UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10
GENERAL FORM FOR REGISTRATION OF SECURITIES
Pursuant to Section 12(b) or (g) of the
Securities Exchange Act of 1934
MEWBOURNE ENERGY PARTNERS 09-A, L.P.
(Exact name of registrant as specified in its charter)
| | |
| Delaware | | 26-4280211 |
(State or other jurisdiction of incorporation) | | (I.R.S. Employer Identification Number) |
| |
| 3901 South Broadway, Tyler, Texas | | 75701 |
| (Address of principal executive offices) | | (Zip code) |
(903) 561-2900
(Registrant’s telephone number, including area code)
Securities to be registered pursuant to Section 12(b) of the Act: None
Securities to be registered pursuant to Section 12(g) of the Act:
Limited Partner Interests
(Title of class)
General Partner Interests
(Title of class)
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
| | | | | | |
| Large accelerated filer | | ¨ | | Accelerated filer | | ¨ |
| | | |
| Non-accelerated filer | | ¨ (Do not check if a smaller reporting company) | | Smaller reporting company | | x |
TABLE OF CONTENTS
i
FORWARD-LOOKING STATEMENTS
Forward-looking statements are inherently uncertain. Some statements in this Registration Statement constitute forward-looking statements. These forward-looking statements include, but are not limited to, statements about the industry, plans, objectives, expectations, intentions and assumptions of Mewbourne Energy Partners 09-A, L.P. (the “Registrant” or the “Partnership”) and other statements contained herein that are not historical facts. When used in this Registration Statement, the words “expect,” “anticipate,” “intend,” “plan,” “believe,” “seek,” “estimate” and similar expressions are generally intended to identify forward-looking statements. Because these forward-looking statements involve risks and uncertainties, actual results may differ materially from those expressed or implied by these forward-looking statements. The Registrant does not intend to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
1
General
The Registrant is a limited partnership that was organized under the laws of the State of Delaware on February 26, 2009 in accordance with the laws of the State of Delaware. Mewbourne Development Corporation (“MD” or the “Managing Partner”), a Delaware corporation, has been appointed as the Registrant’s managing general partner. MD has no equity interest in the Registrant.
Limited and general partner interests in the Registrant were offered at $5,000 each to accredited investors in a private placement pursuant to Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”), and Regulation D promulgated thereunder, with a maximum offering amount of $73,000,000 (14,600 interests). On August 28, 2009, the offering of limited and general partnership interests in the Registrant was closed, with interests aggregating $66,210,000 originally being sold to accredited investors of which $62,140,000 were sold to accredited investors as general partner interests and $4,070,000 were sold to accredited investors as limited partner interests.
The Registrant engages primarily in oil and gas drilling and development activities with a concentration on gas under a drilling program (the “Program”), and it is not involved in any other industry segment. The Program is governed by a Drilling Program Agreement (the “Drilling Program Agreement”) between the Registrant, MD and Mewbourne Oil Company (“MOC” or the “Program Manager”), the program manager and a wholly-owned, indirect subsidiary of Mewbourne Holdings, Inc., which is also the parent of MD. MD does not make any capital contributions directly to the Registrant; rather MD makes its capital contributions directly to the Program. See the organizational structure chart of the various Mewbourne companies below. See also the financial statements in Item 13 of this Registration Statement for a summary of the Registrant’s revenue, income and identifiable assets.
OWNERSHIP STRUCTURE OF THE MEWBOURNE COMPANIES
Corporate Structure
2
Proposed Operations
Under the Drilling Program Agreement referenced above, the activities of the Partnership focus upon the acquisition of oil and gas leases covering prospects with a concentration on gas, the drilling of development wells, and the production and operation of the resulting properties. In addition to development wells, at the discretion of the Managing Partner, up to 20% of the Partnership’s capital contributions may be expended in connection with activities relating to exploratory wells. All drilling activities involve a high degree of risk, with exploratory wells presenting a higher degree of risk than development wells.
As of December 31, 2009, the Partnership had seven wells producing, five wells in drilling operations and one well that was plugged and abandoned for a total of thirteen wells in which the Partnership owns an interest. These wells are located in West Texas and Southeastern New Mexico in an area known as the Permian Basin and in Western Oklahoma and the Texas Panhandle in an area known as the Anadarko Basin.
The Managing Partner intends to cause the Partnership to engage in drilling for oil and gas, with a concentration on gas, on a number of additional prospects, none of which is yet determined. It is impossible at this time to predict with certainty the additional drilling activities that will be conducted by the Partnership.
Decisions as to the number and location of the prospects in which the Partnership will ultimately invest and as to the amounts spent on drilling are made solely by the Managing Partner for the Partnership and by the Program Manager on behalf of the Program. The Managing Partner intends to cause the Partnership to acquire an interest in as many prospects as practicable in order to best diversify the risks associated with drilling for oil and gas. However, the number and type of wells to ultimately be drilled by the Partnership will vary according to the costs of each well and the size of the fractional working interests selected in each well.
Area of Geographic Concentration
The Managing Partner anticipates that all of the Partnership’s funds available for drilling activities will be expended in the Permian Basin and also the Anadarko Basin. However, if the Managing Partner determines that it is in the best interest of the Partnership to conduct additional drilling activities in other onshore geographic areas of the United States, the Program and the Partnership may expend available funds in such areas.
The Permian Basin encompasses a large area of approximately 75,000 square miles located in West Texas and Southeastern New Mexico. Since 1921, over 30 billion barrels of oil and 100 trillion cubic feet of natural gas have been produced from the Permian Basin. Two interior basins, the Midland Basin in West Texas and the Delaware Basin in West Texas and Southeastern New Mexico, subdivide the Permian Basin. Drilling depths in the Permian Basin range from very shallow to more than 20,000 feet in the Permian Basin.
Over the past 45 years, MOC and its affiliates have drilled approximately 650 commercially productive oil and gas wells in the Permian Basin, and MOC currently operates approximately 630 wells in the Permian Basin. These historical results are not indicative of the results that may be achieved by the Partnership. In addition, a commercially productive well may not necessarily have sufficient production to recover both operating expenses and drilling and development costs. The Managing Partner and its affiliates target multiple Pennsylvanian and Permian age sandstone and carbonate reservoirs along the shelf and shelf-slope areas within the interior subbasins, which lay at depths ranging from 3,000 to 13,000 feet, and most current operations are centered on the shelf and along shelf-slope areas of the Delaware Basin located in Eddy County, Chaves County and Lea County, New Mexico. It is anticipated that the Partnership will, through the Program, conduct a portion of its oil and gas drilling and development activities in this area of the Permian Basin. Predominantly, wells drilled by MOC in this region of the Permian Basin are classified as gas wells but produce both oil and gas. However, MOC and its affiliates have drilled a number of wells in this area that have been classified as oil wells.
The Anadarko Basin of Western Oklahoma, the Texas Panhandle and Southwestern Kansas encompasses an area of approximately 60,000 square miles. First production was established in 1917, and since that time over 14 billion barrels of oil and 98 trillion cubic feet of natural gas have been produced from this geological basin. Production in the Anadarko Basin ranges from several hundred feet to over 26,000 feet in depth.
3
Over the past 35 years, MOC and its affiliates have drilled approximately 1,400 commercially productive wells that have targeted Pennsylvanian, Mississippian, Devonian, and Silurian age sandstone and carbonate reservoirs along the shelf area of Western Oklahoma and the Texas Panhandle at depths of between 6,000 and 13,000 feet. MOC currently operates approximately 750 wells in the Anadarko Basin. It is anticipated that the Partnership will, through the Program, conduct a portion of its drilling and development activities along the shelf area of Western Oklahoma, the Texas Panhandle and Southwest Kansas. A majority of the wells drilled by MOC over the past 35 years in this region of the Anadarko Basin have been classified as gas wells but produce both oil and gas. However, MOC and its affiliates have drilled a number of wells in this area that have been classified as oil wells.
Insurance
The Managing Partner expects to conduct the business of the Partnership and to cause the Program Manager to conduct the business of the Program in a manner intended to limit, to the extent practicable, the exposure of the general partners to liability in excess of their capital contributions to the Partnership. It is anticipated that drilling activities of the Partnership will be conducted in the medium depths, between 3,000 to 13,000 feet, of the Northwest Shelf, the shelf of the Delaware and Midland Basins, Central Basin Platform geological sub-regions of the Permian Basin and the shelf and the shelf-slope area of the Anadarko Basin, areas where the probability of encountering severely over-pressured formations and other hazards associated with drilling activities is less likely. The Program Manager and its affiliates will maintain extensive insurance coverage to protect, to the extent practicable, the Partnership from losses that could arise in connection with Program activities, including legal and contractual liability to third parties.
The Program Manager and its affiliates expect to retain the insurance coverage described below unless such coverage becomes unobtainable or is only available at premiums that are prohibitively more expensive than the premiums now being paid for such policies. However, the Program Manager and its affiliates will not be required to retain operator’s extra expense, including provisions for care, custody and control insurance coverage, for the Partnership after the Program has completed its drilling activities.
A brief discussion of the insurance policies that the Program Manager and its affiliates have obtained on behalf of themselves and the Partnership is set forth below. Each of these policies is subject to, including among others, customary terms, specific policy terms, conditions, exclusions, reporting provisions for certain types of claims, sub-limits, various deductibles, annual aggregates and limitations that may preclude the Partnership from recovering damages, expenses and liabilities suffered by the Partnership, including, among others, damages and liabilities arising from or caused by:
| | • | | the violation of any federal, state or local statute, ordinance or regulation, |
| | • | | fines, penalties and punitive and exemplary damages, |
| | • | | war and terrorist acts, |
| | • | | normal operation, including wear and tear, |
| | • | | the fraud, disloyalty, theft, malicious acts or other similar conduct of employees. |
Other exclusions that are customary in the insurance and oil and gas industries may also apply, including exclusions relating to claims for bodily injury or property damage arising from pollution and environmental events. The Program Manager believes that from time to time the terms, conditions, exclusions and limitations described herein may prevent the Partnership from recovering the full amount of any damages, expenses and liabilities suffered by the Partnership that arise in the event of an accident. In some cases, the Partnership may not recover any portion of such damages, expenses and liabilities.
4
The Program Manager and its affiliates maintain insurance policies that are typical of those maintained by similar operators that drill for oil and gas in the areas where the Program Manager conducts its activities, including comprehensive general liability, which provides legal liability coverage for bodily injury or property damage of others resulting from operations and ownership or use of premises, employer’s liability and commercial automobile insurance. These policies generally protect against the routine hazards encountered by the Program Manager, its affiliates and its employees and agents in the conduct of the business of the Program Manager and its affiliates.
The Program Manager and its affiliates also maintain a comprehensive energy package and an excess liability policy that together provide an additional coverage amount of $50,000,000 per occurrence. These excess umbrella liability policies generally provide legal liability coverage for bodily injury and property damage for losses in excess of the limits provided by the primary policies and protect against liabilities imposed by law or assumed under contract or agreement for damages on account of personal injuries, property damage or advertising liability such as libel, slander, defamation and invasion of privacy caused by or arising out of an occurrence happening anywhere in the world. Injury and damage arising from seepage, pollution or contamination is covered by the excess umbrella liability policies only if caused by a sudden, unintended and unexpected happening, and injury and damage arising from pollution is not covered for sites used in handling, processing, treatment, storage or disposal of waste substances or the transportation of waste substances.
In addition, the physical damage section of the oil and gas lease property policy generally protects the Program Manager against all risks of direct physical loss or damage to all personal property, except drilling rigs and related equipment, vehicles, oil and gas, and various other personal property, for which the Program Manager has liability or is legally liable, subject to a deductible.
Further, the Program Manager and its affiliates maintain an operator’s extra expense policy that has a coverage limit of $5,000,000 for land wells less than 10,000 feet in depth and a limit of $10,000,000 for wells greater than 10,000 feet in depth and that generally protects from:
| | • | | the costs to regain control of a well that goes out of control and costs to redrill or restore a well that has been lost or otherwise damaged as a result of an out of control well, |
| | • | | third-party claims for property damage relating to seepage, pollution or contamination arising from an out of control well and the cost of cleaning up such substances, |
| | • | | loss, damage or expense arising from the uncontrollable flow of oil, gas or water from one subterranean stratum to another through the bore of a well, |
| | • | | evacuation expense if ordered by a governmental agency, and |
| | • | | legal or contractual liability for oilfield equipment in the care, custody or control of the operator. |
The above policies are in effect and are renewed annually but may be canceled by the insurance underwriters upon a minimum of 30 days’ prior written notice. Each of these policies names the Partnership as a co-insured and co-beneficiary thereunder.
The Managing Partner will notify general and limited partners of any material reduction in the insurance coverage of the Program and Partnership. If possible, this notice shall be given 30 days in advance of the change in insurance coverage. In addition, if the Program or the Partnership has its insurance coverage materially reduced for any reason, the Partnership will, as soon as possible, halt all drilling activity until such time as comparable replacement coverage is obtained.
Market and Competitive Risks
The ability of the Partnership to market oil and natural gas found and produced, if any, will depend on numerous factors beyond the control of the Partnership, the effect of which factors cannot be accurately predicted or anticipated. Some of these factors include, without limitation, the availability of other domestic and foreign
5
production, the marketing of competitive fuels, the proximity and capacity of pipelines, fluctuations in supply and demand, the availability of a ready market, the effect of United States federal and state regulation of production, refining, transportation and sales, and general national and worldwide economic conditions.
While the Registrant does not have long-term contracts with purchasers of its crude oil or natural gas, MOC may enter into short-term contracts with its customers to sell the Registrant’s natural gas at specified prices. The Registrant’s natural gas may also be sold to local distribution companies, gas marketers and end users on the spot market. The spot market reflects immediate sales of natural gas without long-term contractual commitments. A substantial portion of the Program’s gas production is being sold regionally in the spot market. The future market condition for natural gas cannot be predicted with any certainty, and the Registrant may experience delays in marketing natural gas production and fluctuations in natural gas prices. The market for crude oil is such that the Registrant anticipates it will be able to sell all the crude oil it can produce.
Many aspects of the Registrant’s activities are highly competitive, including, but not limited to, the acquisition of suitable drilling prospects and the procurement of drilling and related oil field equipment. The Registrant’s ability to compete depends on its financial resources and on the Managing Partner’s staff and facilities, none of which are significant in comparison to those of the oil and gas exploration, development and production industry as a whole.
Regulation
Regulation of Production
The production of oil and gas found by the Program, if any, will be subject to federal and state laws and regulations, and orders of regulatory bodies under those laws and regulations, governing a wide variety of matters, including the drilling and spacing of wells on producing acreage, allowable rates of production, marketing, prevention of waste and pollution, and protection of the environment. Such laws, regulations and orders may restrict the rate of oil and gas production below the rate that would otherwise exist in the absence of such laws, regulations and orders and may restrict the number of wells that may be drilled on a particular oil and gas lease. For example, the Railroad Commission of Texas determines the amount of gas producers can produce and purchasers can take from oil and gas leases located within the State of Texas. Additionally, state statutory provisions relating to oil and gas generally require permits for the drilling of wells.
Natural Gas Prices
The Natural Gas Wellhead Decontrol Act of 1989 was enacted on July 26, 1989, and provides that all gas prices are decontrolled at the wellhead effective January 1, 1993. Accordingly, sales of natural gas by the Partnership generally will not be subject to the maximum lawful price ceilings set by the Natural Gas Policy Act of 1978, as amended. Thus, market conditions will determine the prices that the Partnership receives from the sale of natural gas produced from Program wells.
Oil and Liquid Hydrocarbon Prices
There are currently no federal price controls on oil production, and sales of oil, condensate and natural gas liquids by the Partnership can be made at uncontrolled market prices. However, there can be no assurance that Congress will not enact controls at any time.
Regulation of the Environment
The exploration, development and production of oil and gas is subject to various federal and state laws and regulations to protect the environment. Various states and governmental agencies are considering, and some have adopted, other laws and regulations regarding environmental control that could adversely affect the business of the Partnership. Compliance with such legislation and regulations, together with any penalties resulting from noncompliance therewith, will increase the cost of oil and gas development and production. All or a portion of these costs may ultimately be borne by the Partnership.
6
Possible Legislation
Currently, there are many legislative proposals pertaining to regulation of the oil and gas industry, which proposals may directly or indirectly affect the activities of the Partnership. No prediction can be made as to what additional energy legislation may be proposed, if any, which bills may be enacted, or when any such bills, if enacted, would become effective.
The preceding discussion of regulation of the oil and gas industry is necessarily brief and is not intended to constitute a complete discussion of the various statutes, rules, regulations or governmental orders to which the Partnership’s and the Program’s operations may be subject.
Summary of Material Contracts
Drilling Program Agreement
The Drilling Program Agreement provides that MOC, in its capacity as the Program Manager, will have the exclusive power and authority to act on behalf of the Partnership with respect to the management, control and administration of the business and affairs of the Program and the oil and gas properties subject to the Drilling Program Agreement. The Drilling Program Agreement sets out the rights, duties and obligations of the Program Manager and the other participants in the Program. For a more detailed summary of the material provisions of the Drilling Program Agreement, see “Item 11—Description of Registrant’s Securities to be Registered—Drilling Program Agreement.”
Operating Agreement
The Operating Agreement is a model form operating agreement based upon the American Association of Petroleum Landsmen Form 610-1989. The Operating Agreement includes the accounting procedure for joint operations issued by the Council of Petroleum Accountants Societies of North America. The Operating Agreement contains modifications that are customary and usual for the geographic area in which the Partnership intends to conduct operations.
Gas Marketing Agreement
In consideration for gas marketing services to be rendered by the Program Manager in connection with the marketing of natural gas from the Program’s interests, the Program will pay to the Program Manager a gas marketing fee that is currently equal to four cents per thousand cubic feet (“McF”) of natural gas that is marketed by the Program Manager on the spot gas market. The gas marketing fee may be changed from time to time, but the Program Manager may not charge the Partnership a gas marketing fee that is greater than other participants in a well. The gas marketing fee will be allocated 75% to the investor partners and 25% to the Managing Partner.
Relationship between the Partnership, MD and MOC
The Partnership does not have any employees of its own. All management functions of the Partnership are conducted by MD in its capacity as the Managing Partner, and all administration of the Program, including the origination of prospects and the supervision of drilling and completion activities with respect to those operations for which it is acting as operator, will be conducted by MOC in its capacity as the Program Manager. At December 31, 2009, MOC employed 222 persons on a full-time basis, many of whom dedicate a part of their time to conduct the Partnership’s business. For example, numerous employees of MOC provide accounting, engineering, geological, land and information technology support to the Partnership. None of such employees is subject to collective bargaining arrangements.
With respect to the executive officers of MD and MOC, such persons serve in the same capacities for both MD and MOC. It is not anticipated that the executive officers will spend a significant amount of time on the Partnership’s affairs. J. Roe Buckley, Executive Vice President and Chief Financial Officer of both MD and MOC, will spend some time managing the financial affairs of the Partnership, including working to ensure that the
7
Partnership complies with applicable reporting requirements. Mr. Buckley performs the same functions for the other partnerships managed and administered by MD and MOC. The other executive officers may from time to time tend to the affairs of the Partnership but will focus the majority of their time on the overall affairs of MD and MOC, which include overseeing the Partnership’s participation in drilling activities as discussed above.
Seasonality and Backlog
The production of oil and gas is not considered subject to seasonal factors although the price received by the Registrant for natural gas sales will generally tend to increase during the winter months. Order backlog is not pertinent to the Registrant’s business.
| Item 2. | Financial Information. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
The Registrant was organized as a Delaware limited partnership on February 26, 2009. The offering of limited and general partner interests began May 1, 2009 and concluded August 28, 2009, with total investor partner contributions of $66,210,000. The Registrant commenced its business operations on the closing date of August 28, 2009.
The Registrant was formed to engage primarily in the business of drilling development wells, produce and market crude oil and natural gas produced from such properties, distribute any net proceeds from operations to the general and limited partners and, to the extent necessary, acquire leases that contain drilling prospects. The economic life of the Registrant depends on the period over which the Registrant’s oil and gas reserves are economically recoverable.
Results of Operations
Results of operations for the period from February 26, 2009 (date of inception) through December 31, 2009 are as follows:
| | | |
Oil sales | | $ | 345,134 |
Barrels produced | | | 4,806 |
Average price/barrel | | $ | 71.81 |
Gas sales | | $ | 173,899 |
Mcf produced | | | 29,284 |
Average price/Mcf | | $ | 5.94 |
Although the Partnership inception date was February 26, 2009, no income or expenses were earned or incurred prior to the August 28, 2009 closing date of the offering.
Revenues and other income for the period from February 26, 2009 (date of inception) through December 31, 2009 totaled $521,554 and consisted of oil and gas sales in the amount of $519,033 and interest income in the amount of $2,521. Oil production volume for such period amounted to approximately 4,806 barrels of oil at a corresponding average realized price of $71.81 per barrel of oil, and gas production volume during such period amounted to approximately 29,284 Mcf of gas at a corresponding average realized price of $5.94 per Mcf of gas. Expenses totaling $170,250 consisted primarily of depreciation, depletion and amortization of $130,217. Lease operating expenses totaled $7,673, and production taxes were $30,716. Administrative and general expenses were $1,299, and asset retirement obligation accretion expense was $345. At December 31, 2009, seven wells had been drilled and were productive.
Because the Registrant was formed during 2009, no trend analysis based on yearly changes in liquidity, capital resources or results of operations is available.
8
Liquidity and Capital Resources
The drivers underlying the Partnership’s cash flows consist principally of the ability of the Partnership’s wells to produce oil and gas as well as the prices of crude oil and natural gas. The Partnership expects oil and gas production and, as a result, cash flows, to increase during 2010 as additional wells are completed and oil and gas production is sold. Additionally, the Partnership will invest excess cash in short-term interest bearing securities that may also provide funds for distribution. It is anticipated that substantially all of the Partnership’s excess funds will be expended for drilling costs by the end of the fourth quarter of 2010.
Cash and cash equivalents were $48,806,858 at December 31, 2009. For the period from February 26, 2009 (date of inception) through December 31, 2009, approximately $11.6 million of the initial partners’ capital of $66,210,000 was used for drilling and completion and prepaid well costs, and $5,627,850 was utilized for sales commissions and marketing fees.
Capital requirements in the future are expected to be paid with remaining cash on hand. Management of MD believes at this point that the Partnership will have sufficient capital to complete its drilling activities and that no borrowings will be necessary. Specifically, it is anticipated that the Partnership will have begun drilling the majority of its wells by September 30, 2010, with substantially all activity completed by the end of the fourth quarter of 2010. However, due to unforeseen circumstances, it could become necessary to finance the costs of Partnership operations through Partnership borrowings, utilization of Partnership revenues obtained from production or other methods of financing. These operations may include the drilling, completing and equipping of additional wells to further develop Program prospects. The Partnership Agreement provides that outstanding Partnership borrowings may not at any time exceed 20% of its aggregate capital contributions. Furthermore, the Partnership may borrow funds only if the lender agrees that it will have no recourse against individual general partners. As a result of these provisions, obtaining sufficient debt financing on acceptable terms or at all may not be possible. If the Managing Partner deems it to be in the best interest of the Partnership to borrow funds from an unaffiliated third party, it would do so; however, it is currently anticipated that, if it became necessary to finance the costs of Partnership operations through borrowings, the Partnership would not need to borrow money from an unaffiliated third party.
Revenues that, in the sole judgment of the Managing Partner, are not required to meet the Registrant’s obligations will be distributed to the partners at least quarterly in accordance with the Partnership Agreement. The Partnership made no cash distributions to the investor partners for the period beginning February 26, 2009 (date of inception) through December 31, 2009. The Partnership expects that cash distributions will begin and continue during 2010 due to additional oil and gas revenues that are expected to be sufficient to produce cash flows from operations.
Critical Accounting Policies
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Significant estimates inherent in the Registrant’s financial statements include the estimate of oil and gas reserves and future abandonment costs. Changes in oil and gas prices, changes in production estimates and the success or failure of future development activities could have a significant effect on reserve estimates. The reserve estimates directly impact the computation of depreciation, depletion and amortization, asset retirement obligation and the ceiling test for the Registrant’s oil and gas properties.
The Registrant follows the full-cost method of accounting for its oil and gas activities. Under the full-cost method, all productive and non-productive costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized. Depreciation, depletion and amortization of oil and gas properties subject to amortization are computed on the units-of-production method based on the proved reserves underlying the oil and gas properties. Oil and gas properties are subject to a quarterly ceiling test that limits such costs to the aggregate of the present value of future net cash flows of proved reserves and the lower of cost or fair value of unproved properties. The present value of future net cash flows has been prepared using the oil and gas pricing guidelines
9
established by the Securities and Exchange Commission (the “SEC”), year-end development and production costs and a 10 percent annual discount rate. There were no cost ceiling write-downs during the period from February 26, 2009 (date of inception) through December 31, 2009.
The process of estimating oil and gas reserves is complex and involves decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data. Therefore, these estimates are inherently imprecise.
Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this Form 10. In addition, the Partnership may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond the Partnership’s control.
In December 2008, the SEC issued its final rule for Modernization of Oil and Gas Reporting. Pursuant to this rule, the SEC adopted revisions to its oil and gas reporting disclosures effective for annual reports for fiscal years ending on or after December 31, 2009. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves, which should help investors evaluate the relative value of oil and gas entities. In the three decades that have passed since the original adoption of oil and gas disclosure items, there have been significant changes in the oil and gas industry. These revisions are designed to modernize and update the oil and gas disclosure requirements to align them with current practices and changes in technology.
The new rules include provisions that permit the use of new technologies to determine proved reserves, require entities to report any third party that is relied upon to prepare or audit reserve estimates, and require that oil and gas reserves be reported and the full cost ceiling value calculated using average first-of-the-month natural gas and oil prices during the twelve-month period ending in the reporting period.
Since the Partnership uses the full-cost method to account for its oil and gas operations, it is susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. For instance, a 10% decline in average oil and gas prices would have resulted in a cost ceiling write-down of $232,677.
All financing activities of the Registrant are reported in the financial statements. The Registrant does not engage in any off-balance sheet financing arrangements. Additionally, the Registrant has no contractual obligations but has a financial obligation to plug and abandon non-producing properties, as discussed below.
Asset Retirement Obligations
The Partnership has recognized an estimated liability for future plugging and abandonment costs. A liability for the estimated fair value of the future plugging and abandonment costs is recorded with a corresponding increase in the full cost pool at the time a new well is drilled. Depreciation expense associated with estimated plugging and abandonment costs is recognized in accordance with the full cost methodology.
The Partnership estimates a liability for plugging and abandonment costs based on historical experience and estimated well life. The liability is discounted using the credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in well plugging and abandonment costs or well useful lives or if federal or state regulators enact new well restoration requirements. The Partnership recognizes accretion expense in connection with the discounted liability over the remaining life of the well.
10
A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the period beginning February 26, 2009 (date of inception) through December 31, 2009 is as follows:
| | | |
Balance, beginning of period | | $ | — |
Liabilities incurred | | $ | 69,288 |
Accretion expense | | $ | 345 |
Balance, end of period | | $ | 69,633 |
New Accounting Pronouncements
Modernization of Natural Gas and Oil Reporting. In January 2009, the SEC issued revisions to the natural gas and oil reporting disclosures, “Modernization of Oil and Gas Reporting, Final Rule” (the “Final Rule”). In January 2010, the Financial Accounting Standards Board (the “FASB”) updated its oil and gas estimation and disclosure requirements to align its requirements with the SEC’s modernized oil and gas reporting rules, which are described above. The update amends the definition of “proved reserves” to use the average of first-day-of-the-month prices during the twelve months preceding the end of the reporting period, adds definitions used in estimating and disclosing proved oil and natural gas quantities and expands the disclosures required for equity-method investments. The update must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. The Partnership adopted the new standards effective December 31, 2009. See the notes to the financial statements for disclosures regarding natural gas and oil reserves.
FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles. In June 2009, the FASB issued guidance on the accounting standards codification and the hierarchy of generally accepted accounting principles (“GAAP”). The accounting standards codification is intended to be the source of authoritative GAAP and reporting standards as issued by the FASB. Its primary purpose is to improve clarity and use of existing standards by grouping authoritative literature under common topics. The accounting standards codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Partnership describes the authoritative guidance used within the footnotes per this standard rather than using numerical references. The accounting standards codification does not change or alter existing GAAP, and there is no expected impact on the Partnership’s financial position, results of operations or cash flows.
Organization and Related Party Transactions
The Partnership was organized on February 26, 2009 in accordance with the laws of the State of Delaware. MD, a Delaware corporation, has been appointed as the Registrant’s managing general partner. MD has no equity interest in the Registrant. MOC is operator of oil and gas properties owned by the Partnership. Mewbourne Holdings, Inc. is the parent of both MD and MOC. Substantially all transactions are with MD and MOC. Because of the common control of the Partnership, the Program, MD, MOC and other affiliates thereof, and the fact that some individuals hold positions in both MD and MOC and oversee activities in various partnerships similar to the Partnership, conflicts of interest may arise in the following situations:
| | • | | MD currently manages and in the future will sponsor and manage other partnerships similar to the Partnership; |
| | • | | MD will decide which prospects the Partnership will acquire; |
| | • | | MOC will act as the operator for Program wells under the operating agreement, the terms of which have not been negotiated by non-affiliated persons; |
| | • | | MD and its affiliates will contribute oil and gas leases and sell other property to the Program and the Partnership; |
11
| | • | | MD is a general partner of numerous other partnerships and owes duties of good faith and fair dealing to such other partnerships; |
| | • | | MD and its affiliates engage in significant drilling, operating and producing activities for other partners; and |
| | • | | Affiliates of MD may purchase interests in the Partnership, and subject to limitations, interests purchased by an affiliate have voting rights under the Partnership Agreement. |
MD is accountable to the Partnership as a fiduciary and is required to act in good faith in the best interests of the Partnership at all times. MD will attempt, in good faith, to resolve all conflicts of interest in a fair and equitable manner with respect to all persons affected by those conflicts of interest. For additional information on potential conflicts of interest and MD’s fiduciary responsibility to the Partnership, please see “Item 11. Description of Registrant’s Securities to be Registered—Partnership Agreement—Fiduciary Responsibility of the Managing Partner.”
In the ordinary course of business, MOC will incur certain costs that will be passed on to well owners of the well for which the costs were incurred. The Partnership will receive its portion of these costs based upon its ownership in each well incurring the costs. These costs are referred to as operator charges and are standard and customary in the oil and gas industry. Operator charges include recovery of gas marketing costs, fixed rate overhead, supervision, pumping and equipment furnished by the operator, some of which will be included in the full cost pool pursuant to Rule 4-10(c)(2) of Regulation S-X of the Securities Act. Reimbursement to MOC for operator charges totaled $188,152 for the period from February 26, 2009 (date of inception) through December 31, 2009. Operator charges are billed in accordance with the Program and the Partnership Agreement.
In consideration for services rendered by MD in managing the business of the Partnership, the Partnership during each of the initial three years of the Partnership will pay to MD a management fee in the amount equal to 0.75 of 1% of the subscriptions by the investor partners to the Partnership. Management fees can only be paid out of funds available for distributions. No management fees were allocated to the Partnership for the period from February 26, 2009 (date of inception) through December 31, 2009. In the periods in which management fees are paid, the Partnership includes them as part of the full cost pool pursuant to Rule 4-10(c)(2) of Regulation S-X of the Securities Act.
In general, during any particular calendar year, the total amount of administrative expenses allocated to the Partnership by MOC shall not exceed the greater of (a) 3.5% of the Partnership’s gross revenue from the sale of oil and natural gas production during each year (calculated without any deduction for operating costs or other costs and expenses) or (b) the sum of $50,000 plus 0.25% of the capital contributions of limited and general partners. Administrative expenses can only be paid out of funds available for distributions. Under this arrangement, $363 was allocated to the Partnership during the period from February 26, 2009 (date of inception) through December 31, 2009. The costs and revenues of the Program are allocated to MD and the Partnership as follows:
| | | | | | |
| | | Partnership | | | MD | |
Revenues: | | | | | | |
Interest earned on capital contributions of investor partners | | 100 | % | | 0 | % |
Proceeds from disposition of depreciable and depletable properties | | 75 | % | | 25 | % |
All other revenues | | 75 | % | | 25 | % |
| | |
Costs and expenses: | | | | | | |
Organization and offering costs(1) | | 0 | % | | 100 | % |
Lease acquisition costs(1) | | 0 | % | | 100 | % |
Tangible and intangible drilling costs(1) | | 100 | % | | 0 | % |
Operating costs, reporting and legal expenses, general and administrative expenses and all other costs | | 75 | % | | 25 | % |
| (1) | Pursuant to the Program, MD must contribute 100% of organization and offering costs and lease acquisition costs, which should approximate 17.65% of total capital costs. To the extent that organization and offering costs and lease acquisition costs are less than 17.65% of total capital costs, MD is responsible for tangible drilling costs until its share of the Program’s total capital costs reaches approximately 17.65%. |
12
The Partnership’s financial statements reflect its respective proportionate participation in the Program.
Property Interests
The Registrant’s properties consist primarily of interests in properties on which oil and gas wells are located, both producing and in progress. Such property interests are often subject to landowner royalties, overriding royalties and other oil and gas leasehold interests. MD and the Partnership are joint owners of undivided working interests in these properties.
Fractional working interests in developmental oil and gas prospects located primarily in the Anadarko Basin of Western Oklahoma, the Texas Panhandle and Southwest Kansas and the Permian Basin of Southeastern New Mexico and West Texas were acquired by the Registrant, resulting in the Registrant’s participation in the drilling of oil and gas wells. As of December 31, 2009, the Registrant had seven wells producing, five wells in drilling operations and one well that was plugged and abandoned for a total of thirteen wells in which the Partnership owns an interest.
The following table summarizes the Registrant’s drilling activity for the period beginning February 26, 2009 (date of inception) through December 31, 2009:
| | | | |
| | | Gross | | Net |
Development Wells | | | | |
Oil and natural gas wells | | 7 | | 1.395 |
Non-productive wells | | 1 | | 0.314 |
Reserves Estimate
The reserves estimate has been prepared by MOC’s Petroleum Engineering Department. MOC’s Manager of Economics and Evaluations, Bryan Montgomery, is the technical person primarily responsible for overseeing the preparation of the company’s reserve estimates. His qualifications include the following:
| | • | | Twenty-six years of practical experience in petroleum engineering with twenty-four years of this experience being in the estimation and evaluation of reserves; |
| | • | | Certified professional engineer in the State of Texas; |
| | • | | Bachelor of Science Degree in Petroleum Engineering and Master of Business Administration degree; and |
| | • | | Member in good standing of the Society of Petroleum Engineers |
Internal Controls over Reserves Estimate
MOC maintains internal controls such as the following to ensure the reliability of reserves estimation:
| | • | | No employee’s compensation is tied to the amount of reserves booked; |
| | • | | Comprehensive SEC-compliant internal policies to determine and report proved reserves are followed. Reserve estimates are made by experienced reservoir engineers; |
13
| | • | | Senior reservoir engineers review all the company’s reported proved reserves at the close of each quarter; and |
| | • | | Each quarter, the Manager of Economics and Evaluations, the Vice-President of Exploration and the Chief Operating Officer review all significant reserve changes and all new proved undeveloped reserves additions. |
| Item 4. | Security Ownership of Certain Beneficial Owners and Management |
Beneficial Owners of More than Five Percent
| | | | | | |
Title of Class | | Name of Beneficial
Owner | | Amount and Nature
of Beneficial Owner | | Percent of Class |
None | | None | | N/A | | N/A |
Security Ownership of Management
The Registrant does not have any officers or directors. The Managing Partner, MD, has the exclusive right and full authority to manage, control and administer the Registrant’s business. No officers or directors of the Managing Partner beneficially own any partnership interests of the Registrant.
Changes in Control
Under the Partnership Agreement, limited and general partners holding a majority of the outstanding limited and general partnership interests have the right to take certain actions, including the removal of the managing general partner. The Registrant is not aware of any current arrangement or activity that may lead to such removal.
| Item 5. | Directors and Executive Officers. |
As discussed in “Item 1—Business” above, the Registrant does not have any employees, officers or directors of its own. Under the Partnership Agreement, the Registrant’s managing general partner, MD, is granted the exclusive right and full authority to manage, control and administer the Registrant’s business. MD is a wholly-owned subsidiary of Mewbourne Holdings, Inc. It is not anticipated that the executive officers of MD will spend a significant amount of time on the Partnership’s affairs. J. Roe Buckley, Executive Vice President and Chief Financial Officer of MD, will spend some time managing the financial affairs of the Partnership, including working to ensure that the Partnership complies with applicable reporting requirements. Mr. Buckley performs the same functions for the other partnerships managed and administered by MD and MOC. The other executive officers may from time to time tend to the affairs of the Partnership but will focus the majority of their time on the overall affairs of MD and MOC, which include overseeing the Partnership’s participation in drilling activities.
Set forth below are the names, ages and positions of the directors and executive officers of MD, the Registrant’s managing general partner. Directors of MD are elected to serve until the next annual meeting of stockholders or until their successors are elected and qualified, and officers serve at the discretion of the Board of Directors.
14
| | | | |
Name | | Age as of
December 31,
2009 | | Position |
Curtis W. Mewbourne | | 74 | | President and Director |
J. Roe Buckley | | 47 | | Vice President and Chief Financial Officer |
Alan Clark | | 57 | | Treasurer and Controller |
Michael F. Shepard | | 63 | | Secretary and General Counsel |
Dorothy M. Cuenod | | 49 | | Assistant Secretary and Director |
Ruth M. Buckley | | 48 | | Assistant Secretary and Director |
Julie M. Greene | | 46 | | Assistant Secretary and Director |
Curtis W. Mewbourne, age 74, formed Mewbourne Holdings, Inc. in 1965 and serves as Chairman of the Board and President of Mewbourne Holdings, Inc., MD and MOC. He has operated as an independent oil and gas producer for the past 45 years. Mr. Mewbourne received a Bachelor of Science Degree in Petroleum Engineering from the University of Oklahoma in 1957. Mr. Mewbourne is the father of Dorothy M. Cuenod, Ruth M. Buckley and Julie M. Greene and the father-in-law of J. Roe Buckley.
J. Roe Buckley, age 47, joined Mewbourne Holdings, Inc. in July, 1990 and serves as Vice President and Chief Financial Officer of both MD and MOC. Mr. Buckley was employed by Mbank Dallas from 1985 to 1990 where he served as a commercial loan officer. He received a Bachelor of Arts in Economics from Sewanee in 1984. Mr. Buckley is the son-in-law of Curtis W. Mewbourne and is married to Ruth M. Buckley. He is also the brother-in-law of Dorothy M. Cuenod and Julie M. Greene.
Alan Clark, age 57, joined MOC in 1979 and serves as Treasurer and Controller of both MD and MOC. Prior to joining MOC, Mr. Clark was employed by Texas Oil and Gas Corporation as Assistant Supervisor of joint interest accounting from 1976 to 1979. Mr. Clark has served in several accounting/finance positions with MOC prior to his current assignment. Mr. Clark received a Bachelor of Business Administration from the University of Texas at Arlington.
Michael F. Shepard, age 63, joined MOC in 1986 and serves as Secretary and General Counsel of MD. He has practiced law exclusively in the oil and gas industry since 1979 and formerly was counsel with Parker Drilling Company and its Perry Gas subsidiary for seven years. Mr. Shepard holds the Juris Doctor degree from the University of Tulsa where he received the National Energy Law and Policy Institute award as the outstanding graduate in the Energy Law curriculum. He received a B.A. degree, magna cum laude, from the University of Massachusetts in 1976. Mr. Shepard is a member of the bar in Texas and Oklahoma.
Dorothy M. Cuenod, age 49, received a B.A. degree in Art History from The University of Texas and a Masters of Business Administration Degree from Southern Methodist University. Since 1984 she has served as a Director and Assistant Secretary of both MD and MOC. Ms. Cuenod is the daughter of Curtis W. Mewbourne and is the sister of Ruth M. Buckley and Julie M. Greene. She is also the sister-in-law of J. Roe Buckley.
Ruth M. Buckley, age 48, received a Bachelor of Science Degree in both Engineering and Geology from Vanderbilt University. Since 1987 she has served as a Director and Assistant Secretary of both MD and MOC. Ms. Buckley is the daughter of Curtis W. Mewbourne and is the sister of Dorothy M. Cuenod and Julie M. Greene. She is also the wife of J. Roe Buckley.
Julie M. Greene, age 46, received a B.A. degree in Business Administration from The University of Oklahoma. Since 1988 she has served as a Director and Assistant Secretary of both MD and MOC. Prior to that time she was employed by Rauscher, Pierce, Refsnes, Inc. Ms. Greene is the daughter of Curtis W. Mewbourne and is the sister of Dorothy M. Cuenod and Ruth M. Buckley. She is also the sister-in-law of J. Roe Buckley.
15
| Item 6. | Executive Compensation. |
The Registrant does not have any officers or directors. Management of the Registrant is vested in the Managing Partner. None of the officers or directors of MD or MOC receive remuneration directly from the Registrant but continue to be compensated by their present employers. The Registrant reimburses MD and MOC and affiliates thereof for certain costs of overhead falling within the definition of Administrative Costs (as provided in the Drilling Program Agreement and the Partnership Agreement), including, without limitation, salaries of the officers and employees of MD and MOC; provided that no portion of the salaries of the directors or of the executive officers of MOC or MD may be reimbursed as Administrative Costs.
| Item 7. | Certain Relationships and Related Transactions, and Director Independence. |
Pursuant to the Partnership Agreement and the Drilling Program Agreement, the Registrant had the following related party transactions with MD and its affiliates during the year ended December 31, 2009:
| | | |
Administrative and general expense, management fees (if applicable) and payment of well charges and supervision charges in accordance with standard industry operating agreements | | $ | 188,515 |
The Registrant participates in oil and gas activities through the Program. Pursuant to the Program, MD pays approximately 25% of the Program’s operating costs. The Registrant believes that these transactions were on terms no less favorable than could have been obtained from non-affiliated third parties.
Administrative Costs. MD, as the managing partner of the Partnership, and MOC, as the program manager of the Program, will be entitled to reimbursement of administrative costs incurred by them in connection with managing and conducting the affairs relating to the Partnership’s interest in the Program or of the Partnership, as applicable. The amount of administrative costs that are reimbursed by the Partnership shall be allocated to the Partnership and the Program on a basis consistent with applicable industry standards and must be supported in writing as to the application of such costs and as to the amount charged. Regardless of the actual amount of administrative costs incurred by the Managing Partner or the Program Manager in connection with the affairs of the Partnership, during any particular calendar year the total amount of administrative costs allocable to the Partnership shall not exceed the greater of: (a) 3.5% of the Partnership’s gross revenues from the sale of oil and natural gas production during such year, calculated without any deduction for operating costs or other costs and expenses, or (b) the sum of $50,000 plus 0.25% of the subscriptions by investor partners to the Partnership. Such limitation on administrative costs shall not, however, be applicable to administrative costs otherwise allocable to the Partnership that are extraordinary and non-recurring or to the fixed overhead fee chargeable by an operator of oil and gas wells, including the fixed overhead fee chargeable under an operating agreement by MOC with respect to the oil and gas wells operated by MOC.
Administrative costs incurred by the Managing Partner and the Program Manager for managing and conducting the business and affairs of the Partnership and the Program will be allocated 75% to the investor partners and 25% to the Managing Partner. Administrative costs will not include any portion of the salaries, benefits, compensation or remuneration of directors, executive officers, those holding 5% or more of the equity interests in the Managing Partner or a person having power to direct or cause the direction of the Managing Partner, whether through the ownership of voting securities, by contract or otherwise.
Reporting and Legal Expenses.MD, as the managing partner of the Partnership, and MOC, as the program manager of the Program, will be entitled to reimbursement of reporting and legal expenses incurred by them in connection with managing and conducting the affairs relating to the Partnership’s interest in the Program or of the Partnership, as applicable. Reporting and legal expenses will be allocated 75% to the investor partners in the Partnership and 25% to the Managing Partner.
Management Fee. In consideration for services to be rendered by the Managing Partner in managing the business of the Partnership, each program during each of the initial three years of the Partnership will pay to the Managing Partner a management fee in an amount equal to 1% of the subscriptions by the investor partners to the Partnership. The management fee will be allocated 75% to the investor partners in the Partnership and 25% to the
16
Managing Partner. The portion of the management fee allocated to the investor partners payable during a particular partnership year will not be deducted from the capital contributions of the investor partners but will be paid by the Program in monthly or other periodic installments from funds that would otherwise be available for distribution to the partners in the Partnership during such partnership year and in such amounts as may be determined in the discretion of the Managing Partner. To the extent that the Partnership has insufficient distributable funds during a particular partnership year to fully pay its share of the amount of the management fee payable during the partnership year, then the amount of such unpaid management fee will be carried forward and payable in the next succeeding partnership year.
Gas Marketing Services Fee. In consideration for gas marketing services to be rendered by the Program Manager in connection with the marketing of natural gas from the Program’s interests, the Program will pay to the Program Manager a gas marketing fee that is currently equal to four cents per MCF that is marketed by the Program Manager on the spot gas market. The gas marketing fee may be changed from time to time, but the Program Manager may not charge the Partnership a gas marketing fee that is greater than other participants in a well. The gas marketing fee will be allocated 75% to the investor partners and 25% to the Managing Partner.
For additional information on these related party transactions, please see “Item 2. Financial Information—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Organization and Related Party Transactions,” which is incorporated herein by reference.
As discussed above, the Registrant does not have any directors.
| Item 8. | Legal Proceedings. |
The Registrant is not aware of any pending legal proceedings to which it is a party.
| Item 9. | Market Price of and Dividends on the Registrant’s Common Equity and Related Stockholder Matters. |
At December 31, 2009, the Registrant had 13,242 outstanding limited and general partnership interests held of record by 1,754 subscribers, 1,655 of which subscribed to general partner interests and 99 of which subscribed to limited partner interests. None of the partnership interests may be sold pursuant to Rule 144 under the Securities Act. There is no established public or organized trading market for the limited and general partner interests.
Approximately $11.6 million of the initial partners’ capital of $66,210,000 was used for drilling and completion and prepaid well costs, and $5,627,850 was utilized for sales commissions and marketing fees for the period from February 26, 2009 (date of inception) through December 31, 2009. Capital requirements in the future are expected to be paid with remaining cash on hand. Management of MD believes that funds are sufficient to complete the wells for which funds have been committed. Specifically, it is anticipated that the Partnership will have begun drilling the majority of its wells by September 30, 2010 with substantially all activity completed by the end of the fourth quarter of 2010.
Revenues that, in the sole judgment of the Managing Partner, are not required to meet the Registrant’s obligations will be distributed to the partners at least quarterly in accordance with the Registrant’s Partnership Agreement. The Partnership made no cash distributions to the investor partners for the period beginning February 26, 2009 (date of inception) through December 31, 2009. The Partnership expects that cash distributions will begin and continue during 2010 due to additional oil and gas revenues that are expected to be sufficient to produce cash flows from operations.
| Item 10. | Recent Sales of Unregistered Securities. |
The partnership interests in the Registrant were offered at $5,000 each to accredited investors in a private placement pursuant to Section 4(2) of the Securities Act and Regulation D promulgated thereunder, with a maximum offering amount of $73,000,000 (14,600 interests). Mewbourne Securities, Inc., an affiliate of MD (“MS”), served as the dealer manager for the private placement.
17
On August 28, 2009, the offering of limited and general partnership interests in the Registrant was closed, with interests aggregating $66,210,000 originally being sold to accredited investors of which $62,140,000 were sold to accredited investors as general partner interests and $4,070,000 were sold to accredited investors as limited partner interests. An amount equal to 8.5% of the proceeds realized from the sale of interests to investors was not received by the Registrant and was deducted to pay sales commissions and marketing fees to MS. The remainder of the proceeds has been or will be used for drilling and completion and prepaid well costs.
| Item 11. | Description of the Registrant’s Securities to be Registered. |
The following is a summary of the provisions of the Partnership Agreement and the Drilling Program Agreement. This summary is qualified in all respects by reference to the full text of the Partnership Agreement, which appears as Exhibit 4.1 hereto, and the Drilling Program Agreement, which appears as Exhibit 10.1 hereto.
Partnership Agreement
Term
The Partnership is organized under the Delaware Revised Uniform Limited Partnership Act (the “Delaware Limited Partnership Act”). The Partnership will continue until terminated as provided for in the Partnership Agreement. See “—Dissolution, Liquidation and Termination” below.
Rights and Powers of Partners
General and Limited Partners. Under the terms of the Partnership Agreement, general and limited partners will have the following rights and powers with respect to the Partnership:
| | (a) | to share all charges, credits and distributions in accordance with the Partnership Agreement and to share all charges, credits and distributions of the Program through the Partnership, |
| | (b) | to inspect at their expense books and records relating to the activities of the Partnership through the Program, upon adequate notice and at all reasonable times, other than geophysical, geological and other similar data and information and studies, maps, evaluations and reports derived therefrom that for a reasonable period of time may be kept confidential because the Managing Partner has agreed to keep such matters confidential or has determined in good faith that such matters should be kept confidential considering the interests of the Partnership and each of its partners, |
| | (c) | to have on demand true and full information of all activities of the Partnership, through the Program, and a formal account of affairs whenever circumstances render it just and reasonable, |
| | (d) | to have dissolution and winding up of the Partnership by decree of court as provided under Delaware law, |
| | (e) | to reconstitute the Partnership with a new managing partner upon the withdrawal or retirement of the Managing Partner from the Partnership, directly or as a result of a bankruptcy, dissolution or similar event that would dissolve the Partnership, which causes the dissolution of the Partnership upon the election of a majority in interest of the general and limited partners, |
| | (f) | to terminate any contract between the Partnership and the Managing Partner or any affiliate of the Managing Partner by a vote or written consent of a majority in interest of the general and limited partners, without penalty upon 60 days’ written notice, |
18
| | (g) | to approve the sale of all or substantially all of the assets of the Partnership, except upon liquidation of the Partnership, by the affirmative vote of a majority in interest of the general and limited partners, except in connection with a roll-up transaction that requires the affirmative vote of at least 66% in interest of the general and limited partners, |
| | (h) | to dissolve the Partnership at any time upon the election of a majority in interest of the general and limited partners, |
| | (i) | to permit the assignment by the Partnership or the Managing Partner of their obligations under the Drilling Program Agreement, if such permission is required under the Drilling Program Agreement, by the affirmative vote of a majority in interest of the general and limited partners, |
| | (j) | to agree to the termination or amendment, except for certain conformatory amendments and amendments necessary to conform to the Internal Revenue Code of 1986, as amended (the “Code”), or that do not adversely affect the general and limited partners, of the Drilling Program Agreement or the waiver of any rights of the Partnership under the Drilling Program Agreement by the affirmative vote of a majority in interest of the general and limited partners, |
| | (k) | to remove the Managing Partner and substitute a new managing partner to operate and carry on the business of the Partnership or to remove the Program Manager and substitute a successor to act in such capacity by the affirmative vote of a majority in interest of the general and limited partners, and |
| | (l) | to propose and vote on certain matters affecting the Partnership, as provided in the Partnership Agreement. |
Limited Partners. Limited partners of the Partnership will take no part in the control of the business or affairs of the Partnership or the Program and will have no voice in the management or operations of the Partnership or Program. This lack of management and control is necessary to insulate the limited partners from liability in excess of their investment in the Partnership and their share of undistributed profits from the Partnership. Notwithstanding the foregoing, limited partners shall:
| | • | | have all of the rights described under the caption “General and Limited Partners” above, and |
| | • | | have their liability for operations of the Partnership and the Program limited to the amount of their capital contributions and to their shares of Partnership capital and undistributed net revenues of the Partnership, if any; provided, however, that under Delaware law the limited partners may under certain circumstances be required to repay the Partnership amounts previously distributed to them by the Partnership if the Partnership does not have sufficient other assets to satisfy the claims of creditors. |
General Partners. The general partners will delegate to the Managing Partner the responsibility for the day-to-day operations of the Partnership. In addition, the general partners will covenant not to exercise the following rights granted to them under Delaware law:
| | • | | the right to withdraw from the Partnership, |
| | • | | the right to act as agent of the Partnership or to execute documents on behalf of the Partnership, and |
| | • | | the right to act, other than together with other general partners constituting a majority in interest of the general and limited partners, to cause the Managing Partner on behalf of the Partnership to convey Partnership property or take any other action binding on the Partnership. |
19
A general partner who violates such covenants is obligated to indemnify the Partnership and the other partners for any loss or liability caused by such violation. Furthermore, in the event of a dissolution caused by a withdrawing general partner, upon reconstitution of the Partnership, the withdrawing general partner shall remain subject as a general partner to any liabilities or obligations of the Partnership arising prior to such withdrawal. Upon withdrawal from the Partnership, a general partner is entitled to continue to receive any distributions to which he is otherwise entitled under the Partnership Agreement for the period prior to his withdrawal; however, such general partner shall not be entitled to receive the fair value of his interest in the Partnership as of the date of such withdrawal based upon his right to share in distributions from the Partnership, and neither the Partnership nor the Managing Partner has any obligation to repurchase any interest in the Partnership from the withdrawing general partner. The withdrawing general partner will no longer be entitled to receive any distributions nor shall such general partner have any rights as an investor partner under the Partnership Agreement. The sharing ratios will be recalculated among the general and limited partners without regard to the withdrawing general partner’s capital contribution. See “—Reconstitution of the Partnership” below.
The Managing Partner. The Managing Partner has full and exclusive power, except as limited by the Partnership Agreement and applicable law, to manage, control, administer and operate the properties, business and affairs of the Partnership. The Managing Partner has the authority to enter into the Drilling Program Agreement on behalf of the Partnership.
Under the Partnership Agreement, the Managing Partner is required to devote only such time and effort to the business of the Partnership as may be necessary to promote adequately the interests of the Partnership and the mutual interests of the partners. The Managing Partner is permitted to engage in any other business ventures, including the ownership and management of oil and gas properties and the organization and management of other drilling programs.
Fiduciary Responsibility of the Managing Partner
The contemplated activities of the Partnership will involve decisions by the Managing Partner, on behalf of the Partnership, and the Program Manager, on behalf of the Program, and transactions between the Partnership, the Program, the Managing Partner or affiliates thereof. Because of the common control of the Partnership, the Program, the Managing Partner, the Program Manager and other affiliates thereof, any such decisions or transactions will lack the benefits of arm’s-length bargaining and will necessarily involve conflicts of interest. The Managing Partner is accountable to the Partnership as a fiduciary and is required to act in good faith in the best interests of the Partnership at all times. The Managing Partner will attempt, in good faith, to resolve all conflicts of interest in a fair and equitable manner with respect to all persons affected by those conflicts of interest. Nevertheless, the actions of the Managing Partner may not be the most advantageous to the Partnership and could fall short of the full exercise of such fiduciary duty. No provision has been made for an independent review of conflicts of interest.
The Partnership is organized under Delaware law, and under Delaware law the general partner of a partnership owes a fiduciary duty to the partnership and to its partners. Under Delaware law, the Managing Partner will owe the general and limited partners a duty of good faith, fairness and loyalty. In this regard, the Managing Partner is required to supervise and direct the activities of the Partnership prudently and with that degree of care, including acting on an informed basis, that an ordinarily prudent person in a like position would use under similar circumstances. Moreover, the Managing Partner must act at all times in the best interests of the Partnership and the general and limited partners. The Managing Partner and its affiliates may never profit by causing the Partnership to engage in drilling in contravention of these duties.
In an effort to give the Managing Partner maximum flexibility with respect to its management of the Partnership and other partnerships, the Partnership Agreement contains provisions that modify what would otherwise be the applicable Delaware law relating to the fiduciary standards of the Managing Partner to the general and limited partners. The fiduciary standards in the Partnership Agreement could be less advantageous to the general and limited partners and more advantageous to the Managing Partner than the corresponding fiduciary standards otherwise applicable under Delaware law, specifically:
| | • | | the Partnership may indemnify and hold harmless the Managing Partner and its affiliates, |
20
| | • | | the Managing Partner is required to devote only so much of its time as is necessary to manage the affairs of the Partnership, |
| | • | | the Managing Partner and its affiliates may conduct business with the Partnership in a capacity other than as a sponsor, |
| | • | | the Managing Partner and any of its affiliates may pursue business opportunities that are consistent with the Partnership’s investment objectives for their own account, and |
| | • | | the Managing Partner may manage multiple programs simultaneously. |
As a result of these provisions in the Partnership Agreement, the general and limited partners may find it more difficult to hold the Managing Partner responsible for acting in the best interests of the Partnership and its general and limited partners than if the fiduciary standards of the otherwise applicable Delaware law governed the situation.
In addition, the Partnership Agreement contains provisions that are intended to limit the liability of the Managing Partner or any affiliate of the Managing Partner for any act or omission within the scope of authority conferred upon them under the Partnership Agreement or Drilling Program Agreement if the Managing Partner has determined in good faith, as of the time of the conduct or omission, that such conduct or omission was in the best interest of the Partnership and that it did not constitute negligence or misconduct. Further, as discussed in greater detail below under “Item 12. Indemnification of Directors and Officers,” the Partnership Agreement provides for indemnification of the Managing Partner and its affiliates against claims arising from conduct or omission on behalf of the Partnership. Such indemnification will be available if the Managing Partner determines in good faith, as of the time of the conduct or omission, that such conduct or omission was in the best interests of the Partnership and that it did not constitute negligence or misconduct. The Managing Partner would be subject to a conflict of interest in making any determination as to limitations of its liability and as to whether it and its affiliates should be indemnified, and the general and limited partners must rely upon the integrity of the Managing Partner in making such determinations.
Where the question has arisen, courts have held that an investor partner may institute a legal action called a class action on behalf of itself and all other similarly situated investor partners to recover damages for a breach by a general partner of its fiduciary duty. An investor partner may also institute a legal action called a derivative suit on behalf of the partnership to recover damages from third parties. In addition, investor partners may have the right, subject to procedural and jurisdictional requirements, to bring partnership class actions in federal courts to enforce their rights under the federal securities laws. Further, investor partners who have suffered losses in connection with the purchase or sale of their interests in the partnership may be able to recover such losses from a general partner where the losses result from a violation by the general partner of the antifraud provisions of the federal securities laws. The burden of proving such a breach, and all or a portion of the expense of such lawsuit, would have to be borne by the investor partner bringing such action. In the event of a lawsuit for a breach of its fiduciary duty to the Partnership and/or the general and limited partners, the Managing Partner, depending upon the particular circumstances involved, might be able to avail itself under Delaware law of various defenses to the lawsuit.
Indemnification of the Managing Partner and its Affiliates
The Partnership Agreement provides that neither the Managing Partner nor any of its affiliates shall be liable to the Partnership or the general and limited partners for any loss suffered by the Partnership that arises out of any action or inaction performed or omitted by the Managing Partner or such affiliate if the Managing Partner in good faith has determined, as of the time of the conduct or omission, that the course of conduct or omission was in the best interest of the Partnership, that the Managing Partner or such affiliate was acting on behalf of or performing services for the Partnership, and that such conduct or omission did not constitute negligence or misconduct.
The Partnership Agreement also provides that the Managing Partner and its affiliates shall be indemnified by the Partnership, only from the tangible net assets of the Partnership and not from other assets of the partners, from and against all losses, judgments, liabilities, expenses and settlements sustained by them in connection with acts performed or omitted by the Managing Partner or affiliates acting on behalf of or performing services for the
21
Partnership or the Program; provided that, unless otherwise ordered by a court, the Managing Partner has determined in good faith, as of time of the conduct or omission, that the course of conduct or omission was in the best interests of the Partnership and that the conduct or omission did not constitute negligence or misconduct. The Partnership is authorized to purchase insurance against liabilities asserted against and expenses incurred by such persons in connection with the Partnership’s activities; provided that, the Partnership will not bear the cost of that portion of any insurance, other than insurance customary for the Partnership’s business, that insures the Managing Partner for any liability for which the Managing Partner may not be indemnified as discussed above.
The Partnership Agreement further limits indemnification of the Managing Partner by providing that the Managing Partner, its affiliates and any person acting as a broker-dealer will not be indemnified for any losses, liabilities or expenses arising from or out of a violation of federal or state securities laws unless:
| | • | | there has been a successful adjudication on the merits of each count involving alleged securities law violations as to the particular indemnitee and the court approves indemnification of the litigation costs, |
| | • | | such claims have been dismissed with prejudice on the merits by a court of competent jurisdiction as to the particular indemnitee and the court approves indemnification of the litigation costs, or |
| | • | | a court of competent jurisdiction approves a settlement of the claims against a particular indemnitee and finds that indemnification of the settlement and related costs should be made. |
Insofar as indemnification for liabilities under the Securities Act may be permitted to the Managing Partner by the Partnership Agreement, the Partnership has been advised that in the opinion of the SEC and certain state securities authorities such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.
Right of Presentment
Each investor partner in the Partnership may request in writing that the Managing Partner purchase for cash all, but not less than all, of that investor partner’s interests subject to certain limitations, and the Managing Partner may cause its affiliate to fulfill its obligation to purchase such investor’s interests. Unless extended by the Managing Partner, partners may make such request in each of the years 2013 through 2018. If the interests are subsequently listed on a national securities exchange or are traded in the over-the-counter market, this right of presentment may be terminated at the option of the Managing Partner. Any such listing could have an adverse effect on the tax consequences of an investment in interests. If the obligation of the Managing Partner or its purchaser designee to purchase interests from general and limited partners is determined to violate any existing or future laws, such obligation will be eliminated or modified appropriately.
Assignability of Interests
Assignability of interests is limited. Except as required by law or in unusual circumstances when consented to by the Managing Partner, an investor partner in the Partnership may not assign less than its whole interest to any person unless such assignment is to the Partnership, the Managing Partner, an affiliate of the Managing Partner or a third person specified by the Managing Partner, and an investor partner must retain at least a whole interest in the event fewer than all of his interests are assigned to any person other than the Partnership, the Managing Partner, an affiliate of the Managing Partner, or a third person specified by the Managing Partner. In addition, the interests are subject to restrictions on transferability and resale under applicable securities laws and may not be transferred or resold except as permitted under applicable securities laws. Interests may only be assigned to a person otherwise qualified to become a substituted general partner or a limited partner, as the case may be. In no event may any assignment be made that, in the opinion of counsel to the Partnership, would result in the Partnership being considered to have been terminated for purposes of Section 708 of the Code or might result in a change in the status of the Partnership to a “publicly traded partnership” within the meaning of Section 7704 of the Code, unless the Managing Partner consents to such an assignment, or that, in the opinion of counsel to the Partnership, may not be effected without registration under the Securities Act or would result in the violation of any applicable state securities laws. The Partnership will not be required to recognize any assignment until the instrument of assignment has been delivered to the Managing Partner. In the case of a mere assignee of interests, the transferring general
22
partner or limited partner retains all rights other than the right to receive distributions as a general partner or limited partner. However, an assignee of interests may become a substituted general partner or limited partner, as the case may be, and thus be entitled to all of the rights of a general partner or limited partner, only upon meeting certain conditions, including:
| | • | | obtaining the consent of the assignor and the consent of the Managing Partner to such substitution, which consent may only be withheld to the extent legally necessary (as set forth in an opinion of counsel) to preserve the tax status of the Partnership or the classification of Partnership income for tax purposes, |
| | • | | paying all costs and expenses incurred in connection with such substitution, |
| | • | | making certain representations to the Managing Partner, and |
| | • | | executing appropriate documents to evidence its agreement to be bound by all of the terms and provisions of the Partnership Agreement. |
The Partnership will amend its records at least once each calendar quarter to effect the substitution of substituted partners. In the case of assignments, where the assignee does not become a substituted partner, the Partnership shall recognize the assignment not later than the last day of the calendar month following receipt of notice of assignment and required documentation. The restrictions on transfer contained in the Partnership Agreement may have the effect of reducing interest in the Partnership as a potential acquisition target or encouraging persons considering an acquisition or takeover of the Partnership to negotiate with the Managing Partner rather than pursue non-negotiated acquisition or takeover attempts, although no assurance can be given that they will have that effect.
The rights and obligations of the Managing Partner with respect to the Partnership may not be assigned except in limited circumstances set forth in the Partnership Agreement, including, without limitation, assignments to affiliates of the Managing Partner that agree to assume a proportionate share of the obligations of the assigning Managing Partner, dispositions arising out of the merger, consolidation, reorganization or similar transaction of the Managing Partner, and any pledge by the Managing Partner.
Removal or Withdrawal of the Managing Partner and the Program Manager
A majority in interest of the general and limited partners shall have the right to remove the Managing Partner and to elect and substitute a new managing partner. In such event, the removed managing partner shall be required to offer to sell a minimum of 20% of, and shall have the right to offer to sell the remaining 80% of, such managing partner’s interest, if any, in the Partnership to the new managing partner at a price and method of payment mutually agreeable to the removed managing partner and the new managing partner. Although the Managing Partner does not currently hold an equity interest in the Partnership, it may acquire such interest in the future. If the new managing partner and the removed managing partner are unable to agree within ten days on the purchase price of such interest, the new managing partner and the removed managing partner shall select a mutually agreeable independent expert to determine such purchase price. The method of payment for the removed managing partner’s interest must be fair and must protect the solvency and liquidity of the Partnership.
In the event the Managing Partner withdraws or retires from the Partnership and such withdrawal or retirement causes dissolution of the Partnership, a majority in interest of the general and limited partners shall be entitled to reconstitute the Partnership and elect and substitute a new managing partner. Such new managing partner shall be entitled to acquire the Partnership interest of the retiring managing partner on the same basis and in the same manner as set forth above. The Managing Partner may not voluntarily withdraw from the Partnership prior to the later to occur of (a) the completion of the Partnership’s primary drilling activities under the Program, and (b) the fifth anniversary of the date that general and limited partners were admitted to the Partnership. In order to exercise its right of withdrawal, the Managing Partner must give the general and limited partners at least 120 days’ advance written notice.
23
Dissolution, Liquidation and Termination of the Partnership
The Partnership shall be dissolved upon:
| | • | | the occurrence of December 31, 2059, |
| | • | | the vote or consent in writing of a majority in interest of the general and limited partners at any time, |
| | • | | the sale, disposition or termination of all or substantially all of the oil and gas leases then owned by the Partnership, |
| | • | | the withdrawal, bankruptcy, insolvency or dissolution in certain circumstances of the Managing Partner, the occurrence of any other event that would permit a trustee or receiver to acquire control of the property or affairs of the Managing Partner or any other event of withdrawal from the Partnership by the Managing Partner as provided for by law; provided that neither the dissolution of the Managing Partner as a consequence of merger, consolidation, recapitalization or other corporate reorganization effected under the Partnership Agreement shall cause dissolution of the Partnership, |
| | • | | the adjudication of insolvency or bankruptcy of the Partnership or an assignment by the Partnership for the benefit of creditors, |
| | • | | the withdrawal or retirement of the Managing Partner, or |
| | • | | the occurrence of any other event that, under applicable law, causes the dissolution of the Partnership. |
If dissolution of the Partnership occurs due to the withdrawal or bankruptcy of a general partner, the Partnership shall not be terminated but shall automatically be reconstituted. Upon dissolution of the Partnership for any reason other than bankruptcy or withdrawal of a general partner, unless it is reconstituted as provided under “—Rights and Powers of Partners” above, the Managing Partner or a liquidator appointed by the Managing Partner shall wind up the affairs of the Partnership and make final distribution of its assets. In the event the Managing Partner is unable to serve as liquidator, the liquidator shall be appointed by a majority in interest of the general and limited partners.
After making a proper accounting and paying or making provision for the payment of existing and contingent liabilities, the liquidator of the Partnership shall sell all remaining assets of the Partnership for cash at the best price available therefor and distribute the proceeds of such sales to the partners. In the case of a sale in liquidation, the liquidator shall adjust the capital accounts of the partners under the terms of the Partnership Agreement to account for all gain and loss on such sales and shall distribute the proceeds of such sales to the partners in accordance with their respective capital account balances, as so adjusted. Partners in the Partnership will not be obligated to restore any negative balance in their capital accounts after the liquidation of their interests in the Partnership. The distribution of cash or properties to the partners will constitute a complete distribution to the partners of their respective interests in the Partnership and its property.
In the event of a dissolution and liquidation of the Partnership as a result of an exchange or tender offer, the liquidator may assume the sale of all remaining assets of the Partnership for cash at the respective fair market values of such assets and then debit or credit each partner’s capital account with its respective share of the hypothetical gains or losses resulting from such assumed sales in the same manner as such capital account would be debited or credited on the actual sales of such assets. If such exchange or tender offer is conducted through a sale of all or substantially all of the assets of the Partnership or is otherwise binding on the partners, the liquidator shall distribute all securities or other assets received from the sale of the Partnership assets to the partners proportionately based on the partners’ positive capital account balances, as so adjusted. In the event of an exchange offer that is not binding upon all partners, the liquidator shall then exchange for securities offered in the exchange or tender offer Partnership
24
oil and gas properties having a fair market value equal to the sum of the positive balances in the capital accounts, as so adjusted, of the partners who elect to accept the exchange or tender offer. The liquidator shall distribute such securities to such accepting partners on a basis reflecting the partners’ respective positive capital account balances, adjusted as provided above.
Reconstitution of the Partnership
In the event the Managing Partner withdraws or retires from the Partnership, directly or as a result of a bankruptcy, dissolution, or similar event that would dissolve the Partnership, a majority in interest of general and limited partners, acting at a meeting to be held within 90 days following receipt of written notice of such event from the Managing Partner, shall be entitled to reconstitute the Partnership and elect and substitute a new managing partner, which may be the retiring managing partner.
In the event a majority in interest but less than all of the general and limited partners in the Partnership elect to reconstitute the Partnership, the partners’ capital accounts shall be adjusted by assuming the sale of all assets of the Partnership for cash at the respective fair market values of such assets as of the date of dissolution of the Partnership and debiting or crediting each partner’s capital account with its respective share of the hypothetical gains or losses resulting from such assumed sales in the same manner as such capital account would be debited or credited on the actual sales of such assets.
The new managing partner shall then sell for cash Partnership oil and gas properties having a fair market value equal to the fair market value of all Partnership oil and gas properties times the ratio of the aggregate of the positive balances in the capital accounts, as so adjusted, of the general and limited partners that have not elected to reconstitute the Partnership and the retiring managing partner, to the extent the retiring managing partner’s aggregate partnership interest was not purchased by the new managing partner, to the positive balances of all partners. The new managing partner shall then distribute such cash to the general and limited partners that have elected not to reconstitute the Partnership and to the Managing Partner, to such extent, in proportion to the positive balances of their respective capital accounts.
The new managing partner, on behalf of the partners that have elected not to form the reconstituted Partnership, shall retain for the benefit of the reconstituted Partnership an undivided interest in all oil and gas properties of the Partnership remaining after the distributions provided for above.
Each general partner of the Partnership will covenant not to cause a dissolution of the Partnership by voluntary withdrawal or other voluntary act. In the event of such a dissolution, however, upon reconstitution of the Partnership, the withdrawing general partner shall remain subject as a general partner with respect to any liabilities or obligations of the Partnership arising prior to such withdrawal. Upon withdrawal from the Partnership, a general partner is entitled to continue to receive any distributions to which he is otherwise entitled under the Partnership Agreement for the period prior to his withdrawal; however, such general partner shall not be entitled to receive the fair value of his interest in the Partnership as of the date of such withdrawal based upon his right to share in distributions from the Partnership, and neither the Partnership nor the Managing Partner has any obligation to repurchase any interest in the Partnership from the withdrawing general partner. The withdrawing general partner will not be entitled to receive any distributions for the period subsequent to his withdrawal nor shall such general partner have any rights as an investor partner under the Partnership Agreement. The sharing ratios will be recalculated among the general and limited partners without regard to the withdrawing general partner’s capital contribution. If the Partnership is reconstituted due to the bankruptcy of a general partner, the trustee, receiver or other successor in interest of the bankrupt general partner shall become liable for all of the debts and obligations of the bankrupt general partner.
Amendments
A majority in interest of the general and limited partners of the Partnership may require the amendment of the Partnership Agreement without the consent of the Managing Partner, except that any amendment that would increase the liability or duties of any partner, change the contributions required of a partner, provide for the reallocation of profits, losses or deductions to the detriment of a partner, establish any new priority in one or more partners as to the return of capital contributions or as to profits, losses, deductions or distributions to the detriment of
25
a partner or cause the Partnership to be taxed as a corporation, must be approved by such partner before it will be binding upon him. Minor and conformatory amendments and amendments that do not adversely affect the general and limited partners in any material respect may be made by the Managing Partner without the consent of the general and limited partners.
Reports to Partners
The Managing Partner will furnish to the general and limited partners of the Partnership semi-annual and annual reports that will contain financial statements, including a balance sheet and statements of income, partners’ equity and cash flows, all of which shall be prepared in accordance with generally accepted accounting principles, which statements at fiscal year end will be audited by an independent certified public accountant. Financial statements furnished in the Partnership’s semi-annual reports will not be audited. Semi-annually, all general and limited partners will also receive a summary itemization of the transactions between the Managing Partner or any affiliate of the Managing Partner and the Partnership showing all items of compensation received by the Managing Partner and its affiliates, including without limitation the average price paid by any affiliate of the Managing Partner during the two most recent calendar quarters for oil and gas produced by Program wells purchased by such affiliate and the highest average price paid by any other substantial purchaser of comparable oil or gas produced in the field where such Program wells are located.
Annually, beginning with the fiscal year ending December 31, 2010, oil and gas reserve estimates prepared by an independent petroleum engineer will also be furnished to the general and limited partners. Annual reports will be provided to the general and limited partners within 120 days after the close of the Partnership’s fiscal year, and semi-annual reports will be provided within 75 days after the close of the first six months of the Partnership’s fiscal year. The notes to the audited financial statements included in the annual reports will summarize the administrative costs reimbursements and operating fees and will disclose the allocation of administrative costs. In addition, the general and limited partners in the Partnership shall receive on a monthly basis while the Partnership is participating in the drilling and completion activities of the Program, reports containing a description of the Partnership’s acquisition of interests in prospects, including farmins and farmouts, and the drilling, completion and abandonment of wells thereon.
All general and limited partners will receive a report containing information necessary for the preparation of their federal income tax returns and any required state income tax returns by March 15 of each calendar year or as soon as practicable thereafter. The Managing Partner will furnish to the general and limited partners information regarding differences between tax basis of accounting and generally accepted accounting principles. General and limited partners in the Partnership will also receive in such monthly reports a summary of the status of wells drilled by the Partnership. The Managing Partner may provide such other reports and financial statements as it deems necessary or desirable.
Power of Attorney
In signing the subscription agreement, each investor adopted the terms and provisions of the Partnership Agreement, including representations and warranties contained in the Partnership Agreement, and made the power of attorney set forth in Section 10.2 of the Partnership Agreement. Pursuant to the Partnership Agreement, each investor partner of the Partnership appointed the Managing Partner as his attorney-in-fact, on his behalf and in his name, to execute, swear to and file all documents or instruments necessary or desirable:
| | • | | to comply with the laws of any state in which the Partnership does business, |
| | • | | to amend the Partnership Agreement to admit a new or substituted general partner or limited partner or make changes required by amendments thereto adopted by the general and limited partners, |
| | • | | to amend the Partnership Agreement to effect the conversion of the general partners to limited partners, |
26
| | • | | to conduct the business and affairs of the Partnership, |
| | • | | to reflect the agreement of all of the general and limited partners if the required majority in interest of the general and limited partners has approved any action under the Partnership Agreement and amendments to the Partnership Agreement to implement such action, and |
| | • | | to perform other ministerial acts in connection with the Partnership and its operations, all subject to compliance with the Partnership Agreement. |
Such appointment shall constitute a power coupled with an interest, shall not be revocable and was effectuated under Section 10.2 of the Partnership Agreement by an investor partner’s execution of the subscription agreement.
Drilling Program Agreement
Management
The Program is a partnership for income tax purposes only and, for all other purposes, is intended to be an agreement among MD and the Partnership, as joint owners of undivided working interests in the Program’s oil and gas properties, and MOC, as program manager. MOC, as program manager, has the power and authority to act on behalf of the Partnership with respect to the management, control, and administration of the business and affairs of the Program and the properties subject to the Drilling Program Agreement.
Term
The Program will continue until the occurrence of any of the following: (a) the dissolution of the Partnership, or (b) upon the election of MD after cessation of substantially all drilling activities of the Program; provided that, in the case of clause (b), that MD will have given at least 120 days’ notice to the partners of the Partnership prior to the termination.
Allocation of Costs and Revenues
Pursuant to the Drilling Program Agreement, the costs and revenues of the Program are allocated to MD and the Partnership as follows:
| | | | |
| | | Partnership | | MD |
Revenues: | | | | |
Interest earned on capital contributions of investor partners | | 100% | | 0% |
Proceeds from disposition of depreciable and depletable properties | | 75% | | 25% |
All other revenues | | 75% | | 25% |
| | |
Costs and expenses: | | | | |
Organization and offering costs(1) | | 0% | | 100% |
Lease acquisition costs(1) | | 0% | | 100% |
Tangible and intangible drilling costs(1) | | 100% | | 0% |
Operating costs, reporting and legal expenses, general and administrative expenses and all other costs | | 75% | | 25% |
| (1) | Pursuant to the Program, MD must contribute 100% of organization and offering costs and lease acquisition costs, which should approximate 17.65% of total capital costs. To the extent that organization and offering costs and lease acquisition costs are less than 17.65% of total capital costs, MD is responsible for tangible drilling costs until its share of the Program’s total capital costs reaches approximately 17.65%. The Partnership’s financial statements reflect its respective proportionate participation in the Program. |
27
Liability and Indemnification of Program Manager
The Program Manager and its affiliates have liability under the Drilling Program Agreement that is similar to the liability of the Managing Partner under the Partnership Agreement, and the Program Manager’s rights with respect to insurance and entitlement to indemnity are similar to the Managing Partner’s rights under the Partnership Agreement.
Removal of the Program Manager
The Partnership has the right to remove MOC as program manager and to elect and substitute a successor to act in the capacity as program manager; provided that, the Partnership will not have the right to remove MOC as program manager and to elect and substitute a successor to act in such capacity during the term that MD or any of its affiliates serve in the capacity of managing partner.
Assignment
The rights and obligations of the Managing Partner and its affiliates with respect to the Program under the Drilling Program Agreement may be assigned to affiliates and successors in interest by reason of merger, consolidation, reorganization or similar transaction, with the consent of a majority in interest of the general and limited partners of the Partnership, subject to limitations set forth in the Drilling Program Agreement, and the Managing Partner and its affiliates will have the right at any time to mortgage or pledge its interest in properties of the Program.
Amendment
The Drilling Program Agreement may only be amended in writing by MD and the Partnership; provided that, to the extent required under the terms of the Partnership Agreement, the Partnership will execute or have executed on its behalf such a written amendment only if the amendment has been approved by a majority in interest of the general and limited partners of the Partnership to the extent required by the Partnership Agreement. Minor and conformatory amendments or amendments that do not adversely affect in a material manner the general and limited partners of the Partnership do not require the consent of the Partnership.
| Item 12. | Indemnification of Directors and Officers. |
The Registrant does not have any officers or directors.
Section 5.4 of the Partnership Agreement provides that neither the Managing Partner nor any of its affiliates shall be liable to the Partnership or the general and limited partners for any loss suffered by the Partnership that arises out of any action or inaction performed or omitted by the Managing Partner or such affiliate if the Managing Partner in good faith has determined, as of the time of the conduct or omission, that such course of conduct or omission was in the best interest of the Partnership, that the Managing Partner or such affiliate was acting on behalf of or performing services for the Partnership, and that such conduct or omission did not constitute negligence or misconduct. Section 6(f)(i) of the Drilling Program Agreement provides parallel protection from liability to the Program Manager and its affiliates.
Section 5.5 of the Partnership Agreement provides that the Managing Partner and its affiliates shall be indemnified by the Partnership, only from the tangible net assets of the Partnership and not from other assets of the partners thereof, from and against all losses, judgments, liabilities, expenses and settlements sustained by the Managing Partner or any of its affiliates in connection with acts performed or omitted by the Managing Partner or any of its affiliates acting on behalf of, or performing services for, the Partnership or the Program; provided that, unless otherwise ordered by a court, the Managing Partner has determined in good faith, as of time of the conduct or omission, that the course of conduct or omission was in the best interests of the Partnership and that the conduct or omission did not constitute negligence or misconduct. Section 5.5(b) of the Partnership Agreement further limits indemnification of the Managing Partner by providing that the Managing Partner and its affiliates will not be indemnified for any losses, liabilities or expenses arising from or out of a violation of federal or state securities laws
28
unless (a) there has been a successful adjudication on the merits of each count involving alleged securities law violations as to the particular indemnitee and the court approves indemnification of the litigation costs, (b) such claims have been dismissed with prejudice on the merits by a court of competent jurisdiction as to the particular indemnitee and the court approves indemnification of the litigation costs, or (c) a court of competent jurisdiction approves a settlement of the claims against a particular indemnitee and finds that indemnification of the settlement and related costs should be made. Section 5.5(c) of the Partnership Agreement provides that the Partnership is authorized to purchase insurance against liabilities asserted against, and expenses incurred by, the Managing Partner and its affiliates in connection with the Partnership’s activities; provided that, the Partnership will not bear the cost of that portion of any insurance, other than insurance customary for the Partnership’s business, that insures the Managing Partner for any liability for which the Managing Partner may not be indemnified as discussed above. Pursuant to Section 6(f) of the Drilling Program Agreement, the Program Manager has similar rights with respect to insurance, and the Program Manager and its affiliates are entitled to similar indemnification.
Section 17-108 of the Delaware Limited Partnership Act provides that a Delaware limited partnership may indemnify and hold harmless any partner or other person from and against any and all claims and demands whatsoever.
As permitted by Section 102(b)(7) of the Delaware General Corporation Law (the “DGCL”), Article 10 of each of MD’s and MOC’s Certification of Incorporation contains a limitation of liability provision under which a director will not be personally liable to MD, MOC or their respective stockholders for monetary damages resulting from breaches of his fiduciary duty of care as a director, subject to certain limitations.
Article 7, Section 7 of each of MD’s and MOC’s By-laws provides that MD or MOC, as the case may be, shall indemnify its officer or director to the fullest extent permitted under the DGCL. Section 145 of the DGCL permits indemnification of an officer or director upon a determination that such officer or director has met the applicable standard of conduct. In order to meet such standard of conduct, such officer or director must have acted in good faith and in a manner he reasonably believed to be in, or not opposed to, the best interests of MD and, with respect to any criminal action, without reasonable cause to believe his conduct was unlawful. Section 145 of the DGCL does not authorize indemnification, in actions brought by or in the right of a corporation, against judgments, fines or amounts paid in settlement, nor does it provide for indemnification of expenses incurred in the defense or settlement of claims as to which a director or officer is adjudged to be liable to MD or MOC, as the case may be, unless specifically authorized by the Delaware Court of Chancery or the court in which such action is brought.
The above discussion of the provisions of Sections 5.4 and 5.5 of the Partnership Agreement, Section 6(f) of the Drilling Program Agreement, Section 17-108 of the Delaware Limited Partnership Act, Sections 102(b)(7) and 145 of the DGCL, Article 10 of each of MD’s and MOC’s Certificate of Incorporation, and Article 7, Section 7 of each of MD’s and MOC’s By-laws is not intended to be exhaustive and is respectively qualified in its entirety by the applicable provisions of the Partnership Agreement and Drilling Program Agreement, which are included as Exhibits 4.1 and 10.1 hereto and are hereby incorporated herein by reference, the Delaware Limited Partnership Act and the DGCL, Article 10 of each of MD’s and MOC’s Certificate of Incorporation, and Article 7, Section 7 of each of MD’s and MOC’s By-laws.
29
| Item 13. | Financial Statements and Supplementary Data. |
INDEX TO FINANCIAL STATEMENTS
The following balance sheets are those of the Managing Partner, in which the general and limited partners have no ownership interest.
30
Report of Independent Registered Public Accounting Firm
To the Partners of Mewbourne Energy Partners 09-A, L.P. and to the Board of Directors of Mewbourne Development Corporation
We have audited the accompanying balance sheet of Mewbourne Energy Partners 09-A, L.P. as of December 31, 2009 and the related statements of operations, change in partners’ capital, and cash flows for the period from February 26, 2009 (date of inception) through December 31, 2009. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Mewbourne Energy Partners 09-A, L.P. at December 31, 2009, and the results of its operations and its cash flows for the period from February 26, 2009 (date of inception) through December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.
|
| /s/ BDO Seidman, LLP |
|
| Dallas, Texas |
| April 30, 2010 |
31
MEWBOURNE ENERGY PARTNERS 09-A, L.P.
BALANCE SHEET
December 31, 2009
| | | | |
ASSETS | | | | |
| |
Cash and cash equivalents | | $ | 48,806,858 | |
Account receivables, affiliate | | | 654,629 | |
| | | | |
Total current assets | | | 49,461,487 | |
| | | | |
| |
Oil and gas properties at cost, full-cost method | | | 11,698,981 | |
Less accumulated depreciation, depletion, amortization and impairment | | | (130,217 | ) |
| | | | |
| | | 11,568,764 | |
| | | | |
| |
Total assets | | $ | 61,030,251 | |
| | | | |
| |
LIABILITIES AND PARTNERS’ CAPITAL | | | | |
| |
Accounts payable, affiliate | | $ | 27,164 | |
| | | | |
Total current liabilities | | | 27,164 | |
| | | | |
| |
Asset retirement obligation | | | 69,633 | |
| |
Partners’ capital | | | | |
General partners | | | 57,187,809 | |
Limited partners | | | 3,745,645 | |
| | | | |
Total partners’ capital | | | 60,933,454 | |
| | | | |
| |
Total liabilities and partners’ capital | | $ | 61,030,251 | |
| | | | |
The accompanying notes are an integral part of the financial statements.
32
MEWBOURNE ENERGY PARTNERS 09-A, L.P.
STATEMENT OF OPERATIONS
For the period from February 26, 2009 (date of inception) through December 31, 2009
| | | |
Revenues and other income: | | | |
Oil sales | | $ | 345,134 |
Gas sales | | | 173,899 |
Interest income | | | 2,521 |
| | | |
Total revenues and other income | | | 521,554 |
| | | |
| |
Expenses: | | | |
Lease operating expense | | | 7,673 |
Production taxes | | | 30,716 |
Administrative and general expense | | | 1,299 |
Depreciation, depletion and amortization | | | 130,217 |
Asset retirement obligation accretion | | | 345 |
| | | |
Total expenses | | | 170,250 |
| | | |
| |
Net Income | | $ | 351,304 |
| | | |
| |
Allocation of net income: | | | |
General partners | | $ | 329,709 |
| | | |
Limited partners | | $ | 21,595 |
| | | |
| |
Basic and diluted net income per partner interest | | | |
(13,242 interests outstanding) | | $ | 26.53 |
| | | |
The accompanying notes are an integral part of the financial statements.
33
MEWBOURNE ENERGY PARTNERS 09-A, L.P.
STATEMENT OF CHANGES IN PARTNERS’ CAPITAL
For the period from February 26, 2009 (date of inception) through December 31, 2009
| | | | | | | | | |
| | | General
Partners | | Limited
Partners | | Total |
| | | |
Balance at February 26, 2009 (date of inception) | | $ | — | | $ | — | | $ | — |
Capital contributions, net of sales commissions and marketing costs and net of $5,281,900 and $345,950 from general and limited partners, respectively | | | 56,858,100 | | | 3,724,050 | | | 60,582,150 |
| | | |
Net income | | | 329,709 | | | 21,595 | | | 351,304 |
| | | | | | | | | |
| | | |
Balance at December 31, 2009 | | $ | 57,187,809 | | $ | 3,745,645 | | $ | 60,933,454 |
| | | | | | | | | |
The accompanying notes are an integral part of the financial statements.
34
MEWBOURNE ENERGY PARTNERS 09-A, L.P.
STATEMENT OF CASH FLOWS
For the period from February 26, 2009 (date of inception) through December 31, 2009
| | | | |
Cash flows from operating activities | | | | |
Net income | | $ | 351,304 | |
Adjustments to reconcile net income to net cash used in operating activities: | | | | |
Depreciation, depletion and amortization | | | 130,217 | |
Asset retirement obligation accretion | | | 345 | |
Changes in operating assets and liabilities | | | | |
Account receivable, affiliate | | | (654,629 | ) |
Account payable, affiliate | | | 27,164 | |
| | | | |
Net cash used in operating activities | | | (145,599 | ) |
| | | | |
| |
Cash flows from investing activities | | | | |
Purchase and development of oil and gas properties | | | (11,629,693 | ) |
| | | | |
Net cash used in investing activities | | | (11,629,693 | ) |
| |
Cash flows from financing activities | | | | |
Capital contributions from partners, net of sales commissions and marketing costs totaling $5,627,850 | | | 60,582,150 | |
| | | | |
Net cash provided by financing activities | | | 60,582,150 | |
| | | | |
| |
Net increase in cash and cash equivalents | | | 48,806,858 | |
Cash and cash equivalents, beginning of period | | | — | |
| | | | |
| |
Cash and cash equivalents, end of period | | $ | 48,806,858 | |
| | | | |
| |
Supplemental Cash Flow Information: | | | | |
Non-cash changes to oil and gas properties related to asset retirement obligation liabilities | | $ | 69,288 | |
| | | | |
The accompanying notes are an integral part of the financial statements.
35
MEWBOURNE ENERGY PARTNERS 09-A
NOTES TO FINANCIAL STATEMENTS
1. Significant Accounting Policies
Nature of Business
Mewbourne Energy Partners 09-A, L.P., (the “Registrant” or the “Partnership”), a Delaware limited partnership engaged primarily in oil and gas development and production in Texas, Oklahoma, and New Mexico, was organized on February 26, 2009. The offering of limited and general partner interests began May 1, 2009 as a part of a private placement pursuant to Section 4(2) of the Securities Act of 1933 and Regulation D promulgated thereunder, and concluded August 28, 2009, with total investor contributions of $66,210,000 originally being sold to accredited investors of which $62,140,000 were sold to accredited investors as general partner interests and $4,070,000 were sold to accredited investors as limited partner interests. The managing general partner, Mewbourne Development Corporation (“MD”), has no equity interest in the Partnership.
The Partnership conducts its activities under a drilling program (the “Program”). Its sole business is the development and production of oil and gas with a concentration on gas. A substantial portion of the Program’s gas production is being sold regionally in the spot market. Due to the highly competitive nature of the spot market, prices are subject to seasonal and regional pricing fluctuations. In addition, such spot market sales are generally short-term in nature and are dependent upon obtaining transportation services provided by pipelines. The prices received for the Program’s oil and gas are subject to influences such as global consumption and supply trends.
Under the terms of the partnership agreement for the Partnership, general and limited partners have the following rights and powers:
| | (a) | to participate in costs and revenues, |
| | (b) | to inspect the Partnership’s books and records, |
| | (c) | to receive information regarding the Partnership, |
| | (d) | to have a dissolution of the Partnership by decree of a court, |
| | (e) | to reconstitute the Partnership by a majority vote upon an event that would otherwise dissolve the Partnership, |
| | (f) | to terminate by a majority vote any contract between the Partnership and MD or its affiliates, |
| | (g) | to approve by a majority vote the sale of all or substantially all of the Partnership’s assets, |
| | (h) | to dissolve the Partnership by a majority vote, |
| | (i) | to permit by a majority vote the assignment by the Partnership or MD of their obligations under the Drilling Program Agreement, |
| | (j) | to agree by a majority vote to the termination or amendment of the Drilling Program Agreement, |
| | (k) | to remove by majority vote the managing partner of the Partnership or the program manager of the Program, and |
| | (l) | to propose and vote on certain matters described in the partnership agreement. |
Except for the rights described in clauses (a) through (l) of the immediately preceding sentence, limited partners will have no voice in the management or operations of the Partnership or the Program. The general partners of the Partnership delegate to the managing general partner the responsibility for the day-to-day operations of the Partnership. The managing general partner has full and exclusive power, except as limited by the partnership agreement and applicable law, to manage, control, administer and operate the properties, business and affairs of the Partnership.
MD does not make any capital contributions directly to the Registrant; rather, MD makes its capital contributions directly to the Program. MD contributes to the Program the oil and gas leases upon which the Program conducts its operations. The contribution of oil and gas leases to the Program is credited to the Program at the lease acquisition costs of the oil and gas leases contributed or at fair market value if the lease acquisition costs are materially more than fair market value. Consequently, MD does not receive a percentage of profits or distributions from the Partnership; rather, MD participates in revenues and costs at the Program level.
36
MEWBOURNE ENERGY PARTNERS 09-A
NOTES TO FINANCIAL STATEMENTS—(Continued)
Accounting for Oil and Gas Producing Activities
The Partnership follows the full-cost method of accounting for its oil and gas activities. Under the full-cost method, all productive and non-productive costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized. Depreciation, depletion and amortization of oil and gas properties subject to amortization is computed on the units-of-production method based on the proved reserves underlying the oil and gas properties. At December 31, 2009 approximately $8.3 million of development in progress capitalized costs were excluded. Proceeds from the sale or other disposition of properties are credited to the full cost pool. Gains and losses are not recognized unless such adjustments would significantly alter the relationship between capitalized costs and the proved oil and gas reserves. Capitalized costs are subject to a quarterly ceiling test that limits such costs to the aggregate of the present value of future net cash flows of proved reserves and the lower of cost or fair value of unproved properties. There were no cost ceiling write-downs during the period from February 26, 2009 (date of inception) through December 31, 2009.
MOC, the program manager, initially purchases oil and gas leases from landowners. MD, the Partnership’s managing general partner, then purchases from MOC and contributes to the Program the oil and gas leases upon which the Program conducts its operations. MD’s contribution of oil and gas leases to the Program is credited to the Program at MOC’s carryover basis.
Significant estimates inherent in the Registrant’s financial statements include the estimate of oil and gas reserves and future abandonment costs. Changes in oil and gas prices and the changes in production estimates could have a significant effect on reserve estimates. The reserve estimates directly impact the computation of depreciation, depletion, and amortization, asset retirement obligation, and the ceiling test for the Registrant’s oil and gas properties.
In December 2008, the SEC issued its final rule for Modernization of Oil and Gas Reporting. Pursuant to this rule the SEC adopted revisions to its oil and gas reporting disclosures effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves, which should help investors evaluate the relative value of oil and gas entities. In the three decades that have passed since the original adoption of oil and gas disclosure items, there have been significant changes in the oil and gas industry. These revisions are designed to modernize and update the oil and gas disclosure requirements to align them with current practices and changes in technology.
The new rules include provisions that permit the use of new technologies to determine proved reserves. The requirements require entities to report any third party that is relied upon to prepare or audit reserve estimates. In addition, the new rules require that oil and gas reserves be reported and the full cost ceiling value calculated using average first-of-the-month natural gas and oil prices during the twelve month period ending in the reporting period.
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Subsequent Events
In the preparation of its financial statements, the Partnership considered subsequent events through April 30, 2010, which was the filing date of the Partnership’s financial statements.
New Accounting Pronouncements
Modernization of Natural Gas and Oil Reporting. In January 2009, the SEC issued revisions to the natural gas and oil reporting disclosures, “Modernization of Oil and Gas Reporting, Final Rule” (the “Final Rule”). In January 2010, the FASB updated its oil and gas estimation and disclosure requirements to align its requirements with the SEC’s modernized oil and gas reporting rules, which are described above. The update amends the definition of proved
37
MEWBOURNE ENERGY PARTNERS 09-A
NOTES TO FINANCIAL STATEMENTS—(Continued)
reserves to use the average of first-day-of-the-month prices during the twelve months preceding the end of the reporting period, adds definitions used in estimating and disclosing proved oil and natural gas quantities and expands the disclosures required for equity-method investments. The Partnership adopted the new standards effective December 31, 2009.
FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles. In June 2009, the Financial Accounting Standards Board (“FASB”) issued guidance on the accounting standards codification and the hierarchy of generally accepted accounting principles. The accounting standards codification is intended to be the source of authoritative US GAAP and reporting standards as issued by the FASB. Its primary purpose is to improve clarity and use of existing standards by grouping authoritative literature under common topics. The accounting standards codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Partnership describes the authoritative guidance used within the footnotes without any numerical references as per this accounting standards codification. The accounting standards codification does not change or alter existing US GAAP.
Cash and Cash Equivalents
The Partnership maintains all its cash in one financial institution. At various times throughout the year, the cash amount may be in excess of the amount insured by the Federal Deposit Insurance Corporation (“FDIC”). At December 31, 2009, cash did not exceed the amount insured by the FDIC.
Fair Value of Financial Instruments
The Financial Accounting Standards Board (“FASB”) has issued guidance on determining the estimated fair value for financial instruments. This disclosure states that the fair value of financial instruments is determined at discrete points in time based on relevant market information. Such estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature.
Asset Retirement Obligations
The Partnership has recognized an estimated liability for future plugging and abandonment costs. The estimated liability is based on historical experience and estimated well life. The liability is discounted using the credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in well plugging and abandonment costs or well useful lives, or if federal or state regulators enact new well restoration requirements. The Partnership recognizes accretion expense in connection with the discounted liability over the remaining life of the well.
The Partnership measures the fair values of nonfinancial assets measured at fair value on a non-recurring basis at the estimated price that would be received upon the sale of the asset in an orderly transaction between market participants at the measurement date. These estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Partnership has designated these liabilities as Level 3, which means they are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. they are supported by little or no market activity).
38
MEWBOURNE ENERGY PARTNERS 09-A
NOTES TO FINANCIAL STATEMENTS—(Continued)
A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the period from February 26, 2009 (date of inception) through December 31, 2009 is as follows:
| | | |
Balance, beginning of period | | $ | — |
Liabilities incurred | | | 69,288 |
Accretion expense | | | 345 |
| | | |
| |
Balance, end of period | | $ | 69,633 |
| | | |
Oil and Gas Sales
The Program’s oil and condensate production is sold and revenue recognized at or near the Program’s wells under short-term purchase contracts at prevailing prices in accordance with arrangements which are customary in the oil industry. Sales of gas applicable to the Program’s interest are recorded as revenue when the gas is metered and title transferred pursuant to the gas sales contracts covering the Program’s interest in gas reserves. The Partnership uses the sales method to recognize oil and gas revenue whereby revenue is recognized for the amount of production taken regardless of the amount for which the Partnership is entitled based on its working interest ownership. As of December 31, 2009, no material gas imbalances between the Partnership and other working interest owners existed.
Substantially all of the Partnership’s accounts receivable result from oil and natural gas sales to third parties in the oil and natural gas industry. This concentration of customers may impact the Partnership’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, the Partnership has not experienced significant credit losses on such receivables. No bad debt expense was recorded in 2009. The Partnership cannot ensure that such losses will not be realized in the future.
Income Taxes
The Partnership is treated as a partnership for income tax purposes and, as a result, income of the Partnership is reported on the tax returns of the partners and no recognition is given to income taxes in the financial statements. The Partnership’s financial reporting bases of its net assets exceeded the tax bases of its net assets by $11,101,794 at December 31, 2009.
2. Organization and Related Party Transactions
The Partnership was organized on February 26, 2009 in accordance with the laws of the state of Delaware. MD, a Delaware Corporation, has been appointed as the Registrant’s managing general partner. MD has no equity interest in the Registrant. MOC is operator of oil and gas properties owned by the Partnership. Mewbourne Holdings, Inc. is the parent of both MD and MOC. Substantially all transactions are with MD and MOC.
In the ordinary course of business, MOC will incur certain costs that will be passed on to well owners of the well on which the costs were incurred. The Partnership will be charged their portion of these costs based upon their ownership in each well incurring the costs. These costs are referred to as operator charges and are standard and customary in the oil and gas industry. Operator charges include recovery of gas marketing costs, fixed rate overhead, supervision, pumping, and equipment furnished by the operator, some of which will be included in the full cost pool pursuant to Rule 4-10(c)(2) of Regulation S-X. Reimbursement to MOC for operator charges totaled $188,152 for the period beginning February 26, 2009 (date of inception) through December 31, 2009, respectively. Operator charges are billed in accordance with the Program and Partnership Agreements.
In consideration for services rendered by MD in managing the business of the Partnership, the Partnership during each of the initial three years of the Partnership pays to MD a management fee in the amount equal to .75 of 1% of the subscriptions by the investor partners to the Partnership. Management fees can only be paid out of funds available for distributions. No management fees were allocated to the Partnership for the period beginning February 26, 2009 (date of inception) through December 31, 2009. In the periods in which management fees are paid, the Partnership includes them as part of the full cost pool pursuant to Rule 4-10(c)(2) of Regulation S-X.
39
MEWBOURNE ENERGY PARTNERS 09-A
NOTES TO FINANCIAL STATEMENTS—(Continued)
In general, during any particular calendar year, the total amount of administrative expenses allocated to the Partnership by MOC shall not exceed the greater of (a) 3.5% of the Partnership’s gross revenue from the sale of oil and natural gas production during each year (calculated without any deduction for operating costs or other costs and expenses) or (b) the sum of $50,000 plus .25% of the capital contributions of limited and general partners. Administrative expenses can only be paid out of funds available for distributions. Under this arrangement, $363 was allocated to the Partnership during the period beginning February 26, 2009 (date of inception) through December 31, 2009.
The Partnership participates in oil and gas activities through the Program. The Drilling Program Agreement provides that MOC, in its capacity as manager of the Program, will have the exclusive power and authority to act on behalf of the Partnership with respect to the management, control and administration of the business and affairs of the Program and the oil and gas properties subject to the Drilling Program Agreement. The Drilling Program Agreement sets out the rights, duties, and obligations of the program manager and the other participants in the Program. The Partnership and MD are parties to the Program Agreement. The costs and revenues of the Program are allocated to MD and the Partnership as follows:
| | | | |
| | | Partnership | | MD |
Revenues: | | | | |
Proceeds from disposition of depreciable and depletable properties | | 75% | | 25% |
All other revenues | | 75% | | 25% |
Costs and expenses: | | | | |
Organization and offering costs(1) | | 0% | | 100% |
Lease acquisition costs(1) | | 0% | | 100% |
Tangible and intangible drilling costs(1) | | 100% | | 0% |
Operating costs, reporting and legal expenses, general and administrative expenses and all other costs | | 75% | | 25% |
| (1) | As noted above, pursuant to the Program, MD must contribute 100% of organization and offering costs and lease acquisition costs which should approximate 17.65% of total capital costs. To the extent that organization and offering costs and lease acquisition costs are less than 17.65% of total capital costs, MD is responsible for tangible drilling costs until its share of the Program’s total capital costs reaches approximately 17.65%. The Partnership’s financial statements reflect its respective proportionate participation in the Program. |
3. Supplemental Oil and Gas Information (unaudited)
The tables presented below provide supplemental information about oil and natural gas exploration and production activities.
Costs Incurred and Capitalized Costs:
Costs incurred in oil and natural gas acquisition, exploration and development activities for the period from February 26, 2009 (date of inception) through December 31, 2009 were:
| | | | | |
| | | Gross | | Net |
Development Wells | | | | | |
Oil and natural gas wells | | | 7 | | 1.395 |
Non-productive wells | | | 1 | | 0.314 |
| | |
| | | 2009 | | |
| | |
Development | | $ | 11,629,693 | | |
| | | | | |
40
MEWBOURNE ENERGY PARTNERS 09-A
NOTES TO FINANCIAL STATEMENTS—(Continued)
Capitalized costs related to oil and natural gas acquisition, exploration and development activities for the period from February 26, 2009 (date of inception) through December 31, 2009 were as follows:
| | | | |
Costs of oil and natural gas properties at year-end: | | | | |
Producing assets – Proved Properties | | $ | 3,265,700 | |
Development in progress | | | 8,363,993 | |
Asset retirement obligation | | | 69,288 | |
| | | | |
Total capitalized cost | | | 11,698,981 | |
Accumulated deprecation, depletion, amortization and impairment | | | (130,217 | ) |
| | | | |
Net capitalized costs | | $ | 11,568,764 | |
| | | | |
Estimated Net Quantities of Proved Oil and Gas Reserves:
Reserve estimates as well as certain information regarding future production and discounted cash flows were determined by MOC’s petroleum engineers in accordance with guidelines established by the Securities and Exchange Commission and the FASB’s accounting standards. The Partnership considers reserve estimates to be reasonable; however, due to inherent uncertainties and the limited nature of reservoir data, estimates of oil and gas reserves are imprecise and subject to change over time as additional information becomes available.
These reserve estimates have been prepared based on the average first-of-the-month natural gas and oil prices for the period from February 26, 2009 (date of inception) through December 31, 2009. There have been no favorable or adverse events that have caused a significant change in estimated proved reserves since December 31, 2009. The Partnership has no long-term supply agreements or contracts with governments or authorities in which it acts as producer nor does it have any interest in oil and gas operations accounted for by the equity method. All reserves are located onshore within the United States. All proved reserves are developed; therefore, the Partnership has no proved undeveloped properties as of December 31, 2009.
| | | | | | |
| | | Crude Oil
and
Condensate
(MBbl) | | | Natural
Gas
(MMcF) | |
Proved Reserves: | | | | | | |
Balance at February 26, 2009 (date of inception) | | — | | | — | |
Extensions, discoveries and other additions | | 52,022 | | | 1,144,527 | |
Production | | (4,806 | ) | | (29,284 | ) |
| | | | | | |
Balance at December 31, 2009(1) | | 47,216 | | | 1,115,243 | |
| | | | | | |
| (1) | All of these reserves are categorized as proved as of December 31, 2009. |
Technologies Used in Reserves Estimation
Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil technologies that an entity can use to establish reserves. The SEC now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To achieve reasonable certainty, MOC’s petroleum engineers employ technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of the proved
41
MEWBOURNE ENERGY PARTNERS 09-A
NOTES TO FINANCIAL STATEMENTS—(Continued)
reserves may include, but are not limited to, empirical evidence through drilling results and well performance, well logs, geologic maps and available downhole and production data, seismic data, well test data and reservoir simulation modeling.
42
Report of Independent Auditors
To the Board of Directors and Stockholder of
Mewbourne Development Corporation
Tyler, Texas
We have audited the accompanying balance sheet of Mewbourne Development Corporation (the “Company”) as of June 30, 2009. The balance sheet is the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Mewbourne Development Corporation at June 30, 2009, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
/s/ BDO SEIDMAN, LLP
December 14, 2009
43
MEWBOURNE DEVELOPMENT CORPORATION
BALANCE SHEET
June 30, 2009
| | | |
Assets | | | |
Current assets | | | |
Cash and cash equivalents | | $ | 7,147,531 |
Accounts receivable, related party | | | 3,364,834 |
| | | |
| |
Total current assets | | | 10,512,365 |
| |
Investments in partnerships | | | 952,883 |
Oil and gas properties - full-cost method, net | | | 54,436,448 |
| | | |
| |
Total assets | | $ | 65,901,696 |
| | | |
| |
Liabilities and stockholder’s equity | | | |
Current liabilities | | | |
Accounts payable, related party | | $ | 3,018,642 |
| | | |
Total current liabilities | | | 3,018,642 |
| |
Long term debt | | | 97,222 |
Deferred income taxes | | | 2,353,954 |
Asset retirement obligation | | | 2,268,365 |
| | | |
| |
Total liabilities | | | 7,738,183 |
| | | |
| |
Commitments and contingencies | | | |
| |
Stockholder’s equity | | | |
Common stock, $1 par value, 1,000 shares authorized, issued and outstanding | | | 1,000 |
Paid-in capital in excess of par value of common stock | | | 1,190,262 |
Retained earnings | | | 56,972,251 |
| | | |
| |
Total stockholder’s equity | | | 58,163,513 |
| | | |
| |
Total liabilities and stockholder’s equity | | $ | 65,901,696 |
| | | |
See accompanying notes to financial statements.
44
MEWBOURNE DEVELOPMENT CORPORATION
NOTES TO BALANCE SHEET
1. Significant Accounting Policies
Financial Statement Presentation
Mewbourne Development Corporation (the “Company”) is a wholly-owned subsidiary of Mewbourne Holdings, Inc. (the “Stockholder”). The Company is principally involved in the exploration and production of oil and gas in Texas, Oklahoma and New Mexico.
Oil and Gas Properties
The Company follows the full-cost method of accounting for its oil and gas activities, all of which are located in the Continental United States. Under the full-cost method, all productive and nonproductive costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized. All such costs are directly identified with acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead, or similar activities. Depreciation, depletion and amortization of oil and gas properties are computed on the units-of-production method, using the proved reserves underlying the oil and gas properties. Unproved oil and natural gas properties are excluded from the calculation of depreciation, depletion and amortization until it is determined whether or not proved reserves can be assigned to such properties. At June 30, 2009, $631,210 was considered unproved property costs. Gains and losses on the sale or other disposition of properties are not recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas.
Included in capitalized costs are organization and offering costs related to the offering of certain partnerships in which the Company is the managing partner. These partnerships were formed to acquire interest in oil and gas properties and the Company received its interest in these oil and gas properties through its contribution of these organization and offering costs. Depreciation, depletion and amortization of capitalized organization and offering cost are computed on the units-of-production method using the proved reserves and depletion rate of each partnership for which the organization and offering costs were incurred.
Capitalized costs are subject to a ceiling test that limits such costs to the aggregate of the present value of future net revenues of proved reserves discounted at 10%, based on oil and gas prices and operating conditions at the balance sheet date, and the lower of cost or fair value of unproved properties. There was a ceiling write-down of $16,935,018 at June 30, 2009.
Management’s Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
In addition, oil and gas reserves and dismantlement costs require significant estimates which could materially differ from amounts ultimately realized.
Cash and Cash Equivalents
The Company considers all highly liquid investments, those with original maturities of three months or less at the date of acquisition, to be cash equivalents.
A substantial portion of the Company’s cash and cash equivalents is maintained in one financial institution which the Company believes to be of high credit quality.
45
MEWBOURNE DEVELOPMENT CORPORATION
NOTES TO BALANCE SHEET—(Continued)
Fair Value of Financial Instruments
The carrying values of cash and cash equivalents, accounts receivable, and accounts payable approximate their fair values because of the short maturity or duration of these instruments. The fair value of the Company’s long-term debt approximates carrying value due to the terms available to the Company for similar financial instruments.
Investments in Partnerships
The Company is the managing partner of several oil and gas partnerships. The Company accounts for its investment in partnerships using the equity method of accounting.
Asset Retirement Obligations
The Company is required to record the fair value of liabilities associated with the retirement of long-lived assets. A liability for the estimated fair value of the future plugging and abandonment costs is recorded with a corresponding increase in the full cost pool at the time a new well is drilled. The Company recognizes accretion expense in connection with the discounted liability over the remaining life of the well.
Subsequent Events
In preparation of its financial statements, the Company considered subsequent events through December 14, 2009, which was the date the Company’s financial statements were available to be issued.
2. Oil and Gas Properties
Oil and gas properties consist of the following:
| | | | |
June 30, | | 2009 | |
Proved oil and gas properties | | $ | 107,289,502 | |
Unproved oil and gas properties | | | 631,210 | |
Accumulated depreciation, depletion and amortization | | | (53,484,264 | ) |
| | | | |
| |
Net oil and gas properties | | $ | 54,436,448 | |
| | | | |
3. Long-Term Debt
On December 31, 2007, the Company renewed its bank revolving credit agreement, extending the maturity date of its $4,000,000 revolving line of credit. The Company can borrow under the bank revolving credit agreement from December 31, 2007 to December 31, 2012. Principal outstanding and unpaid on January 1, 2010 will be payable in 36 equal monthly installments until the Note is paid in full on December 31, 2012. The Company has the option to borrow at either the prime rate minus .25% or at the Eurodollar Fixed Period Rate, plus 2.5%.
The bank revolving credit agreement also contains certain covenants including the maintenance of minimum proven oil and gas reserves. The bank revolving credit agreement is uncollateralized; however, the Company is subject to certain negative covenants. As of June 30, 2009, the Company has $97,222 outstanding under this revolving credit agreement and has $3,902,778 available for borrowing.
4. Asset Retirement Obligation
The Company has recognized an estimated liability for future plugging and abandonment costs. The estimated liability is based on historical experience and estimated well life. The liability is discounted using the credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in well plugging and abandonment costs or well useful lives, or if federal or state regulators enact new property restoration requirements. The Company recognizes accretion expense in connection with the discounted liability over the remaining life of the well.
46
MEWBOURNE DEVELOPMENT CORPORATION
NOTES TO BALANCE SHEET—(Continued)
A reconciliation of the Company’s liability for well plugging and abandonment costs for the year ended is as follows:
| | | |
June 30, | | 2009 |
Balance at June 30, 2009 | | $ | 1,852,885 |
Liabilities incurred during period | | | 301,355 |
Accretion expense | | | 114,125 |
| | | |
| |
Balance at June 30, 2009 | | $ | 2,268,365 |
| | | |
5. Fair Value Measurement
Effective July 1, 2008, the Company adopted SFAS No. 157,Fair Value Measurements (SFAS No. 157). SFAS No. 157 clarifies the definition of fair value, prescribes methods for measuring fair value, establishes a fair value hierarchy based on the inputs used to measure fair value and expands disclosures about the use of fair value measurements. The adoption of SFAS No. 157 did not have a material impact on the Company’s fair value measurements.
Beginning July 1, 2008, assets and liabilities recorded at fair value in the balance sheets are categorized based upon the level of judgment associated with the inputs used to measure their fair value. Level inputs are as follows:
| | |
Level Input | | Input Definition |
| |
| Level 1 | | Observable inputs are unadjusted, quoted prices for identical assets or liabilities in active markets at the measurement date. Level 1 securities include Government securities, debt securities, certain common stocks, and cash and cash equivalents. |
| |
| Level 2 | | Observable inputs other than quoted prices included in Level 1 that are observable for the asset or liability through corroboration with market data at the measurement date. |
| |
| Level 3 | | Unobservable inputs that reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. |
The Company has no assets or liabilities that are within the provisions of SFAS 157.
6. Income Taxes
Federal and state income tax is calculated at the Stockholder level and allocated to the subsidiaries based on pretax income. The Company calculates its deferred tax liability as if it were a separate tax paying entity. Deferred income taxes are recognized for the tax consequences in future years of differences between the tax basis of assets and liabilities and their financial reporting amounts at the balance sheet date based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances are established when necessary to reduce deferred tax assets to the amount expected to be realized. As of June 30, 2009, federal and state income taxes payable to the Stockholder were $859,024, which is included in accounts payable, related party in the accompanying balance sheet.
The deferred tax liability at June 30, 2009 is primarily attributable to the differences in the book and tax basis of oil and gas properties between the income and tax basis of accounting and generally accepted accounting principles.
47
MEWBOURNE DEVELOPMENT CORPORATION
NOTES TO BALANCE SHEET—(Continued)
7. Commitments and Contingencies
The Company is obligated, subject to certain limitations, to purchase or cause to be purchased by an affiliate or the Stockholder, limited partnership interests, if tendered. The purchase price is based on a defined formula pursuant to the Partnership agreement and is intended to represent fair value. For the majority of the partnerships in which this obligation exists, the obligation generally commences once the partnership has been in existence for 3 years and extends for a period of 5 years; on certain others, the obligation remains throughout the life of the partnership. The obligation to purchase interests in a single calendar year is generally limited to no more than 5% of the total number of interests of the partnership outstanding at the beginning of the calendar year. Additionally, the total amount of limited partnership interests which the Company is obligated to purchase upon redemption is limited to $500,000 per year. If the partnership interests are tendered in future years, it is anticipated that the Company or Stockholder will use funds provided by operations or borrow funds to satisfy such repurchase obligations. Historically, the amount of limited partnership interests tendered has been immaterial.
At June 30, 2009, the Company had a funding requirement of approximately $15,223,829 to Mewbourne Energy Partners 08-A L.P., an affiliated partnership.
8. Related Party Transactions
Mewbourne Oil Company (“MOC”), a wholly owned subsidiary of the Stockholder, acts as operator of substantially all oil and gas properties in which the Company invests. Under the terms of the operating agreements, oil and gas sales are collected by MOC and remitted to the Company and lease operating expenses and production taxes are billed by and paid to MOC. Additionally, MOC charges the Company for general and administrative expenses in accordance with the partnership and program agreements. For the year ended June 30, 2009, $1,137,176 was included in general and administrative expenses for such fees. MOC remits revenues to the Company and bills the company for expenses on a monthly basis. At June 30, 2009, accounts receivable, related party consists of revenues receivable from MOC and accounts payable, related party consists of $3,877,666 payable to MOC for expenses and $859,024 due to the Stockholder for income taxes. The Company considers the amounts receivable from MOC to be fully collectible.
9. Supplemental Oil and Gas Information (Unaudited)
The tables presented below provide supplemental information about oil and gas exploration and production activities as defined by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.”
Capitalized costs related to oil and gas acquisition, exploration and development activities at June 30, 2009 are as follows:
| | | | |
June 30, | | 2009 | |
Proved property costs | | $ | 43,502,728 | |
Unproved property costs | | | 631,209 | |
Producing assets | | | 62,744,775 | |
Other | | | 1,042,000 | |
| | | | |
| |
Total capitalized costs | | | 107,920,712 | |
Accumulated depreciation, depletion and amortization | | | (53,484,264 | ) |
| | | | |
| |
Net capitalized costs | | $ | 54,436,448 | |
| | | | |
48
MEWBOURNE DEVELOPMENT CORPORATION
NOTES TO BALANCE SHEET—(Continued)
Costs incurred in property acquisitions and development activities during the year ended June 30, 2009 are as follows:
| | | |
June 30, | | 2009 |
Proved property acquisition costs | | $ | 8,169,919 |
Development costs | | | 14,802,840 |
| | | |
| |
Total | | $ | 22,972,759 |
| | | |
Depletion, depreciation and amortization per equivalent unit of oil production for the year ended June 30, 2009 was $9.56.
The estimates of proved oil and gas reserves utilized in the preparation of these financial statements were estimated in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board, which require that reserve reports be prepared using oil and gas prices and operating conditions at the balance sheet date with no provision for price and cost escalation except by contractual agreement. Proved oil and gas reserves are defined as estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. These estimates may change as future information becomes available. All of the Company’s reserves are located onshore in the Continental United States.
Changes in proved oil and gas reserves for the year ended June 30, 2009 are as follows:
| | | | | |
| | | Gas
(MMcf) | | | Oil
(MBbls) |
Proved reserves at June 30, 2008 | | 33,406 | | | 563 |
Revisions to previous estimates | | (5,233 | ) | | (24) |
Extensions, discoveries and other additions | | 10,743 | | | 363 |
Production | | (4,213 | ) | | (115) |
| | | | | |
| | |
Proved reserves at June 30, 2009 | | 34,703 | | | 787 |
| | | | | |
Substantially all of the Company’s proved reserves at June 30, 2009 are developed.
As required by the Financial Accounting Standards Board, the standardized measure of discounted future cash flows is computed by applying year-end prices and costs and a discount factor of 10 percent to net proved reserves. The price of oil and gas used in the standardized measure of discounted future cash flows at June 30, 2009 is $65.87 per barrel and $3.52 per mcf, respectively.
The Company believes the standardized measure does not provide a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including year-end prices, which represent a single point in time and therefore may cause significant variability in cash flows from year to year as prices change.
49
MEWBOURNE DEVELOPMENT CORPORATION
NOTES TO BALANCE SHEET—(Continued)
The standardized measure of discounted future net cash flows as of June 30, 2009 is as follows:
| | | | |
June 30, | | 2009 | |
Future cash inflows | | $ | 174,068,641 | |
Future production costs | | | (66,462,750 | ) |
Future development costs | | | (2,752,394 | ) |
Future income tax expense | | | (3,886,461 | ) |
| | | | |
| | | 100,967,036 | |
Discount at ten percent | | | (50,192,334 | ) |
| | | | |
| |
Standard measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes | | $ | 50,774,702 | |
| | | | |
Changes in the standardized measure of discounted future net cash flows for the year ended June 30, 2009 are as follows:
| | | | |
June 30, | | 2009 | |
Standardized measure of discounted future net cash flows at June 30, 2008 | | $ | 119,880,845 | |
Change in value of previous year reserved due to: | | | | |
Value of reserves added due to extensions, discoveries and other additions | | | 19,905,563 | |
Accretion of discount | | | 35,475,899 | |
Development costs incurred during the year | | | 3,718,614 | |
Changes in estimated development costs | | | (633,758 | ) |
Sales of oil and gas produced during the year, net of production costs | | | (26,646,587 | ) |
Revisions of previous reserve estimates | | | (19,482,707 | ) |
Net change in prices | | | (138,798,679 | ) |
Net change in income taxes | | | 34,255,574 | |
Timing and other | | | 23,099,938 | |
| | | | |
| |
Standardized measure of discounted future net cash flows at June 30, 2009 | | $ | 50,774,702 | |
| | | | |
50
Accountants’ Review Report
To the Board of Directors and Stockholder of Mewbourne Development Corporation
Tyler, TX
We have reviewed the accompanying balance sheet of Mewbourne Development Corporation (the “Company”) as of December 31, 2009, in accordance with Statements on Standards for Accounting and Review Services issued by the American Institute of Certified Public Accountants. All information included in these financial statements is the representation of the management of Mewbourne Development Corporation.
A review consists principally of inquiries of company personnel and analytical procedures applied to financial data. It is substantially less in scope than an audit in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying balance sheet in order for them to be in conformity with generally accepted accounting principles.
/s/ BDO SEIDMAN, LLP
April 30, 2010
51
MEWBOURNE DEVELOPMENT CORPORATION
BALANCE SHEET
December 31, 2009
(Unaudited)
| | | |
Assets | | | |
| |
Current assets | | | |
Cash and cash equivalents | | $ | 1,247,372 |
Accounts receivable, related party | | | 5,238,852 |
| | | |
Total current assets | | | 6,486,224 |
| |
Investments in partnerships | | | 993,428 |
Oil and gas properties - full-cost method, net | | | 68,650,240 |
| | | |
| |
Total assets | | $ | 76,129,892 |
| | | |
| |
Liabilities and stockholder’s equity | | | |
| |
Current liabilities | | | |
Accounts payable, related party | | $ | 7,113,065 |
| | | |
Total current liabilities | | | 7,113,065 |
| |
Long term debt | | | 97,222 |
Deferred income taxes | | | 3,520,123 |
Asset retirement obligation | | | 2,666,542 |
| | | |
| |
Total liabilities | | | 13,396,952 |
| |
Commitments and contingencies | | | |
| |
Stockholder’s equity | | | |
Common stock, $1 par value, 1,000 shares authorized, issued and outstanding | | | 1,000 |
Paid-in capital in excess of par value of common stock | | | 1,190,262 |
Retained earnings | | | 61,541,678 |
| | | |
Total stockholder’s equity | | | 62,732,940 |
| | | |
| |
Total liabilities and stockholder’s equity | | $ | 76,129,892 |
| | | |
See accompanying notes to financial statements.
52
MEWBOURNE DEVELOPMENT CORPORATION
NOTES TO UNAUDITED BALANCE SHEET
1. Significant Accounting Policies
Financial Statement Presentation
Mewbourne Development Corporation (the “Company”) is a wholly-owned subsidiary of Mewbourne Holdings, Inc. (the “Stockholder”). The Company is principally involved in the exploration and production of oil and gas in Texas, Oklahoma and New Mexico.
New Accounting Pronouncements
Modernization of Natural Gas and Oil Reporting. In January 2009, the FASB issued revisions to the natural gas and oil reporting disclosures, “Modernization of Oil and Gas Reporting, Final Rule” (the “Final Rule”). In January 2010, the FASB updated its oil and gas estimation and disclosure requirements to align its requirements with the SEC’s modernized oil and gas reporting rules, which are described above. The update amends the definition of proved reserves to use the average of first-day-of-the-month prices during the twelve months preceding the end of the reporting period, adds definitions used in estimating and disclosing proved oil and natural gas quantities and expands the disclosures required for equity-method investments. The update must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods on or after December 31, 2009. The Company adopted the new standards effective December 31, 2009.
FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles. In June 2009, FASB issued guidance on the accounting standards codification and the hierarchy of generally accepted accounting principles. The accounting standards codification was intended to be the source of authoritative US GAAP and reporting standards as issued by the FASB. Its primary purpose is to improve clarity and use of existing standards by grouping authoritative literature under common topics. The accounting standards codification is effective for financial statements issued for interim and annual periods ending after September 13, 2009. The Company now describes the authoritative guidance used with the footnotes but no longer uses numerical references. The accounting standards codification does not change or alter existing US GAAP, and there has been no expected impact on the Company’s financial position, results of operation or cash flows.
Oil and Gas Properties
The Company follows the full-cost method of accounting for its oil and gas activities, all of which are located in the Continental United States. Under the full-cost method, all productive and nonproductive costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized. All such costs are directly identified with acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead, or similar activities. Depreciation, depletion and amortization of oil and gas properties are computed on the units-of-production method, using the proved reserves underlying the oil and gas properties. Unproved oil and natural gas properties are excluded from the calculation of depreciation, depletion and amortization until it is determined whether or not proved reserves can be assigned to such properties. At December 31, 2009, $629,362 was considered unproved property costs. Gains and losses on the sale or other disposition of properties are not recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas.
Included in capitalized costs are costs related to the offering of certain partnerships in which the Company is the managing partner. These partnerships were formed to acquire interest in oil and gas properties and the Company received its interests in these oil and gas properties through its contribution of these costs. Depreciation, depletion and amortization of these costs are computed on the units-of-production method using the proved reserves and depletion rate of each partnership for which the costs were incurred.
Capitalized costs are subject to a ceiling test that limits such costs to the aggregate of the present value of future net revenues of proved reserves discounted at 10%, based on average of first-day-of-the-month prices during the twelve months preceding the end of the reporting period, operating conditions at the balance sheet date, and the lower of cost or fair value of unproved properties. There was no ceiling write-down required at December 31, 2009.
53
MEWBOURNE DEVELOPMENT CORPORATION
NOTES TO UNAUDITED BALANCE SHEET—(Continued)
Management’s Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
In addition, oil and gas reserves and dismantlement costs require significant estimates which could materially differ from amounts ultimately realized.
Cash and Cash Equivalents
The Company considers all highly liquid investments, those with original maturities of three months or less at the date of acquisition, to be cash equivalents.
A substantial portion of the Company’s cash and cash equivalents is maintained in one financial institution which the Company believes to be of high credit quality.
Fair Value of Financial Instruments
The carrying values of cash and cash equivalents, accounts receivable, and accounts payable approximate their fair values because of the short maturity or duration of these instruments. The fair value of the Company’s long-term debt approximates carrying value due to the terms available to the Company for similar financial instruments.
Investments in Partnerships
The Company is the managing partner of several oil and gas partnerships. The Company accounts for its investment in partnerships using the equity method of accounting.
Asset Retirement Obligations
The Company has recognized an estimated liability for future plugging and abandonment costs. The estimated liability is based on historical experience and estimated well life. The liability is discounted using the credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in well plugging and abandonment costs or well useful lives, or if federal or state regulators enact new well restoration requirements. The Company recognizes accretion expense in connection with the discounted liability over the remaining life of the well.
The Company measures the fair values of nonfinancial assets measured at fair value on a non-recurring basis at the estimated price that would be received upon the sale of the asset in an orderly transaction between market participants at the measurement date. These estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3, which means they are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. they are supported by little or no market activity).
Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants (exit price) at the measurement date. Assets and liabilities recorded at fair value in the balance sheets are categorized based upon the level of judgment associated with the inputs used to measure their fair value.
Level inputs are as follows:
Level 1 - Observable inputs are unadjusted, quoted prices for identical assets or liabilities in active markets at the measurement date. Level 1 securities include Government securities, debt securities, certain common stocks, and cash and cash equivalents.
54
MEWBOURNE DEVELOPMENT CORPORATION
NOTES TO UNAUDITED BALANCE SHEET—(Continued)
Level 2 - Observable inputs other than quoted prices included in Level 1 that are observable for the asset or liability through corroboration with market data at the measurement date.
Level 3 - Unobservable inputs that reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date.
Subsequent events
In the preparation of its financial statements, the Company considered subsequent events through April 30, 2010 which was the date the Company’s balance sheet was available to be issued.
2. Oil and Gas Properties
Oil and gas properties consist of the following:
| | | | |
December 31, | | 2009 | |
Proved oil and gas properties | | $ | 125,238,436 | |
Unproved oil and gas properties | | | 629,362 | |
Accumulated depreciation, depletion and amortization | | | (57,217,558 | ) |
| | | | |
| |
Net oil and gas properties | | $ | 68,650,240 | |
| | | | |
3. Long-Term Debt
On December 31, 2009, the Company renewed its bank revolving credit agreement, extending the maturity date of its $4,000,000 revolving line of credit. The Company can borrow under the bank revolving credit agreement from December 31, 2009 to June 30, 2010. Principal outstanding and unpaid on July 1, 2010 will be payable in 30 equal monthly installments until the Note is paid in full on December 31, 2012. The Company has the option to borrow at either the prime rate minus .25% or at the Eurodollar Fixed Period Rate, plus 2.5%.
The bank revolving credit agreement also contains certain covenants including the maintenance of minimum proven oil and gas reserves. The bank revolving credit agreement is uncollateralized; however, the Company is subject to certain negative covenants. As of December 31, 2009, the Company has $97,222 outstanding under this revolving credit agreement and has $3,902,778 available for borrowing.
4. Asset Retirement Obligation
The Company has recognized an estimated liability for future plugging and abandonment costs. The estimated liability is based on historical experience and estimated well life. The liability is discounted using the credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in well plugging and abandonment costs or well useful lives, or if federal or state regulators enact new property restoration requirements. The Company recognizes accretion expense in connection with the discounted liability over the remaining life of the well.
The Company measures the fair values of nonfinancial assets measured at fair value on a non-recurring basis at the estimated price that would be received upon the sale of the asset in an orderly transaction between market participants at the measurement date. These estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3, which means they are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. they are supported by little or no market activity).
55
MEWBOURNE DEVELOPMENT CORPORATION
NOTES TO UNAUDITED BALANCE SHEET—(Continued)
A reconciliation of the Company’s liability for well plugging and abandonment costs for the year ended is as follows:
| | | |
December 31, | | 2009 |
Balance at June 30, 2009 | | $ | 2,268,365 |
Liabilities incurred during period | | | 331,340 |
Accretion expense | | | 66,837 |
| | | |
Balance at December 31, 2009 | | $ | 2,666,542 |
| | | |
5. Income Taxes
Federal and state income tax is calculated at the Stockholder level and allocated to the subsidiaries based on pretax income. The Company calculates its deferred tax liability as if it were a separate tax paying entity. Deferred income taxes are recognized for the tax consequences in future years of differences between the tax basis of assets and liabilities and their financial reporting amounts at the balance sheet date based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances are established when necessary to reduce deferred tax assets to the amount expected to be realized. As of December 31, 2009, federal and state income taxes payable to the Stockholder were $211,387 which is included in accounts payable, related party in the accompanying balance sheet.
The deferred tax liability at December 31, 2009 is primarily attributable to the differences in the book and tax basis of oil and gas properties and depletion and depreciation methods for oil and gas properties between the income tax basis of accounting and generally accepted accounting principles.
6. Commitments and Contingencies
The Company is obligated, subject to certain limitations, to purchase or cause to be purchased by an affiliate or the Stockholder, limited partnership interests, if tendered. The purchase price is based on a defined formula pursuant to the Partnership agreement and is intended to represent fair value. For the majority of the partnerships in which this obligation exists, the obligation generally commences once the partnership has been in existence for three years and extends for a period of five years; on certain others, the obligation remains throughout the life of the partnership. The obligation to purchase interests in a single calendar year is generally limited to no more than 5% of the total number of interests of the partnership outstanding at the beginning of the calendar year. Additionally, the total amount of limited partnership interests which the Company is obligated to purchase upon redemption is limited to $500,000 per year. If the partnership interests are tendered in future years, it is anticipated that the Company or Stockholder will use funds provided by operations or borrow funds to satisfy such repurchase obligations. Historically, the amount of limited partnership interests tendered has been immaterial.
At December 31, 2009, the Company had a funding requirement of approximately $9,186,277 to Mewbourne Energy Partners 09-A L.P., an affiliated partnership.
7. Related Party Transactions
Mewbourne Oil Company (“MOC”), a wholly owned subsidiary of the Stockholder, acts as operator of substantially all oil and gas properties in which the Company invests. Under the terms of the operating agreements, oil and gas sales are collected by MOC and remitted to the Company and lease operating expenses and production taxes are billed by and paid to MOC. Additionally, MOC charges the Company for general and administrative expenses in accordance with the partnership and program agreements. MOC remits revenues to the Company and bills the company for expenses on a monthly basis. At December 31, 2009, accounts receivable, related party consists of revenues receivable from MOC and accounts payable, related party consists of $6,901,678 payable to MOC for expenses and $211,387 payable to the Stockholder for income taxes. The Company considers the amounts receivable from MOC to be fully collectible.
56
MEWBOURNE DEVELOPMENT CORPORATION
NOTES TO UNAUDITED BALANCE SHEET—(Continued)
8. Supplemental Oil and Gas Information (Unaudited)
The tables presented below provide supplemental information about oil and natural gas exploration and production activities.
Capitalized costs related to oil and gas acquisition, exploration and development activities at December 31, 2009 are as follows:
| | | | |
December 31, | | 2009 | |
Proved property costs | | $ | 47,028,976 | |
Unproved property costs | | | 629,362 | |
Producing assets | | | 77,167,460 | |
Other | | | 1,042,000 | |
| | | | |
| |
Total capitalized costs | | | 125,867,798 | |
Accumulated depreciation, depletion and amortization | | | (57,217,558 | ) |
| | | | |
| |
Net capitalized costs | | $ | 68,650,240 | |
| | | | |
Costs incurred in property acquisitions and development activities during the year ended December 31, 2009 are as follows:
| | | |
December 31, | | 2009 |
Proved property acquisition costs | | $ | 3,194,908 |
Development costs | | | 14,131,888 |
| | | |
| |
Total | | $ | 17,326,796 |
| | | |
Estimated Net Quantities of Proved Oil and Gas Reserves
Reserve estimates as well as certain information regarding future production and discounted cash flows were determined by MOC’s petroleum engineers in accordance with guidelines established by the Securities and Exchange Commission and the FASB’s accounting standards. The Company considers reserve estimates to be reasonable; however, due to inherent uncertainties and the limited nature of reservoir data, estimates of oil and gas reserves are imprecise and subject to change over time as additional information becomes available.
These reserve estimates have been prepared based on the average first-of-the-month natural gas and oil prices for the period from January 1, 2009 through December 31, 2009. There have been no favorable or adverse events that have caused a significant change in estimated proved reserves since December 31, 2009. The Company has no long-term supply agreements or contracts with governments or authorities in which it acts as producer nor does it have any interest in oil and gas operations accounted for by the equity method. All reserves are located onshore within the United States. All proved reserves are developed; therefore, the Company has no proved undeveloped properties as of December 31, 2009.
Depletion, depreciation and amortization per equivalent unit of oil production for the year ended December 31, 2009 was $6.83.
57
MEWBOURNE DEVELOPMENT CORPORATION
NOTES TO UNAUDITED BALANCE SHEET—(Continued)
Changes in proved oil and gas reserves for the year ended December 31, 2009 is as follows:
| | | | | |
| | | Gas
(MMcf) | | | Oil
(MBbls) |
Proved reserves at June 30, 2009 | | 34,703 | | | 787 |
Revisions to previous estimates | | 2,551 | | | 4 |
Extensions, discoveries and other additions | | 5,279 | | | 197 |
Production | | (2,863 | ) | | (70) |
| | | | | |
| | |
Proved reserves at December 31, 2009 | | 39,670 | | | 918 |
| | | | | |
Substantially all of the Company’s proved reserves at December 31, 2009 are developed.
Technologies Used in Reserve Estimation
Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil technologies that an entity can use to establish reserves. The FASB now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computation methods) that have been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To achieve reasonable certainty, our technical team employs technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves may include, but are not limited to, empirical evidence through drilling results and well performance, well logs, geologic maps and available downhole and production data, well test data and reservoir stimulation modeling.
As required by the Financial Accounting Standards Board, the standardized measure of discounted future cash flows is computed by applying the average first-of-the-month natural gas and oil prices for the twelve months ended December 31, 2009 and the year-end costs as of December 31, 2009 at a discount factor of ten percent to net proved reserves. The price of oil and gas used in the standardized measure of discounted future cash flows at December 31, 2009 is $57.35 per barrel and $3.94 per mcf, respectively.
The Company believes the standardized measure does not provide a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-of-the-month prices, and therefore may cause significant variability in cash flows from year to year as prices change.
The standardized measure of discounted future net cash flows as of December 31, 2009 is as follows:
| | | | |
December 31, | | 2009 | |
Future cash inflows | | $ | 208,815,047 | |
Future production costs | | | (78,043,906 | ) |
Future development costs | | | (2,783,032 | ) |
Future income tax expense | | | (2,367,905 | ) |
| | | | |
| | | 125,620,204 | |
| |
Discount at 10% | | | (63,572,024 | ) |
| | | | |
| |
Standardized measure of discount future net cash flows from estimated production of proved oil and gas after income taxes | | $ | 62,048,180 | |
| | | | |
58
MEWBOURNE DEVELOPMENT CORPORATION
NOTES TO UNAUDITED BALANCE SHEET—(Continued)
Changes in the standardized measure of discounted future net cash flows for the year ended December 31, 2009 are as follows:
| | | | |
December 31, | | 2009 | |
Standardized measure of discounted future net cash flows at June 30, 2009 | | $ | 50,774,702 | |
Change in value of previous year reserves due to: | | | | |
Value of reserves added due to extensions, discovers and other additions | | | 10,327,457 | |
Accretion of discount | | | 10,485,350 | |
Development costs incurred during the year | | | 23,702 | |
Changes in estimated development costs | | | (15,133 | ) |
Sales of oil and gas produced during the year, net of production costs | | | (11,414,093 | ) |
Revisions of previous reserve estimates | | | (5,595,188 | ) |
Net change in prices | | | (59,790,440 | ) |
Net change in income taxes | | | 33,085,984 | |
Timing and other | | | 34,165,839 | |
| | | | |
| |
Standardized measure of discounted future net cash flows at December 31, 2009 | | $ | 62,048,180 | |
| | | | |
59
| Item 14. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. |
None.
| Item 15. | Financial Statements and Exhibits. |
| (a) | The following are financial statements filed as part of this Registration Statement: |
| | 1. | Balance sheet of the Registrant as of December 31, 2009 |
| | 2. | Statement of operations of the Registrant for the period beginning February 26, 2009 (date of inception) through December 31, 2009 |
| | 3. | Statement of changes in partners’ capital of the Registrant for the period beginning February 26, 2009 (date of inception) through December 31, 2009 |
| | 4. | Statement of cash flows of the Registrant for the period beginning February 26, 2009 (date of inception) through December 31, 2009 |
| | 5. | Notes to financial statements of the Registrant |
| | 6. | Balance sheet of MD as of June 30, 2009 |
| | 7. | Notes to balance sheet of MD as of June 30, 2009 |
| | 8. | Unaudited balance sheet of MD as of December 31, 2009 |
| | 9. | Notes to unaudited balance sheet of MD as of December 31, 2009 |
There are no financial statement schedules. All required information is in the financial statements or the notes thereto.
| (b) | See “Index to Exhibits” below for exhibits filed or incorporated by reference as part of this Registration Statement. |
60
SIGNATURES
Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized.
| | | | | | |
| | | | MEWBOURNE ENERGY PARTNERS 09-A, L.P. |
| Date: April 30, 2010 | | | | | | |
| | | | By: | | /S/ CURTIS W. MEWBOURNE |
| | | | Name: | | Curtis W. Mewbourne |
| | | | Title: | | President and Director |
| | | | | | Mewbourne Development Corporation, |
| | | | | | Managing General Partner of the Registrant |
61
INDEX TO EXHIBITS
The following documents are incorporated by reference in response to Item 15(b).
| | |
EXHIBIT
NUMBER | | DESCRIPTION |
| 3.1 | | Certificate of Limited Partnership of Mewbourne Energy Partners 09-A, L.P., dated February 26, 2009 and filed with the Secretary of State of the State of Delaware on February 26, 2009 |
| |
| 3.2 | | Certificate of Amendment to Certificate of Limited Partnership of Mewbourne Energy Partners 09-A, L.P., dated August 28, 2009 and filed with the Secretary of State of the State of Delaware on August 28, 2009 |
| |
| 3.3 | | Certificate of Correction Filed to Correct a Certain Error in the Certificate of Amendment to Certificate of Limited Partnership of Mewbourne Energy Partners 09-A, L.P., dated December 28, 2009 and filed with the Secretary of State of the State of Delaware on December 28, 2009 |
| |
| 4.1 | | Agreement of Partnership, dated February 26, 2009 |
| |
| 10.1 | | Drilling Program Agreement among Mewbourne Development Corporation, Mewbourne Oil Company and Mewbourne Energy Partners 09-A, L.P., dated August 28, 2009 |
| |
| 10.2 | | Operating Agreement between Mewbourne Energy Partners 09-A, L.P., Mewbourne Development Corporation and Mewbourne Oil Company, dated August 28, 2009 |
| |
| 10.3 | | Gas Marketing Agreement between Mewbourne Oil Company, Mewbourne Energy Partners 09-A, L.P. and Mewbourne Development Corporation, dated August 28, 2009 |
