |||||
2010 Hedge agreements, net | $ | — | $ | 182,817 | $ | — | ||||||
2009 asset retirement obligations incurred | $ | — | $ | — | $ | (77,632 | ) | |||||
2010 asset retirement obligations incurred | $ | — | $ | — | $ | (33,879 | ) |
VOC F-19
Table of Contents
Year | Notional Volume | Fixed Price | ||
2011 | 155,634 Bbls | $100.25 - $100.70 | ||
2012 | 315,889 Bbls | $ 99.10 - $100.00 | ||
2013 | 284,485 Bbls | $ 97.30 - $ 98.45 |
VOC F-20
Table of Contents
Oil | Gas | |||||||
(Bbls) | (Mcf) | |||||||
Proved reserves: | ||||||||
Balance at December 31, 2007 | 7,454,506 | 4,374,316 | ||||||
Revisions of previous estimates | (790,795 | ) | (101,844 | ) | ||||
Purchase of minerals in place | 221,536 | 377,887 | ||||||
Extensions and discoveries | 170 | — | ||||||
Production | (389,268 | ) | (426,326 | ) | ||||
Balance at December 31, 2008 | 6,496,149 | 4,224,033 | ||||||
Revisions of previous estimates | 1,790,387 | 634,099 | ||||||
Purchase of minerals in place | 63,928 | 59,689 | ||||||
Extensions and discoveries | 149,533 | — | ||||||
Production | (407,415 | ) | (414,730 | ) | ||||
Balance at December 31, 2009 | 8,092,582 | 4,503,091 | ||||||
Revisions of previous estimates | 659,977 | 1,041,826 | ||||||
Production | (494,876 | ) | (446,979 | ) | ||||
Balance at December 31, 2010 | 8,257,683 | 5,097,938 | ||||||
Proved developed reserves: | ||||||||
December 31, 2007 | 6,877,406 | 4,116,158 | ||||||
December 31, 2008 | 5,770,190 | 3,928,995 | ||||||
December 31, 2009 | 6,729,632 | 3,854,008 | ||||||
December 31, 2010 | 6,799,873 | 3,992,358 | ||||||
Proved undeveloped reserves: | ||||||||
December 31, 2007 | 577,100 | 258,158 | ||||||
December 31, 2008 | 725,959 | 295,038 | ||||||
December 31, 2009 | 1,362,950 | 649,083 | ||||||
December 31, 2010 | 1,457,810 | 1,105,580 | ||||||
VOC F-21
Table of Contents
FROM PROVED OIL AND GAS RESERVES
VOC F-22
Table of Contents
2008 | 2009 | 2010 | ||||||||||
Future cash inflows | $ | 285,599,020 | $ | 479,804,227 | $ | 648,185,108 | ||||||
Future costs | ||||||||||||
Production | (152,898,120 | ) | (192,121,342 | ) | (223,916,334 | ) | ||||||
Development | (12,501,184 | ) | (25,183,887 | ) | (25,384,253 | ) | ||||||
Future net cash flows | 120,199,716 | 262,498,998 | 398,884,521 | |||||||||
Less 10% discount factor | (60,259,262 | ) | (142,117,093 | ) | (218,408,117 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 59,940,454 | $ | 120,381,905 | $ | 180,476,404 | ||||||
FLOWS FROM PROVED OIL AND GAS RESERVES
2008 | 2009 | 2010 | ||||||||||
Standardized measure at beginning of year | $ | 206,509,831 | $ | 59,940,454 | $ | 120,381,905 | ||||||
Sales of oil and gas produced, net of production costs | (29,744,163 | ) | (15,788,110 | ) | (29,265,616 | ) | ||||||
Net changes in price and production costs | (154,951,804 | ) | 41,451,566 | 52,703,598 | ||||||||
Extensions, discoveries and improved recovery, net of future production and development costs | 5,822 | 5,890,961 | — | |||||||||
Changes in estimated future development costs | (2,726,749 | ) | (14,381,027 | ) | (14,568,030 | ) | ||||||
Development costs incurred during the period which reduce future development costs | 52,800 | 2,700,100 | 7,599,939 | |||||||||
Revisions of quantity estimates | (7,982,910 | ) | 29,413,203 | 15,664,245 | ||||||||
Accretion of discount | 20,650,983 | 5,994,045 | 12,038,190 | |||||||||
Purchase of reserves in place | 4,831,610 | 1,567,625 | — | |||||||||
Change in production rates, timing and other | 23,295,034 | 3,593,088 | 15,922,173 | |||||||||
Standardized measure at end of year | $ | 59,940,454 | $ | 120,381,905 | $ | 180,476,404 | ||||||
VOC F-23
Table of Contents
VOC F-24
Table of Contents
December 31, 2010 | ||||||||||||||||||||
Additional | Pro Forma | |||||||||||||||||||
Historical | Adjustments (a) | Pro Forma | Adjustments | as Adjusted | ||||||||||||||||
Cash and cash equivalents | $ | 11,594,345 | $ | — | $ | 11,594,345 | $ | — | (b) | $ | 11,594,345 | |||||||||
Accounts receivable — oil and gas sales | 1,091,745 | 1,198,682 | 2,290,427 | — | 2,290,427 | |||||||||||||||
Accounts receivable — oil and gas sales — related parties | 3,645,127 | 993,178 | 4,638,305 | — | 4,638,305 | |||||||||||||||
Receivable from Trust | — | — | — | 349,674 | (d) | 349,674 | ||||||||||||||
Note receivable — related parties | — | — | — | 38,786,916 | (c) | 38,786,916 | ||||||||||||||
Oil Swap agreements | 182,817 | — | 182,817 | — | 182,817 | |||||||||||||||
Prepaid expenses | 84,627 | — | 84,627 | — | 84,627 | |||||||||||||||
Total current assets | 16,598,661 | 2,191,860 | 18,790,521 | 39,136,590 | 57,927,111 | |||||||||||||||
OIL AND GAS PROPERTIES | 119,848,855 | 90,941,091 | 210,789,946 | (168,631,957 | )(d) | 42,157,989 | ||||||||||||||
Less accumulated depreciation, depletion and amortization | 28,174,233 | — | 28,174,233 | (22,539,386 | ) (d) | 5,634,847 | ||||||||||||||
91,674,622 | 90,941,091 | 182,615,713 | (146,092,571 | ) (d) | 36,523,142 | |||||||||||||||
OTHER ASSETS | ||||||||||||||||||||
Receivable from Trust | — | — | — | 1,352,490 | (d) | 1,352,490 | ||||||||||||||
Deferred loan costs, net of accumulated amortization of $1,403,726 | 555,155 | — | 555,155 | — | 555,155 | |||||||||||||||
Deferred offering costs | 209,272 | — | 209,272 | (209,272 | ) (e) | — | ||||||||||||||
764,427 | — | 764,427 | 1,143,218 | 1,907,645 | ||||||||||||||||
$ | 109,037,710 | $ | 93,132,951 | $ | 202,170,661 | $ | (105,812,763 | ) | $ | 96,357,898 | ||||||||||
LIABILITIES AND PARTNERS’ CAPITAL/COMMON CONTROL OWNERS’ EQUITY (DEFICIT) | ||||||||||||||||||||
CURRENT LIABILITIES | ||||||||||||||||||||
Accounts payable | ||||||||||||||||||||
Trade | $ | 68,854 | $ | 15,798 | $ | 84,652 | $ | — | $ | 84,652 | ||||||||||
Related parties | 770,513 | 626,830 | 1,397,343 | — | 1,397,343 | |||||||||||||||
Accrued interest | 63,742 | — | 63,742 | — | 63,742 | |||||||||||||||
Settlement payable on oil swap agreements | 228,961 | — | 228,961 | — | 228,961 | |||||||||||||||
Distributions payable | 9,995,900 | 1,549,232 | 11,545,132 | — | 11,545,132 | |||||||||||||||
Accrued ad valorem taxes | 499,596 | 491,392 | 990,988 | — | 990,988 | |||||||||||||||
Other accrued liabilities | 233,531 | 261,964 | 495,495 | — | 495,495 | |||||||||||||||
Due to Trust | — | — | — | 146,254 | (d) | 146,254 | ||||||||||||||
Deferred gain on sale | — | — | — | 8,759,435 | (e) | 8,759,435 | ||||||||||||||
Total current liabilities | 11,861,097 | 2,945,216 | 14,806,313 | 8,905,689 | 23,712,002 | |||||||||||||||
LONG-TERM LIABILITIES, less current maturities | ||||||||||||||||||||
Notes payable | 24,000,000 | — | 24,000,000 | (24,000,000 | ) (b) | — | ||||||||||||||
Deferred gain on sale | — | — | — | 95,586,548 | (e) | 95,586,548 | ||||||||||||||
Asset retirement obligation | 2,240,501 | 1,564,872 | 3,805,373 | — | 3,805,373 | |||||||||||||||
26,240,501 | 1,564,872 | 27,805,373 | 71,586,548 | 99,391,921 | ||||||||||||||||
PARTNERS’ CAPITAL/COMMON CONTROL OWNERS’ EQUITY (DEFICIT) | ||||||||||||||||||||
General partner capital account | 571,419 | — | 571,419 | (1,483,360 | )(f) | (911,941 | ) | |||||||||||||
Limited partner capital account | 51,213,862 | — | 51,213,862 | (72,695,279 | ) (g) | (21,481,417 | ) | |||||||||||||
Common control owners’ equity | 19,228,511 | 88,622,863 | 107,851,374 | (112,126,361 | ) (h) | (4,274,987 | ) | |||||||||||||
Accumulated other comprehensive loss | (77,680 | ) | — | (77,680 | ) | — | (77,680 | ) | ||||||||||||
70,936,112 | 88,622,863 | 159,558,975 | (186,305,000 | ) | (26,746,025 | ) | ||||||||||||||
$ | 109,037,710 | $ | 93,132,951 | $ | 202,170,661 | $ | (105,812,763 | ) | $ | 96,357,898 | ||||||||||
VOC F-25
Table of Contents
Year Ended December 31, 2010 | ||||||||||||||||||||
Pro | ||||||||||||||||||||
(a) | Pro | Additional | Forma as | |||||||||||||||||
Historical | Adjustments | Forma | Adjustments | Adjusted | ||||||||||||||||
Revenues | ||||||||||||||||||||
Oil and gas sales | $ | 38,603,599 | $ | 24,114,838 | $ | 62,718,437 | $ | (50,174,750 | )(i) | $ | 12,543,687 | |||||||||
Gain on sale of assets | — | — | — | 9,423,003 | (j) | 9,423,003 | ||||||||||||||
Other | 31,749 | — | 31,749 | — | 31,749 | |||||||||||||||
38,635,348 | 24,114,838 | 62,750,186 | (40,751,747 | ) | 21,998,439 | |||||||||||||||
Costs and expenses | ||||||||||||||||||||
Lease operating | 7,325,042 | 6,401,986 | 13,727,028 | (10,981,622 | )(k) | 2,745,406 | ||||||||||||||
Production and property taxes | 2,720,313 | 1,416,534 | 4,136,847 | (3,309,478 | )(l) | 827,369 | ||||||||||||||
Depreciation, depletion, amortization and accretion | 6,252,676 | 6,583,585 | 12,836,261 | (9,856,928 | )(m) | 2,979,333 | ||||||||||||||
Interest expense | 1,221,373 | — | 1,221,373 | — | 1,221,373 | |||||||||||||||
General and administrative | 204,575 | — | 204,575 | — | 204,575 | |||||||||||||||
Total costs and expenses | 17,723,979 | 14,402,105 | 32,126,084 | (24,148,028 | ) | 7,978,056 | ||||||||||||||
Net earnings | $ | 20,911,369 | $ | 9,712,733 | $ | 30,624,102 | $ | (16,603,719 | ) | $ | 14,020,383 | |||||||||
VOC F-26
Table of Contents
VOC F-27
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, 2010), liabilities, owners’ equity and oil and gas revenues and related expenses. |
December 31, 2010 | ||||||
(b) | Gross cash proceeds from the sale of the trust units | $ | 215,681,600 | |||
Cash down payment from VOC Sponsor on related party note | 11,511,840 | |||||
Repayment of outstanding borrowing on credit facility | (24,000,000 | ) | ||||
Payment of underwriting discount, structuring fee and other offering expenses | 16,888,440 | (1) | ||||
Distribution to partners | (186,305,000 | ) | ||||
$ | — | |||||
(c) | Receivable from VOC Sponsor for sale of 34.8% of trust units at historical value | $ | 50,298,756 | |||
Cash down payment on receivable | 11,511,840 | |||||
Remaining receivable from VOC Sponsor for sale of 34.8% of trust units | $ | 38,786,916 | ||||
(d) | Current payable for conveyance of oil swap agreements to the Trust | $ | 146,254 | |||
Long-term payable for conveyance of oil swap agreements to the Trust | — | |||||
$ | 146,254 | |||||
Reduction of oil and gas properties due to conveyance of Net Profits Interest | $ | (168,631,957 | ) | |||
Reduction of associated accumulated depreciation, depletion, and amortization | 22,539,386 | |||||
$ | (146,092,571 | ) | ||||
Current receivable from Trust for conveyance of asset retirement obligations | $ | 349,674 | ||||
Long-term receivable from Trust for conveyance of asset retirement obligations | 1,352,490 | |||||
$ | 1,702,164 | |||||
Net oil and gas properties and equipment | $ | 182,615,713 | ||||
Asset retirement obligation liability | (2,127,700 | ) | ||||
Oil swap agreements | 182,817 | |||||
180,670,830 | ||||||
80% Net Profits Interest | $ | 144,536,664 | ||||
(e) | Deferred gain on sale of Net Profits Interest is calculated as follows: | |||||
Gross cash proceeds from the sale of the trust units | $ | 215,681,600 | ||||
Less: Net book value of conveyed Net Profits Interests | (94,237,905 | ) | ||||
Payment of underwriting discounts, structuring fees and other offering expenses | (16,888,440 | ) (1) | ||||
Deferred transaction fees and costs incurred as of December 31, 2010 | (209,272 | ) | ||||
Deferred gain on sale | $ | 104,345,983 | ||||
Current portion of deferred gain | $ | 8,759,435 | ||||
Long-term portion of deferred gain | $ | 95,586,548 | ||||
(f) | To record distribution of remaining cash to general partner | $ | (1,483,360 | ) | ||
(g) | To record distribution of remaining cash to limited partner | $ | (72,695,279 | ) | ||
(h) | To record distribution of remaining cash to common control owners | $ | (112,126,361 | ) | ||
(1) | Includes offering expenses of $829,959 incurred by VOC Kansas Energy Partners, LLC. |
VOC F-28
Table of Contents
Year Ended | ||||||
December 31, 2010 | ||||||
(i) | Decrease in oil and gas sales attributable to Net Profits Interest | $ | (50,174,750 | ) | ||
(j) | To record amortization of gain on sale of trust units over the life of the trust | $ | 9,423,003 | |||
(k) | Decrease in lease operating expenses attributable to the Net Profits Interest | $ | (10,981,622 | ) | ||
(l) | Decrease in production and property taxes attributable to the Net Profits Interest | $ | (3,309,478 | ) | ||
(m) | Reduce depreciation on assets sold to Trust | $ | (9,856,928 | ) | ||
VOC F-29
Table of Contents
Re: | Evaluation Summary VOC Brazos Energy Partners, L.P. Interests Total Proved Reserves As of December 31, 2010 | |||
Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue |
Proved | Proved | |||||||||||||||||
Developed | Developed | Proved | Total | |||||||||||||||
Producing | Non-Producing | Undeveloped | Proved | |||||||||||||||
Net Reserves | ||||||||||||||||||
Oil | — Mbbl | 3,879.6 | 258.8 | 1,338.0 | 5,479.4 | |||||||||||||
Gas | — MMcf | 2,161.0 | 132.3 | 1,105.6 | 3,398.8 | |||||||||||||
Revenue | ||||||||||||||||||
Oil | — M$ | 291,669.2 | 19,410.2 | 102,474.8 | 413,554.3 | |||||||||||||
Gas | — M$ | 15,898.8 | 983.5 | 8,220.8 | 25,103.1 | |||||||||||||
Severance Taxes | — M$ | 13,754.6 | 966.6 | 5,330.4 | 20,051.6 | |||||||||||||
AdValorem Taxes | — M$ | 8,485.8 | 551.2 | 3,466.5 | 12,503.5 | |||||||||||||
Operating Expenses | — M$ | 84,055.8 | 4,156.3 | 6,465.3 | 94,677.3 | |||||||||||||
Workover Expenses | — M$ | 3,933.7 | 0.0 | 0.0 | 3,933.7 | |||||||||||||
Other Deductions | — M$ | 4,518.2 | 256.0 | 309.9 | 5,084.2 | |||||||||||||
Investments | — M$ | 0.0 | 1,467.4 | 22,505.6 | 23,973.0 | |||||||||||||
Net Operating Income | — M$ | 192,819.8 | 12,996.2 | 72,618.0 | 278,434.0 | |||||||||||||
Discounted @ 10% (Present Worth) | — M$ | 81,812.5 | 7,293.0 | 31,050.2 | 120,155.6 |
Annex A-1
Table of Contents
December 28, 2010
Annex A-2
Table of Contents
December 28, 2010
Annex A-3
Table of Contents
December 28, 2010
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Texas Registered Engineering Firm F-693
W. Todd Brooker, P. E. Vice President |
Annex A-4
Table of Contents
Description of Table Information
Identity of Interest Evaluated
Reserve Classification and Development Status
Property Description — Location
Effective Date of Evaluation
(Columns) | ||||
(1)(11)(21) | Calendar orFiscalyears/months commencing on effective date. | |||
(2)(3)(4) | Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts. | |||
(5)(6)(7) | Net Productionaccruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage. | |||
(8) | Average (volume weighted)gross liquid price per barrel before deducting production-severance taxes. | |||
(9) | Average (volume weighted)gross gas price per Mcf before deducting production-severance taxes. | |||
(10) | Average (volume weighted)gross NGL price per barrel before deducting production-severance taxes. | |||
(12) | Revenue derived from oil sales — column(5) times column(8). | |||
(13) | Revenuederived from gas sales — column(6) times column(9). | |||
(14) | Revenuederived from NGL sales — column(7) times column(10). | |||
(15) | Revenue derived from hedge positions. | |||
(16) | Revenue derived from other sourcesnot included in column (12) through column (15); may include revenue from electrical sales, pipeline gas transportation, 3rd party saltwater disposal, etc. | |||
(17) | Total Revenue — sum of column (12) through column(16). | |||
(18) | Production-Severance taxes deducted from gross oil, gas and NGL revenue. | |||
(19) | Ad Valorem taxes. | |||
(20) | $/BOE6 — is the total of column (22), column (25), column (26), and column (27) divided by Barrels of Oil Equivalent (“BOE”). BOE is net oil production column(5) plus net gas production column(6) converted to oil at six Mcf gas per one bbl oil plus net NGL production column(7) converted to oil at one bbl NGL per 0.65 bbls of oil. | |||
(22) | Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS. |
Cawley, Gillespie & Associates, Inc. | Page 1 |
Annex A-5
Table of Contents
(23) | Averagegross wells. | |||
(24) | Averagenet wells are gross wells times working interest. | |||
(25) | Workover Expensesare non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair. | |||
(26) | COPAS expenses are fixed rate administrative overhead charges for company operated producing properties. | |||
(27) | Other Deductions includes fixed rate overhead charges for operated oil and gas producers as per the JOA. | |||
(28) | Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life. | |||
(29)(30) | Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered. | |||
(31) | Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates. | |||
MISCELLANEOUS | ||||
DCF Profile | • The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns(30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile. | |||
Life | • The economic life of the appraised property is noted in the lower right-hand corner of the table. | |||
Footnotes | • Comments regarding the evaluation may be shown in the lower left-hand footnotes. | |||
Price Deck | • A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes. | |||
Differentials | • Total annual price adjustments may be shown in gray font to the left of column(8), column(9) and column(10). |
Cawley, Gillespie & Associates, Inc. | Page 2 |
Annex A-6
Table of Contents
Cawley, Gillespie & Associates, Inc. | Page 3 |
Annex A-7
Table of Contents
Cawley, Gillespie & Associates, Inc. | Page 4 |
Annex A-8
Table of Contents
Cawley, Gillespie & Associates, Inc. | Page 5 |
Annex A-9
Table of Contents
Cawley, Gillespie & Associates, Inc. | Page 6 |
Annex A-10
Table of Contents
Cawley, Gillespie & Associates, Inc. | Page 7 |
Annex A-11
Table of Contents
Cawley, Gillespie & Associates, Inc. | Page 8 |
Annex A-12
Table of Contents
Re: | Evaluation Summary VOC Kansas Energy Partners, LLC Total Proved Reserves As of December 31, 2010 | |||
Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue |
Proved | Proved | |||||||||||||||
Developed | Developed | Proved | Total | |||||||||||||
Producing | Non-Producing | Undeveloped | Proved | |||||||||||||
Net Reserves | ||||||||||||||||
Oil | 6,696.6 | 136.3 | 232.3 | 7,065.3 | ||||||||||||
Gas | 3,550.5 | 0.0 | 0.0 | 3,550.5 | ||||||||||||
Revenue | ||||||||||||||||
Oil | 488,614.9 | 9,862.5 | 16,803.3 | 515,280.6 | ||||||||||||
Gas | 13,285.0 | 0.0 | 0.0 | 13,285.0 | ||||||||||||
Severance Taxes | 4,486.1 | 0.0 | 436.2 | 4,922.3 | ||||||||||||
Ad Valorem Taxes | 16,339.7 | 295.9 | 504.1 | 17,139.7 | ||||||||||||
Operating Expenses | 164,009.5 | 133.3 | 3,658.8 | 167,801.7 | ||||||||||||
Workover Expenses | 12,159.0 | 347.8 | 0.0 | 12,506.9 | ||||||||||||
COPAS | 31,639.5 | 0.0 | 0.0 | 31,639.5 | ||||||||||||
Investments | 0.0 | 716.6 | 2,443.8 | 3,160.4 | ||||||||||||
Net Operating Income | 273,266.1 | 8,368.9 | 9,760.3 | 291,395.3 | ||||||||||||
Discounted @ 10% (Present Worth) | 138,869.4 | 4,163.6 | 5,094.3 | 148,127.3 |
Annex B-1
Table of Contents
December 28, 2010
Annex B-2
Table of Contents
December 28, 2010
Annex B-3
Table of Contents
December 28, 2010
Texas Registered Engineering Firm F-693
W. Todd Brooker, P. E. Vice President |
Annex B-4
Table of Contents
Description of Table Information
Identity of Interest Evaluated
Reserve Classification and Development Status
Property Description — Location
Effective Date of Evaluation
(Columns) | ||||
(1)(11)(21) | Calendar orFiscalyears/months commencing on effective date. | |||
(2)(3)(4) | Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts. | |||
(5)(6)(7) | Net Productionaccruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage. | |||
(8) | Average (volume weighted)gross liquid price per barrel before deducting production-severance taxes. | |||
(9) | Average (volume weighted)gross gas price per Mcf before deducting production-severance taxes. | |||
(10) | Average (volume weighted)gross NGL price per barrel before deducting production-severance taxes. | |||
(12) | Revenue derived from oil sales — column (5) times column (8). | |||
(13) | Revenuederived from gas sales — column (6) times column (9). | |||
(14) | Revenuederived from NGL sales — column (7) times column (10). | |||
(15) | Revenue derived from hedge positions. | |||
(16) | Revenue derived from other sourcesnot included in column (12) through column (15); may include revenue from electrical sales, pipeline gas transportation, 3rd party saltwater disposal, etc. | |||
(17) | Total Revenue — sum of column (12) through column (16). | |||
(18) | Production-Severance taxes deducted from gross oil, gas and NGL revenue. | |||
(19) | Ad Valorem taxes. | |||
(20) | $/BOE6 — is the total of column (22), column (25), column (26), and column (27) divided by Barrels of Oil Equivalent (“BOE”). BOE is net oil production column (5) plus net gas production column (6) converted to oil at six Mcf gas per one bbl oil plus net NGL production column (7) converted to oil at one bbl NGL per 0.65 bbls of oil. | |||
(22) | Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS. |
Cawley, Gillespie & Associates, Inc. | Page 1 |
Annex B-5
Table of Contents
(23) | Averagegross wells. | |||
(24) | Averagenet wells are gross wells times working interest. | |||
(25) | Workover Expensesare non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair. | |||
(26) | COPAS expenses are fixed rate administrative overhead charges for company operated producing properties. | |||
(27) | Other Deductions includes fixed rate overhead charges for operated oil and gas producers as per the JOA. | |||
(28) | Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life. | |||
(29)(30) | Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered. | |||
(31) | Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates. | |||
MISCELLANEOUS | ||||
DCF Profile | • The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns(30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile. | |||
Life | • The economic life of the appraised property is noted in the lower right-hand corner of the table. | |||
Footnotes | • Comments regarding the evaluation may be shown in the lower left-hand footnotes. | |||
Price Deck | • A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes. | |||
Differentials | • Total annual price adjustments may be shown in gray font to the left of column (8), column (9) and column (10). |
Cawley, Gillespie & Associates, Inc. | Page 2 |
Annex B-6
Table of Contents
Cawley, Gillespie & Associates, Inc. | Page 3 |
Annex B-7
Table of Contents
Cawley, Gillespie & Associates, Inc. | Page 4 |
Annex B-8
Table of Contents
Cawley, Gillespie & Associates, Inc. | Page 5 |
Annex B-9
Table of Contents
Cawley, Gillespie & Associates, Inc. | Page 6 |
Annex B-10
Table of Contents
Cawley, Gillespie & Associates, Inc. | Page 7 |
Annex B-11
Table of Contents
Re: | Evaluation Summary VOC Energy Trust Net Profits Interests Total Proved Reserves Certain Oil and Gas Assets — KS & TX As of December 31, 2010 | |||
Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue |
Proved | Proved | |||||||||||||||||
Developed | Developed | Proved | Total | |||||||||||||||
Producing | Non-Producing | Undeveloped | Proved | |||||||||||||||
Net Reserves | ||||||||||||||||||
Oil | — MBBL | 7,924.5 | 371.5 | 1,343.6 | 9,639.6 | |||||||||||||
Gas | — MMCF | 4,953.0 | 132.3 | 938.7 | 6,024.0 | |||||||||||||
Revenue | ||||||||||||||||||
Oil | — M$ | 583,748.3 | 27,566.4 | 102,017.1 | 713,331.8 | |||||||||||||
Gas | — M$ | 24,917.8 | 983.5 | 6,979.8 | 32,881.1 | |||||||||||||
Severance Taxes | — M$ | 13,472.1 | 966.6 | 4,904.0 | 19,342.7 | |||||||||||||
Ad Valorem Taxes | — M$ | 19,118.9 | 795.8 | 3,393.6 | 23,308.3 | |||||||||||||
Operating Expenses | — M$ | 157,288.9 | 4,209.4 | 5,923.2 | 167,421.5 | |||||||||||||
Workover Expenses | — M$ | 10,210.8 | 347.8 | 0.0 | 10,558.6 | |||||||||||||
COPAS | — M$ | 23,909.1 | 256.0 | 162.3 | 24,327.4 | |||||||||||||
Investments | — M$ | 0.0 | 2,184.0 | 24,949.4 | 27,133.4 | |||||||||||||
80% NPI Net Operating Income (BFIT) | — M$ | 307,733.0 | 15,832.1 | 55,731.6 | 379,296.6 | |||||||||||||
80% NPI Disc. @ 10% | — M$ | 171,454.1 | 9,079.3 | 28,019.1 | 208,552.5 |
Annex C-1
Table of Contents
December 28, 2010
Annex C-2
Table of Contents
December 28, 2010
Annex C-3
Table of Contents
December 28, 2010
Texas Registered Engineering Firm (F-693)
W. Todd Brooker, P.E. Vice President |
Annex C-4
Table of Contents
Description of Table Information
Identity of Interest Evaluated
Reserve Classification and Development Status
Property Description — Location
Effective Date of Evaluation
(Columns) | ||||
(1)(11)(21) | Calendar orFiscalyears/months commencing on effective date. | |||
(2)(3)(4) | Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts. | |||
(5)(6)(7) | Net Productionaccruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage. | |||
(8) | Average (volume weighted)gross liquid price per barrel before deducting production-severance taxes. | |||
(9) | Average (volume weighted)gross gas price per Mcf before deducting production-severance taxes. | |||
(10) | Average (volume weighted)gross NGL price per barrel before deducting production-severance taxes. | |||
(12) | Revenue derived from oil sales — column (5) times column (8). | |||
(13) | Revenuederived from gas sales — column (6) times column (9). | |||
(14) | Revenuederived from NGL sales — column (7) times column (10). | |||
(15) | Revenue derived from hedge positions. | |||
(16) | Revenue derived from other sourcesnot included in column (12) through column (15); may include revenue from electrical sales, pipeline gas transportation, 3rd party saltwater disposal, etc. | |||
(17) | Total Revenue — sum of column (12) through column (16). | |||
(18) | Production-Severance taxes deducted from gross oil, gas and NGL revenue. | |||
(19) | Ad Valorem taxes. | |||
(20) | $/BOE6 — is the total of column (22), column (25), column (26), and column (27) divided by Barrels of Oil Equivalent (“BOE”). BOE is net oil production column (5) plus net gas production column (6) converted to oil at six Mcf gas per one bbl oil plus net NGL production column (7) converted to oil at one bbl NGL per 0.65 bbls of oil. | |||
(22) | Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS. |
Cawley, Gillespie & Associates, Inc. | Page 1 |
Annex C-5
Table of Contents
(23) | Averagegross wells. | |||
(24) | Averagenet wells are gross wells times working interest. | |||
(25) | Workover Expensesare non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair. | |||
(26) | COPAS expenses are fixed rate administrative overhead charges for company operated producing properties. | |||
(27) | Other Deductions includes fixed rate overhead charges for operated oil and gas producers as per the JOA. | |||
(28) | Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life. | |||
(29)(30) | Future Net Cash Flow is column (18) less the total of column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered. | |||
(31) | Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates. | |||
MISCELLANEOUS | ||||
DCF Profile | • The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns(30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile. | |||
Life | • The economic life of the appraised property is noted in the lower right-hand corner of the table. | |||
Footnotes | • Comments regarding the evaluation may be shown in the lower left-hand footnotes. | |||
Price Deck | • A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes. | |||
Differentials | • Total annual price adjustments may be shown in gray font to the left of column (8), column (9) and column (10). |
Cawley, Gillespie & Associates, Inc. | Page 2 |
Annex C-6
Table of Contents
Cawley, Gillespie & Associates, Inc. | Page 3 |
Annex C-7
Table of Contents
Cawley, Gillespie & Associates, Inc. | Page 4 |
Annex C-8
Table of Contents
Cawley, Gillespie & Associates, Inc. | Page 5 |
Annex C-9
Table of Contents
Cawley, Gillespie & Associates, Inc. | Page 6 |
Annex C-10
Table of Contents
Cawley, Gillespie & Associates, Inc. | Page 7 |
Annex C-11
Table of Contents
RAYMOND JAMES | MORGAN STANLEY |
OPPENHEIMER & CO. |
RBC CAPITAL MARKETS |
BAIRD |
JANNEY MONTGOMERY SCOTT |
MORGAN KEEGAN |
WUNDERLICH SECURITIES |
Table of Contents
Item 13. | Other Expenses of Issuance and Distribution. |
Registration fee | $ | 30,240 | ||
FINRA filing fee | 26,546 | |||
NYSE listing fee | 125,000 | |||
Printing and engraving expenses | 450,000 | |||
Fees and expenses of legal counsel | 1,000,000 | |||
Accounting fees and expenses | 550,000 | |||
Transfer agent and registrar fees | 5,150 | |||
Trustee fees and expenses | 87,500 | |||
Miscellaneous | 25,564 | |||
Total | $ | 2,300,000 | ||
Item 14. | Indemnification of Directors and Officers. |
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*** | — | First Amendment to Contribution and Exchange Agreement entered into as of April 11, 2011 by and among VOC Brazos Energy Partners, L.P., VOC Kansas Energy Partners, LLC,VAP-III, LLC, Vess Texas Acquisition Group, LLC, Vess Texas Partners, LLC and the other parties named therein. | |||
3 | .4* | — | Certificate of Trust of VOC Energy Trust. | |||
3 | .5* | — | Trust Agreement dated November 3, 2010 among VOC Brazos Energy Partners, L.P., as trustor, and Wilmington Trust Company, and The Bank of New York Mellon Trust Company, N.A., as trustees. | |||
3 | .6*** | — | Form of Amended and Restated Trust Agreement. | |||
5 | .1*** | — | Opinion of Morris James LLP relating to the validity of the trust units. | |||
8 | .1*** | — | Opinion of Vinson & Elkins L.L.P. relating to tax matters. | |||
10 | .1* | — | Credit Agreement dated as of June 27, 2008 among VOC Brazos Energy Partners, L.P., as borrower, Bank of America, N.A., as lender, and the other parties named therein. | |||
10 | .2* | — | First Amendment to Credit Agreement dated August 12, 2008 by and among VOC Brazos, LP (now VOC Brazos, LLC), as borrower, Bank of America, N.A. and the other parties named therein. | |||
10 | .3*** | — | Form of Term Net Profits Interest Conveyance. | |||
10 | .4*** | — | Form of Administrative Services Agreement. | |||
10 | .5*** | — | Form of Registration Rights Agreement. | |||
21 | .1* | — | Subsidiaries of VOC Brazos Energy Partners, L.P. | |||
23 | .1*** | — | Consent of Grant Thornton LLP | |||
23 | .2*** | — | Consent of Morris James LLP (contained in Exhibit 5.1). | |||
23 | .3*** | — | Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1). | |||
23 | .4*** | — | Consent of Cawley, Gillespie & Associates, Inc. | |||
99 | .1*** | — | Summary Reserve Reports of Cawley, Gillespie & Associates, Inc. (included as Annexes A, B, C to the prospectus) |
* | Previously filed with the Registration Statement (File No. 333-171474) on December 30, 2010. |
** | To be filed by amendment |
*** | 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 Sole Managing Member |
II-4
Table of Contents
By: | The Bank of New York Mellon Trust Company, N.A. |
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*** | — | First Amendment to Contribution and Exchange Agreement entered into as of April 11, 2011 by and among VOC Brazos Energy Partners, L.P., VOC Kansas Energy Partners, LLC,VAP-III, LLC, Vess Texas Acquisition Group, LLC, Vess Texas Partners, LLC and the other parties named therein. | |||
3 | .4* | — | Certificate of Trust of VOC Energy Trust. | |||
3 | .5* | — | Trust Agreement dated November 3, 2010 among VOC Brazos Energy Partners, L.P., as trustor, and Wilmington Trust Company, and The Bank of New York Mellon Trust Company, N.A., as trustees. | |||
3 | .6*** | — | Form of Amended and Restated Trust Agreement. | |||
5 | .1*** | — | Opinion of Morris James LLP relating to the validity of the trust units. | |||
8 | .1*** | — | Opinion of Vinson & Elkins L.L.P. relating to tax matters. | |||
10 | .1* | — | Credit Agreement dated as of June 27, 2008 among VOC Brazos Energy Partners L.P., as borrower, Bank of America, N.A., as lender, and the other parties named therein. | |||
10 | .2* | — | First Amendment to Credit Agreement dated August 12, 2008 by and among VOC Brazos, LP (now VOC Brazos, LLC), as borrower, Bank of America, N.A. and the other parties named therein. | |||
10 | .3*** | — | Form of Term Net Profits Interest Conveyance. | |||
10 | .4*** | — | Form of Administrative Services Agreement. | |||
10 | .5*** | — | Form of Registration Rights Agreement. | |||
21 | .1* | — | Subsidiaries of VOC Brazos Energy Partners, L.P. | |||
23 | .1*** | — | Consent of Grant Thornton LLP | |||
23 | .2*** | — | Consent of Morris James LLP (contained in Exhibit 5.1). | |||
23 | .3*** | — | Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1). | |||
23 | .4*** | — | Consent of Cawley, Gillespie & Associates, Inc. | |||
99 | .1*** | — | Summary Reserve Reports of Cawley, Gillespie & Associates, Inc. (included as Annex A to the prospectus). |
* | Previously filed with Registration Statement (File No.333-171474) on December 30, 2010. |
** | To be filed by amendment |
*** | Filed herewith |