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 10-A, L.P.

(Exact name of registrant as specified in its charter)

Delaware	27-1903816
(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 the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	x

TABLE OF CONTENTS

Item 1.	Business	2
Item 2.	Financial Information	8
Item 3.	Properties	14
Item 4.	Security Ownership of Certain Beneficial Owners and Management	15
Item 5.	Directors and Executive Officers	15
Item 6.	Executive Compensation	16
Item 7.	Certain Relationships and Related Transactions, and Director Independence	17
Item 8.	Legal Proceedings	18
Item 9.	Market Price of and Dividends on the Registrant’s Common Equity and Related Stockholder Matters	18
Item 10.	Recent Sales of Unregistered Securities	19
Item 11.	Description of the Registrant’s Securities to be Registered	19
Item 12.	Indemnification of Directors and Officers	30
Item 13.	Financial Statements and Supplementary Data	32
Item 14.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	62
Item 15.	Financial Statements and Exhibits	62

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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 10-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.

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Item 1. Business.

General

The Registrant is a limited partnership that was organized under the laws of the State of Delaware on February 9, 2010 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 (the “Securities Act”) and Regulation D promulgated thereunder, with a maximum offering amount of $73,000,000 (14,600 interests). On August 2, 2010, the offering of limited and general partnership interests in the Registrant was closed, with interests aggregating $73,000,000 originally sold to accredited investors of which $67,820,000 were sold to accredited investors as general partner interests and $5,180,000 were sold to accredited investors as limited partner interests.

The Registrant engages primarily in oil and gas drilling and development activities under a drilling program (the “Program”), and it is not involved in any other industry segment. The Program is intended to be a partnership for income tax purposes only. For all other purposes, the Program is intended to be an agreement among the Registrant and MD, as participants, and Mewbourne Oil Company (“MOC” or the “Program Manager”), as the Program manager and operator of wells held by the Program (the “Program wells”). The Program is governed by a drilling program agreement (the “Drilling Program Agreement”) among such parties, and the Registrant and MD, as participants in the Program, will be co-owners of undivided working interests in the Program wells.

MD does not make any capital contributions directly to the Registrant; instead, MD makes its capital contributions directly to the Program. The private placement investors made capital contributions directly to the Registrant. Mewbourne Securities, Inc., a direct, wholly-owned subsidiary of Mewbourne Holdings, Inc., served as the dealer-manager in the private placement pursuant to which the limited and general partner interests in the Registrants were offered to the investors.

Mr. Curtis Mewbourne, his affiliates and/or joint ventures or partnerships operated, directly or indirectly, by Mewbourne Holdings, Inc. may invest in Program wells alongside the Program. Mr. Mewbourne formed Mewbourne Holdings, Inc. and currently serves as Chief Executive Officer of Mewbourne Holdings, Inc., MD and MOC.

As illustrated in the organizational structure chart of the various Mewbourne companies below, Mewbourne Holdings, Inc. is the parent of both MD and MOC. MD is a direct subsidiary of Mewbourne Holdings, Inc., and MOC is owned indirectly by Mewbourne Holdings, Inc. through Mewbourne Financial Corporation.

For a summary of the Registrant’s revenue, income and identifiable assets, see the financial statements in Item 13 of this Registration Statement.

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Notes:

• Dashed connecting lines represent non-equity based relationships.

• The Program is a partnership for tax purposes but otherwise is a contractual agreement among the Registrant, MD and MOC.

Proposed Operations

Under the Drilling Program Agreement referenced above, the activities of the Registrant focus upon the acquisition of oil and gas leases, the drilling of development wells, the development of prospects, 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 Registrant’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, 2010, the Registrant had an undivided working interest in 11 wells producing and 34 wells currently being drilled for a total of 45 wells in which the Registrant owns an undivided working 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 Registrant, through participation in the Program, to engage in drilling for oil and gas on a number of additional prospects, none of which is yet determined. It is impossible at this time to predict with any certainty the additional drilling activities that will be conducted by the Registrant, through the Program.

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Decisions as to the number and location of the prospects in which the Registrant will ultimately invest and as to the amounts spent on drilling are made solely by the Managing Partner for the Registrant and by the Program Manager on behalf of the Program. The Managing Partner intends to cause the Registrant, through participation in the Program, 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 Registrant will vary according to the costs of each well and the size of the fractional working interests selected in each well.

Consistent with industry trends, the Program Manager has increasingly utilized the process of “horizontal drilling” to drill for oil and gas reserves, which is more complex and has more potential for cost overrun than vertical drilling. To date, the Program Manager has drilled approximately 150 wells horizontally. The Program Manager also extensively utilizes the process of hydraulic fracturing to establish flow rates and to increase the initial production rates as well as the ultimate recovery of oil and gas reserves from the wells it drills, both vertically and horizontally. The process of hydraulic fracturing involves pumping a mixture of fluid, chemicals and proppant down the wellbore to fracture the reservoir rock and create artificial fracture planes that more readily allow oil and/or gas to flow back to the wellbore. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and gas regulatory programs. However, bills have recently been introduced in U.S. Congress that would subject hydraulic fracturing to federal regulation under the Safe Drinking Water Act. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations.

Area of Geographic Concentration

The Managing Partner anticipates that all of the Registrant’s funds available for drilling activities will be expended in the Permian Basin and the Anadarko Basin. However, if the Managing Partner determines that it is in the best interest of the Registrant to conduct additional drilling activities in other onshore geographic areas of the United States, the Program and the Registrant 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.

Over the past 46 years, the Program Manager and its affiliates have conducted operations throughout the Permian Basin. The Program Manager currently operates approximately 550 wells in the Permian Basin, and the Program Manager and its affiliates have drilled approximately 1,000 commercially productive oil and gas wells in the Permian Basin. These historical results are not indicative of the results that may be achieved by the Program. 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 Permian Basin located in Southeast New Mexico and West Texas. It is anticipated that the Registrant, through the Program, will conduct a portion of its oil and gas drilling and development activities in this area of the Permian Basin.

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.

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Over the past 36 years, the Program Manager and its affiliates have drilled approximately 1,300 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. The Program Manager currently operates approximately 700 wells in the Anadarko Basin. It is anticipated that the Registrant, through the Program, will 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 the Program Manager over the past 36 years in this region of the Anadarko Basin have been classified as gas wells but produce both oil and gas. However, the Program Manager 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 Registrant 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 of the Registrant to liability in excess of their capital contributions to the Registrant. It is anticipated that drilling activities of the Registrant, through the Program, 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, which are 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 customary insurance coverage to protect, to the extent practicable, the Registrant 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 Registrant 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 Registrant 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 Registrant from recovering damages, expenses and liabilities suffered by the Registrant, 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,

• faulty design, and

• 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 Registrant from recovering the full amount of any damages, expenses and liabilities suffered by the Registrant that arise in the event of an accident. In some cases, the Registrant may not recover any portion of such damages, expenses and liabilities.

The Program Manager and its affiliates maintain insurance policies and limits of liability customary to the oil and gas industry, including commercial general liability, workers’ compensation, automobile liability and excess liability policies. Each of these policies (except for workers’ compensation) names the Registrant, where applicable, as an additional insured. In addition, the Program Manager and its affiliates maintain property insurance covering direct physical loss or damage to property scheduled with insurers and operators extra expense coverage for wells reported to insurers, including control of well, redrill/extra expense and seepage and pollution coverages.

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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, except in the case of non-payment of any premiums, which may result in cancellation with ten days’ prior written notice.

The Managing Partner will notify general and limited partners of the Registrant of any material reduction in the insurance coverage of the Program and Registrant. If possible, this notice shall be given 30 days in advance of the change in insurance coverage. In addition, if the Program or the Registrant has its insurance coverage materially reduced for any reason, the Registrant will, as soon as possible, halt all drilling activity until such time as comparable replacement coverage is obtained.

Market and Competitive Risks

There are a large number of independent operators and individuals as well as a significant number of major oil companies, both public and private, engaged in exploration for oil and gas and development of oil and gas properties, and many of these competitors have financial resources and staffs considerably larger than those available to the Registrant. Accordingly, many of the activities undertaken by the Registrant, through the Program, are highly competitive, including, but not limited to, the acquisition of suitable drilling prospects, the procurement of drilling and related oil field equipment and services, and the marketing of oil and natural gas found and produced, if any. 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.

The ability of the Registrant, through the Program, to market oil and natural gas found and produced, if any, will depend on numerous factors beyond the control of the Registrant, 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 production, the marketing of competitive fuels, the proximity and capacity of pipelines and storage facilities owned by third parties and access thereto, fluctuations in supply and demand, the availability of a ready market, the effect of federal and state regulation of production, refining, transportation and sales, and general national and worldwide economic conditions. Further, future market conditions 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; however, the Program Manager may experience short-term delays in marketing oil due to trucking and crude oil pipeline capacity and refining constraints.

While the Registrant does not have long-term contracts with purchasers of its crude oil or natural gas, the Program Manager may enter into short-term contracts with its customers to sell the Registrant’s natural gas at specified prices or for a percentage of specified index prices. The Registrant’s natural gas may also be sold under contract 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.

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 and wildlife. 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.

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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 the Registrant’s natural gas 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 Registrant 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 the Registrant’s oil, condensate and natural gas liquids 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 Registrant. Environmental laws and regulations are complex, are subject to change and have become more stringent over time. Certain federal laws, including the Endangered Species Act of 1973, as amended, provide special protection to certain designated species. These laws, and any state equivalents, provide for significant civil and criminal penalties for unpermitted activities that result in harm to or harassment of certain protected animals and plants, including damage to their habitats. If such species are located in an area in which the Program Manager conducts operations, or if additional species in those areas, such as the lesser prairie chicken (tympanuchus pallidicinctus) or the dunes sagebrush lizard (sceloporus arenicolus), become subject to protection, the Program Manager’s operations could be materially restricted or delayed, or the Registrant could be required to implement expensive mitigation measures. Compliance with these and other environmental 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 Registrant.

Possible Legislation

Currently, there are many legislative proposals pertaining to regulation of the oil and gas industry, which proposals may directly or indirectly affect activities taken by the Registrant through the Program. 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 Registrant’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 Registrant and the Managing Partner with respect to the management 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 Registrant and the Managing Partner, who are the 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.”

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Operating Agreement

The agreement pursuant to which MOC acts as the operator for Program wells (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 Program 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 Registrant 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 Registrant, the Managing Partner and the Program Manager

The Registrant does not have any employees of its own. All management functions of the Registrant 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, 2010, MOC employed 225 persons on a full-time basis, many of whom dedicate a part of their time to conduct the Registrant’s business. For example, numerous employees of MOC provide accounting, administrative and information technology support to the Registrant. 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 Registrant’s affairs. J. Roe Buckley, Chief Financial Officer of both MD and MOC, will spend some time managing the financial affairs of the Registrant, including working to ensure that the Registrant 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 Registrant but will focus the majority of their time on the overall affairs of MD and MOC, which include overseeing the Registrant’s participation in drilling activities, through the Program, 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 9, 2010. The offering of limited and general partner interests began May 1, 2010 and concluded August 2, 2010, with total investor partner contributions of $73,000,000. The Registrant commenced its business operations on the closing date of August 2, 2010.

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The Registrant was formed to engage primarily in the business of drilling development wells, producing and marketing crude oil and natural gas produced from such properties, distributing any net proceeds from operations to its general and limited partners and, to the extent necessary, acquiring 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 9, 2010 (date of inception) through December 31, 2010 are as follows

Oil sales	$	513,288
Barrels produced		6,148
Average price/barrel	$	83.49
Gas sales	$	236,328
Mcf produced		41,160
Average price/Mcf	$	5.74

Although the Registrant’s inception date was February 9, 2010, no income or expenses were earned or incurred prior to the August 2, 2010 closing date of the offering.

Revenues for the period from February 9, 2010 (date of inception) through December 31, 2010 totaled $749,616 and consisted of oil and gas sales. Oil production volume for such period amounted to approximately 6,148 barrels of oil at a corresponding average realized price of $83.49 per barrel of oil, and gas production volume during such period amounted to approximately 41,160 Mcf of gas at a corresponding average realized price of $5.74 per Mcf of gas. Expenses totaling $327,259 consisted primarily of depreciation, depletion and amortization of $255,036. Lease operating expenses totaled $20,821, and production taxes were $50,057. Administrative and general expenses were $1,030, and asset retirement obligation accretion expense was $315. At December 31, 2010, 11 wells had been drilled and were productive.

Because the Registrant was formed during 2010, no trend analysis based on yearly changes in liquidity, capital resources or results of operations is available.

Liquidity and Capital Resources

The drivers underlying the Registrant’s cash flows consist principally of the ability of the Registrant’s wells to produce oil and gas as well as the prices of crude oil and natural gas. The Registrant expects oil and gas production and, as a result, cash flows, to increase during 2011 as additional wells are completed and oil and gas production is sold. It is anticipated that substantially all of the Registrant’s excess funds will be expended for drilling costs by the end of the fourth quarter of 2011.

At December 31, 2010, cash was $51,109,051. For the period from February 9, 2010 (date of inception) through December 31, 2010, approximately $15,700,000 of the Registrant’s initial partners’ capital of $73,000,000 was used for drilling and completion, and $6,205,000 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 the Managing Partner believes at this point that the Registrant will have sufficient capital to complete its drilling activities and that no borrowings will be necessary. Specifically, it is anticipated that the Registrant will have begun drilling the majority of its wells by September 30, 2011, with substantially all activity completed by the end of the fourth quarter of 2011. However, due to unforeseen circumstances, it could become necessary to finance the costs of the Registrant’s operations through the Registrant’s borrowings, utilization of the Registrant’s 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 Registrant’s partnership agreement (the “Partnership Agreement”) provides that outstanding borrowings may not at any time exceed 20% of its aggregate capital contributions. Furthermore, the Registrant may borrow funds only if the lender agrees that it will have no recourse against the Registrant’s 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 Registrant 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 the Registrant’s operations through borrowings, the Registrant would not need to borrow money from an unaffiliated third party.

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Revenues that, in the sole judgment of the Managing Partner, are not required to meet the Registrant’s obligations will be distributed to the Registrant’s partners at least quarterly in accordance with the Partnership Agreement. The Registrant made no cash distributions to its investor partners for the period beginning February 9, 2010 (date of inception) through December 31, 2010. The Registrant expects that cash distributions will begin and continue during 2011 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 (“GAAP”) 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 established by the Securities and Exchange Commission (the “SEC”), projected development and production costs and a 10 percent annual discount rate. There were no cost ceiling write-downs during the period from February 9, 2010 (date of inception) through December 31, 2010.

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 Registrant 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 Registrant’s control.

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.

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Asset Retirement Obligations

The Registrant 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 Registrant 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 if federal or state regulators enact new well restoration requirements. The Registrant recognizes accretion expense in connection with the discounted liability over the remaining life of the well.

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A reconciliation of the Registrant’s liability for well plugging and abandonment costs for the period beginning February 9, 2010 (date of inception) through December 31, 2010 is as follows:

Balance, beginning of period	$	—
Liabilities incurred		89,657
Accretion expense		315
Balance, end of period	$	89,972

Organization and Related Party Transactions

The Registrant was organized on February 9, 2010 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 Registrant and MD. Mewbourne Holdings, Inc. is the parent of both MD and MOC. Substantially all of the Partnership’s transactions are with MD and MOC. Because of the common control of the Registrant, 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 Registrant, 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 Registrant;

• MD will decide which prospects the Registrant will acquire;

• MOC acts 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 Registrant, as a participant in the Program, will have an undivided working interest in any such contributed property;

• MD manages fifteen other partnerships as the general partner of each and owes duties of good faith and fair dealing to such other partnerships;

• MD and MOC engage in significant drilling, operating and producing activities for other partnerships; and

• affiliates of MD may purchase interests in the Registrant, and subject to limitations, interests purchased by an affiliate have voting rights under the Partnership Agreement.

MD is accountable to the Registrant as a fiduciary and is required to act in good faith in the best interests of the Registrant 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 Registrant, 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, as the Program Manager, MOC will incur certain costs that will be passed on to well owners of the well for which the costs were incurred. The Registrant 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 by the Registrant for operator charges totaled $358,086 for the period from February 9, 2010 (date of inception) through December 31, 2010. Operator charges are billed in accordance with the Program and the Partnership Agreement.

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In consideration for services rendered by MD in managing and conducting the business of the Registrant (e.g., accounting and recordkeeping activities), the Registrant during each of the initial three years of the Registrant 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 Registrant. Management fees can only be paid out of funds available for distributions. No management fees were allocated to the Registrant for the period from February 9, 2010 (date of inception) through December 31, 2010. In the periods in which management fees are paid, the Registrant 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 Registrant by MOC as the Program Manager shall not exceed the greater of (a) 3.5% of the Registrant’s gross revenue 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 capital contributions of the Registrant’s limited and general partners. Administrative expenses can only be paid out of funds available for distributions. Under this arrangement, no administrative expenses were allocated to the Registrant during the period from February 9, 2010 (date of inception) through December 31, 2010.

The costs and revenues of the Program are allocated to the Registrant’s investor partners and MD as follows:

	Investor Partners			MD
Revenues:
Interest earned on capital contributions of investor partners		100	%		0	%
Proceeds from disposition of depreciated property and depleted oil and gas properties		75	%		25	%
All other revenues		75	%		25	%
Costs and expenses:
Organization and offering costs(1)		0	%		100	%
Lease acquisition costs to the extent that these costs do not exceed 16.15% of the subscriptions by investor partners to the Partnership(1)		0	%		100	%
Sales commissions and marketing fee		100	%		0	%
Tangible and intangible drilling costs(1)		100	%		0	%
Reporting and legal expenses		100	%		0	%
Operating costs, management fee, gas marketing services fee, administrative expenses and all other direct costs (including lease acquisition costs that are in excess of 16.15% of the subscriptions by investor partners to the Partnership		75	%		25	%

(1) Pursuant to the Program, MD must contribute 100% of organization and offering costs and lease acquisition costs, which should approximate 15% of total capital costs. To the extent that organization and offering costs and lease acquisition costs are less than 15% of total capital costs, MD is responsible for tangible drilling costs until its share of the Program’s total capital costs reaches approximately 15%.

The Registrant’s financial statements reflect its respective proportionate participation of 75% in the Program. The Program’s other 25% participant is MD.

For additional detail regarding the Partnership and the Program, please refer to the descriptions of the Partnership Agreement and Drilling Program Agreement in “Item 11. Description of the Registrant’s Securities to be Registered.”

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Item 3. Properties.

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 Registrant 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 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, 2010, the Registrant had an undivided working interest in 11 wells producing and 34 wells currently being drilled for a total of 45 wells in which the Registrant owns an undivided working interest.

The following table summarizes the Registrant’s drilling activity for the period beginning February 9, 2010 (date of inception) through December 31, 2010:

	Gross		Net
Development Wells
Oil and natural gas wells		11		1.894
Non-productive wells		0		0

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-seven years of practical experience in petroleum engineering with 25 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, and reserve estimates are made by experienced reservoir engineers;

• senior reservoir engineers review all of the company’s reported proved reserves at the close of each quarter; and

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• 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. MD as the Managing Partner, has the exclusive right and full authority to manage 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 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 Registrant’s affairs. Mr. Buckley, Chairman of the Board and Chief Financial Officer of MD, MOC and Mewbourne Holdings, Inc., will spend some time managing the financial affairs of the Registrant, including working to ensure that the Registrant complies with applicable reporting requirements. Mr. Buckley performs the same functions for the other partnerships managed by MD. The other executive officers may from time to time tend to the affairs of the Registrant but will focus the majority of their time on the overall affairs of MD and MOC, which include overseeing the Registrant’s participation in the Program’s 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 partners or until their successors are elected and qualified, and officers serve at the discretion of MD’s Board of Directors.

Name	Age as of December 31, 2010	Position
Curtis W. Mewbourne	75	Chief Executive Officer
J. Roe Buckley	48	Chairman of the Board, Executive Vice President and Chief Financial Officer
Kenneth S. Waits	50	President
B. Alan Clark	58	Treasurer and Controller
Michael F. Shepard	64	Secretary and General Counsel
Dorothy M. Cuenod	50	Assistant Secretary and Director
Ruth M. Buckley	49	Assistant Secretary and Director
Julie M. Greene	47	Assistant Secretary and Director

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Curtis W. Mewbourne, age 75, formed Mewbourne Holdings, Inc. in 1965 and serves as Chief Executive Officer 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 48, joined Mewbourne Holdings, Inc. in 1990 and serves as Chairman of the Board, Executive Vice President and Chief Financial Officer of Mewbourne Holdings, Inc., 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 degree in Economics from Sewanee in 1984. Mr. Buckley is the son-in-law of Curtis W. Mewbourne, the husband of Ruth M. Buckley, and the brother-in-law of Dorothy M. Cuenod and Julie M. Greene.

Kenneth S. Waits, age 50, President of Mewbourne Holdings, Inc., MD and MOC, has been with MOC since 1984. He joined the company following his graduation from the University of Oklahoma where he received a Bachelor of Science degree in Petroleum Engineering in 1983. He currently manages all of MOC’s exploration efforts. He has also served as Exploration Manager for Western Oklahoma. Previously at MOC, he held positions in Operations and in Reservoir/Evaluations.

B. Alan Clark, age 58, 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 degree from the University of Texas at Arlington in 1975.

Michael F. Shepard, age 64, 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 Bachelor of Arts 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 50, has served as a Director and Assistant Secretary of both MD and MOC since 1984. Ms. Cuenod received a Bachelor of Arts degree in Art History from The University of Texas in 1982 and a Masters of Business Administration degree from Southern Methodist University in 1987. Ms. Cuenod is the daughter of Curtis W. Mewbourne, the sister of Ruth M. Buckley and Julie M. Greene, and the sister-in-law of J. Roe Buckley.

Ruth M. Buckley, age 49, has served as a Director and Assistant Secretary of both MD and MOC since 1987. Ms. Buckley received a Bachelor of Science degree in both Engineering and Geology from Vanderbilt University in 1984. Ms. Buckley is the daughter of Curtis W. Mewbourne, the sister of Dorothy M. Cuenod and Julie M. Greene, and the wife of J. Roe Buckley.

Julie M. Greene, age 47, has served as a Director and Assistant Secretary of both MD and MOC since 1988. Prior to that time she was employed by Rauscher, Pierce, Refsnes, Inc. Ms. Greene received a Bachelor of Arts degree in Business Administration from The University of Oklahoma in 1986. Ms. Greene is the daughter of Curtis W. Mewbourne, the sister of Dorothy M. Cuenod and Ruth M. Buckley, and the sister-in-law of J. Roe Buckley.

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 the executive officers of MD may be reimbursed as Administrative Costs.

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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 MOC during the period from February 9, 2010 (date of inception) through December 31, 2010:

	MD		MOC		Total
Operating charges	$	—	$	358,086	$	358,086
Management fee		—		—		—
Administrative expenses		—		—		—
Total	$	—	$	358,086	$	358,086

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 Registrant, 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 of the Registrant and relating to the Registrant, respectively. The amount of administrative costs that are reimbursed by the Registrant shall be allocated to the Registrant 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 Registrant or the Program, during any particular calendar year the total amount of administrative costs allocable to the Registrant shall not exceed the greater of: (a) 3.5% of the Registrant’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 Registrant. Such limitation on administrative costs shall not, however, be applicable to administrative costs otherwise allocable to the Registrant 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 the 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 Registrant and the Registrant’s interest in the Program, respectively, will be allocated 75% to the Registrant’s 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.

MD, as the managing partner of the Registrant, 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 of the Registrant and relating to the Registrant’s interest in the Program, respectively. Reporting and legal expenses will be allocated 100% to the investor partners in the Registrant.

Management Fee. In consideration for services to be rendered by the Managing Partner in managing the business of the Registrant, during each of the initial three years of the Registrant, the Managing Partner will be paid a management fee in an amount equal to 1% of the subscriptions by the Registrant’s investor partners to the Registrant. The management fee will be allocated 75% to the Registrant’s investor partners and 25% to the 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 Registrant during such partnership year and in such amounts as may be determined in the discretion of the Managing Partner. To the extent that the Registrant has insufficient distributable funds during a particular partnership year for the Program to fully pay the Partnership’s 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.

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Operating Charges. In its capacity as Program Manager, MOC incurs operating charges, which include recovery of gas marketing costs, fixed rate overhead, supervision, pumping and equipment furnished by MOC. The operating charges related to the Registrant’s interest in the Program will be allocated 75% to the Registrant’s investor partners and 25% to the Managing Partner.

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 Registrant a gas marketing fee that is greater than other participants in a well. The gas marketing fee related to the Registrant’s interest in the Program will be allocated 75% to the Registrant’s 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, 2010, the Registrant had 14,600 outstanding limited and general partnership interests held of record by 1,901 subscribers, 1,755 of which subscribed to general partner interests and 146 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 $15,700,000 of the initial partners’ capital of $73,000,000 was used for drilling and completion, and $6,205,000 was utilized for sales commissions and marketing fees during the period from February 9, 2010 (date of inception) through December 31, 2010. 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 Registrant, through the Program, will have begun drilling the majority of its wells by September 30, 2011 with substantially all activity completed by the end of the fourth quarter of 2011.

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 of the Registrant at least quarterly in accordance with the Partnership Agreement. The Registrant made no cash distributions to the investor partners for the period beginning February 9, 2010 (date of inception) through December 31, 2010. The Registrant expects that cash distributions will begin and continue during 2011 due to additional oil and gas revenues that are expected to be sufficient to produce cash flows from operations.

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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, served as the dealer manager for the private placement and, as such, engaged Financial Industry Regulatory Authority (FINRA) registered broker dealers to market interests. No interests were directly offered or marketed by Mewbourne Securities, Inc.

On August 2, 2010, the offering of limited and general partnership interests in the Registrant was closed, with interests aggregating $73,000,000 originally sold to accredited investors of which $67,820,000 were sold to accredited investors as general partner interests and $5,180,000 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 participating broker dealers engaged by Mewbourne Securities, Inc. The remainder of the proceeds has been or will be used for drilling and completion.

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 of the Partnership 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 its 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,

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(f) to terminate any contract between the Partnership and its managing partner or any affiliate of its 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,

(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 its 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 Partnership’s managing partner and substitute a new managing partner to operate and carry on the business of the Partnership or to remove the manager of the Program 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

• 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 of the Partnership will delegate to the Partnership’s 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

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• 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 Partnership’s managing partner on behalf of the Partnership to convey Partnership property or take any other action binding on the Partnership.

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 Partnership’s 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 Partnership’s managing partner has full and exclusive power, except as limited by the Partnership Agreement and applicable law, to manage, 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 Partnership’s managing partner on behalf of the Partnership and transactions between the Partnership, the Program, the Partnership’s managing partner and/or affiliates thereof. Because of the common control of the Partnership, 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 Partnership’s 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 Partnership’s managing partner will owe the Partnership’s 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 Partnership’s 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 Partnership’s 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:

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• the Partnership may indemnify and hold harmless the managing partner and its affiliates,

• 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 the Partnership’s 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 the 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 and their respective officers and directors against claims arising from conduct or omission on behalf of the Partnership 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 its 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 its affiliate was acting on behalf of or performing services for the Partnership, and that such conduct or omission did not constitute negligence or misconduct.

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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 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. 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, investor partners may make such request in each of the years 2014 through 2019. 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 the investor partners is determined to violate any existing or future laws, such obligation will be eliminated or modified appropriately.

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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 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 of the Partnership) 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 of the Partnership 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.

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Dissolution, Liquidation and Termination of the Partnership

The Partnership shall be dissolved upon:

• the occurrence of December 31, 2060,

• 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.

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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 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 of the Partnership, 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 retiring 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.

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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 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 GAAP, 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, 2011, oil and gas reserve estimates prepared by an independent petroleum engineer will also be furnished to the Partnership’s general and limited partners. Annual reports will be provided to the Partnership’s 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 Partnership’s general and limited partners 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 Partnership’s general and limited partners information regarding differences between tax basis of accounting and GAAP. General and limited partners will also receive in such monthly reports a summary of the status of Program wells. 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 10.3 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,

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• 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,

• 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 10.3 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 Registrant, 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 Registrant and MD with respect to the management 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 Registrant, 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), MD will have given at least 120 days’ notice to the partners of the Registrant prior to the termination.

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Allocation of Costs and Revenues

Pursuant to the Drilling Program Agreement, the costs and revenues of the Program are allocated to the Registrant’s investor partners and MD as follows:

	Investor     Partners		MD
Revenues:
Interest earned on capital contributions of investor partners		100%		0%
Proceeds from disposition of depreciated property and depleted oil and gas properties		75%		25%
All other revenues		75%		25%
Costs and expenses:
Organization and offering costs(1)		0%		100%
Lease acquisition costs to the extent that these costs do not exceed 16.15% of the subscriptions by investor partners to the Partnership(1)		0%		100%
Sales commissions and marketing fee		100%		0%
Tangible and intangible drilling costs(1)		100%		0%
Reporting and legal expenses		100%		0%
Operating costs, management fee, gas marketing services fee, administrative expenses and all other direct costs (including lease acquisition costs that are in excess of 16.15% of the subscriptions by investor partners to the Partnership)		75%		25%

(1) Pursuant to the Program, MD must contribute 100% of organization and offering costs and lease acquisition costs, which should approximate 15% of total capital costs. To the extent that organization and offering costs and lease acquisition costs are less than 15% of total capital costs, MD is responsible for tangible drilling costs until its share of the Program’s total capital costs reaches approximately 15%.

The Registrant’s financial statements reflect its respective proportionate participation in the Program.

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 Registrant’s 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 Registrant 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 Registrant 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 Registrant, 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.

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Amendment

The Drilling Program Agreement may only be amended in writing by MD and the Registrant; provided that, to the extent required under the terms of the Partnership Agreement, the Registrant 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 Registrant 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 Registrant do not require the consent of the Registrant.

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 Registrant’s managing partner nor any of its affiliates shall be liable to the Registrant or the Registrant’s general and limited partners for any loss suffered by the Registrant 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 Registrant, that the managing partner or such affiliate was acting on behalf of or performing services for the Registrant, 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 Registrant only from the tangible net assets of the Registrant 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 Registrant 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 Registrant 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 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 Registrant is authorized to purchase insurance against liabilities asserted against, and expenses incurred by, the managing partner and its affiliates in connection with the Registrant’s activities; provided that, the Registrant will not bear the cost of that portion of any insurance, other than insurance customary for the Registrant’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 Certificate 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.

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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.

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Item 13. Financial Statements and Supplementary Data.

INDEX TO FINANCIAL STATEMENTS

Financial Statements of Mewbourne Energy Partners 10-A, L.P.
Report of Independent Registered Public Accounting Firm	33
Balance Sheet as of December 31, 2010	34
Statement of Operations for the Period from February 9, 2010 (Date of Inception) through December  31, 2010	35
Statement of Changes in Partners’ Capital for the Period from February  9, 2010 (Date of Inception) through December 31, 2010	36
Statement of Cash Flows for the Period Beginning February  9, 2010 (Date of Inception) through December 31, 2010	37
Notes to Financial Statements	38
The following balance sheets are those of the Managing Partner, in which the Registrant’s general and limited partners have no ownership interest.
Balance Sheet of Mewbourne Development Corporation
Report of Independent Auditors	44
Balance Sheet as of June 30, 2010	45
Notes to Balance Sheet	46
Unaudited Balance Sheet of Mewbourne Development Corporation
Accountants’ Review Report	53
Unaudited Balance Sheet as of December 31, 2010	54
Notes to Unaudited Balance Sheet	55

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Report of Independent Registered Public Accounting Firm

To the Partners of Mewbourne Energy Partners 10-A, L.P. and to the Board of Directors of Mewbourne

Development Corporation

Tyler, Texas

We have audited the accompanying balance sheet of Mewbourne Energy Partners 10-A, L.P. (Partnership) as of December 31, 2010 and the related statement of operations, change in partners’ capital and cash flows for the period from February 9, 2010 (date of inception) through December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits include 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 audits 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 the Partnership at December 31, 2010, and the results of its operations and its cash flows for the period from February 9, 2010 (date of inception) through December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.

/s/ BDO USA, LLP

Dallas, Texas

April 28, 2011

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MEWBOURNE ENERGY PARTNERS 10-A, L.P.

BALANCE SHEET

December 31, 2010

ASSETS
Cash	$	51,109,051
Account receivables, affiliate		714,972
Total current assets		51,824,023
Oil and gas properties at cost, full-cost method		15,785,955
Less accumulated depreciation, depletion and amortization		(255,036	)
		15,530,919
Total assets	$	67,354,942
LIABILITIES AND PARTNERS’ CAPITAL
Accounts payable, affiliate	$	47,613
Total current liabilities		47,613
Asset retirement obligation		89,972
Partners’ capital
General partners		62,447,687
Limited partners		4,769,670
Total partners’ capital		67,217,357
Total liabilities and partners’ capital	$	67,354,942

The accompanying notes are an integral part of the financial statements.

34

MEWBOURNE ENERGY PARTNERS 10-A, L.P.

STATEMENT OF OPERATIONS

For the period from February 9, 2010 (date of inception) through December 31, 2010

Revenues:
Oil sales	$	513,288
Gas sales		236,328
Total revenues		749,616
Expenses:
Lease operating expense		20,821
Production taxes		50,057
Administrative and general expense		1,030
Depreciation, depletion and amortization		255,036
Asset retirement obligation accretion		315
Total expenses		327,259
Net income	$	422,357
Allocation of net income:
General partners	$	392,387
Limited partners	$	29,970
Basic and diluted net income per partner interest (14,600 interests outstanding)	$	28.93

The accompanying notes are an integral part of the financial statements.

35

MEWBOURNE ENERGY PARTNERS 10-A, L.P.

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

For the period from February 9, 2010 (date of inception) through December 31, 2010

	General Partners		Limited Partners		Total
Balance at February 9, 2010 (date of inception)	$	—	$	—	$	—
Capital contributions, net of sales commissions and marketing costs and net of $5,764,700 and $440,300 from general and limited partners, respectively		62,055,300		4,739,700		66,795,000
Net income		392,387		29,970		422,357
Balance at December 31, 2010	$	62,447,687	$	4,769,670	$	67,217,357

The accompanying notes are an integral part of the financial statements.

36

MEWBOURNE ENERGY PARTNERS 10-A, L.P.

STATEMENT OF CASH FLOWS

For the period from February 9, 2010 (date of inception) through December 31, 2010

Cash flows from operating activities
Net income	$	422,357
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		255,036
Asset retirement obligation accretion		315
Changes in operating assets and liabilities:
Account receivable, affiliate		(714,972	)
Account payable, affiliate		47,613
Net cash provided by operating activities		10,349
Cash flows from investing activities
Purchase and development of oil and gas properties		(15,696,298	)
Net cash used in investing activities		(15,696,298	)
Cash flows from financing activities
Capital contributions from partners, net of sales commissions and marketing costs of $6,205,000		66,795,000
Net cash provided by financing activities		66,795,000
Net increase in cash		51,109,051
Cash, beginning of period		—
Cash, end of period	$	51,109,051
Supplemental Cash Flow Information:
Non-cash changes to oil and gas properties related to asset retirement obligation liabilities	$	89,657

The accompanying notes are an integral part of the financial statements.

37

MEWBOURNE ENERGY PARTNERS 10-A

NOTES TO FINANCIAL STATEMENTS

1. Description of Business

Mewbourne Energy Partners 10-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 9, 2010. The offering of limited and general partner interests began May 1, 2010 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 2, 2010, with total investor contributions of $73,000,000 originally being sold to accredited investors of which $67,820,000 were sold to accredited investors as general partner interests and $5,180,000 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. 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, 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.

38

MEWBOURNE ENERGY PARTNERS 10-A

NOTES TO FINANCIAL STATEMENTS—(Continued)

2. Summary of Significant 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 will most likely vary from those estimated, and 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.

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. 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 and, therefore, is inherently imprecise.

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, 2010 approximately $7.8 million of capitalized costs were excluded from amortization. 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 for the period beginning February 9, 2010 (date of inception) through December 31, 2010.

In accordance with current Securities and Exchange Commission requirements, the estimated discounted future net cash flows from proved reserves are based the average of first-day-of-the-month prices during the twelve months preceding the end of the reporting period and costs as of the end of the applicable 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.

Mewbourne Oil Company, the program manager (“MOC”), 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.

Cash

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.

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.

39

MEWBOURNE ENERGY PARTNERS 10-A

NOTES TO FINANCIAL STATEMENTS—(Continued)

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.

A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the period from February 9, 2010 (date of inception) through December 31, 2010 is as follows:

Balance, beginning of period	$	—
Liabilities incurred		89,657
Accretion expense		315
Balance, end of period	$	89,972

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, 2010, 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 2010. 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 basis of its net assets exceeded the tax basis of its net assets by $13,592,634 at December 31, 2010.

3. Organization and Related Party Transactions

The Partnership was organized on February 9, 2010 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.

40

MEWBOURNE ENERGY PARTNERS 10-A

NOTES TO FINANCIAL STATEMENTS—(Continued)

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 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 $358,086 for the period beginning February 9, 2010 (date of inception) through December 31, 2010. 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 0.75% of the subscriptions by the investor partners to the Partnership. Management fees can only be paid out of funds available for distributions. Under this arrangement, no management fees were allocated to the Partnership for the period beginning February 9, 2010 (date of inception) through December 31, 2010. The Partnership includes the management fee as part of the full cost pool pursuant to Rule 4-10(c)(2) of Regulation S-X.

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, no expenses were allocated to the Partnership during the period from February 9, 2010 (date of inception) through December 31, 2010.

The Partnership participates in oil and gas activities through a Drilling Program Agreement (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 depreciated property and depleted oil and gas 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	%
Reporting and legal expenses		100	%		0	%
Operating costs, general and administrative expenses (except for reporting and legal 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 15% of total capital costs. To the extent that organization and offering costs and lease acquisition costs are less than 15% of total capital costs, MD is responsible for tangible drilling costs until its share of the Program’s total capital costs reaches approximately 15%. The Partnership’s financial statements reflect its respective proportionate interest in the Program.

4. Supplemental Oil and Gas Information (unaudited)

The tables presented below provide supplemental information about oil and natural gas exploration and production activities.

41

MEWBOURNE ENERGY PARTNERS 10-A

NOTES TO FINANCIAL STATEMENTS—(Continued)

Costs Incurred and Capitalized Costs

Costs incurred in oil and natural gas acquisition, exploration and development activities for the period from February 9, 2010 (date of inception) through December 31, 2010 were:

Development $ 15,696,298

Capitalized costs related to oil and natural gas acquisition, exploration and development activities for the period from February 9, 2010 (date of inception) through December 31, 2010 were as follows:

Costs of oil and natural gas properties at year-end:
Producing assets – Proved properties	$	7,937,336
Incomplete construction – Unproved properties		7,758,962
Asset retirement obligation		89,657
Total capitalized cost		15,785,955
Accumulated deprecation, depletion, amortization and impairment		(255,036	)
Net capitalized costs	$	15,530,919

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 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. These are prepared in accordance with guidelines established by the Securities and Exchange Commission and FASB 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 using projected costs and the average first-of-the-month natural gas and oil prices for the period from February 9, 2010 (date of inception) through December 31, 2010.

There have been no favorable or adverse events that have caused a significant change in estimated proved reserves since December 31, 2010. 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 had no proved undeveloped properties at December 31, 2010.

	Crude Oil and Condensate (MBbl)			Natural Gas (MMcf)
Proved Reserves:
Balance at February 9, 2010 (date of inception)		—			—
Extensions, discoveries and other additions		126			1,673
Production		(6	)		(41	)
Balance at December 31, 2010(1)		120			1,632

(1) All of these reserves are categorized as proved developed.

42

MEWBOURNE ENERGY PARTNERS 10-A

NOTES TO FINANCIAL STATEMENTS—(Continued)

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, technologies that have been demonstrated to yield results with consistency and repeatability are used. The technologies and economic data used in the estimation of 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, seismic data, well test data and reservoir simulation modeling.

43

Independent Auditors’ Report

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, 2010. 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, 2010, 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 USA, LLP

November 29, 2010

Dallas, Texas

44

MEWBOURNE DEVELOPMENT CORPORATION

BALANCE SHEET

June 30, 2010

Assets
Current assets
Cash and cash equivalents	$	1,617,015
Accounts receivable, related party		5,345,790
Total current assets		6,962,805
Investments in partnerships		933,544
Oil and gas properties - full-cost method, net		73,808,222
Total assets	$	81,704,571
Liabilities and stockholder’s equity
Current liabilities
Accounts payable, related party	$	4,611,285
Total current liabilities		4,611,285
Deferred income taxes		4,391,913
Asset retirement obligation		2,896,238
Total liabilities		11,899,436
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		68,613,873
Total stockholder’s equity		69,805,135
Total liabilities and stockholder’s equity	$	81,704,571

See accompanying independent accountants’ report and notes to consolidated financial statements.

45

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.

New Accounting Pronouncements

In January 2009, the Securities and Exchange Commission (“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 (“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 Corporation adopted the new standards effective January 1, 2010.

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 accounting principles generally accepted in the United States of America (“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. Effective July 1, 2009, the Corporation 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 Corporation’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. 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 interests 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 the average of first-day-of-the-month oil and gas prices during the twelve months preceding the end of the reporting period, and the lower of cost or fair value of unproved properties. There was a no ceiling write-down at June 30, 2010.

46

MEWBOURNE DEVELOPMENT CORPORATION

NOTES TO 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

Effective July 1, 2008, the Company adopted the FASB standard regarding fair value measurements, which 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 this standard did not have a material impact on the Company’s fair value measurements.

Assets and liabilities recorded at fair value in the balance sheet 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 carrying values of cash and cash equivalents, accounts receivable, and accounts payable approximates their fair values because of the short maturity or duration of these 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. 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.

47

MEWBOURNE DEVELOPMENT CORPORATION

NOTES TO BALANCE SHEET—(Continued)

The Company 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 Company recognizes accretion expense in connection with the discounted liability over the remaining life of the well.

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.

Subsequent Events

In preparation of its financial statements, the Company considered subsequent events through November 29, 2010, 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,	2010
Proved oil and gas properties	$	134,933,015
Unproved oil and gas properties		20,330
Accumulated depreciation, depletion and amortization		(61,145,123	)
Net oil and gas properties	$	73,808,222

3. Long-Term Debt

On June 1, 2010, the Company, along with Mewbourne Oil Company, Mewbourne Financial Corporation and Mewbourne Holdings, Inc., as co-borrowers entered into a revolving credit facility including a Loan Agreement and Promissory Note with a maximum principal amount of $20,000,000 (the “Line of Credit”) maturing June 1, 2014. Interest is to be calculated on a per annum basis at a rate equal to the prime rate less .25%. The Loan Agreement contains certain covenants which apply to the Company and the other co-borrowers pertaining to the maintenance of minimum cash and cash equivalents and minimum value of proven oil and gas reserves. The Loan Agreement is uncollateralized; however, the Company has given a negative pledge to the bank. At June 30, 2010, the Company’s affiliated co-borrower Mewbourne Oil Company had outstanding borrowings of $13,100,000 and $6,900,000 was available for borrowing under the Line of Credit.

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.

48

MEWBOURNE DEVELOPMENT CORPORATION

NOTES TO BALANCE SHEET—(Continued)

A reconciliation of the Company’s liability for well plugging and abandonment costs is as follows:

June 30,	2010
Balance at June 30, 2009	$	2,268,365
Liabilities incurred during period		490,265
Accretion expense		140,427
Liabilities settled during period		(2,819	)
Balance at June 30, 2010	$	2,896,238

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 June 30, 2010, federal and state income taxes due to the Stockholder were $105,412 which is included in accounts payable, related party in the accompanying balance sheet.

The deferred tax liability at June 30, 2010 is primarily attributable to the differences in the book and tax bases of 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 June 30, 2010, the Company had a funding requirement of approximately $5,519,759 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. For the year ended June 30, 2010, $839,153 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, 2010, accounts receivable, related party consists of revenues receivable from MOC and accounts payable, related party consists of $4,505,873 payable to MOC for expenses and $105,412 due to the Stockholder for income taxes. The Company considers the amounts receivable from MOC to be fully collectible.

49

MEWBOURNE DEVELOPMENT CORPORATION

NOTES TO BALANCE SHEET—(Continued)

8. Supplement 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, 2010 are as follows:

June 30,	2010
Proved property costs	$	53,423,109
Unproved property costs		20,330
Producing assets		80,140,262
Other		1,369,644
Total capitalized costs		134,953,345
Accumulated depreciation, depletion and amortization		(61,145,123	)
Net capitalized costs	$	73,808,222

Costs incurred in property acquisitions and development activities during the year ended June 30, 2010 are as follows:

June 30,	2010
Proved property acquisition costs	$	9,430,107
Development costs		16,485,319
Total	$	25,915,426

Depletion, depreciation and amortization per equivalent unit of oil production for the year ended June 30, 2010 was $8.54.

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 year ended June 30, 2010. There have been no favorable or adverse events that have caused a significant change in estimated proved reserves since June 30, 2010. The Company has no long-term supply agreements or contracts with governments or authorities in which it acts as producer. All reserves are located onshore within the United States. All proved reserves are developed; therefore, the Company has no proved undeveloped properties as of June 30, 2010.

50

MEWBOURNE DEVELOPMENT CORPORATION

NOTES TO BALANCE SHEET—(Continued)

Changes in proved oil and gas reserves for the year ended June 30, 2010 are as follows:

	Gas (MMcf)			Oil (MBbls)
Proved reserves at June 30, 2009		34,703			787
Revisions to previous estimates		2,991			67
Extensions, discoveries and other additions		9,367			513
Production		(4,380	)		(163	)
Proved reserves at June 30, 2010		42,681			1,204

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 ending June 30, 2010 and the year-end costs as of June 30, 2010 and 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 June 30, 2010 is $69.67 per barrel and $4.52 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 first-of-the-month prices, and therefore may cause significant variability in cash flows from year to year as prices change.

51

MEWBOURNE DEVELOPMENT CORPORATION

NOTES TO BALANCE SHEET—(Continued)

The standardized measure of discounted future net cash flows as of June 30, 2010 is as follows:

June 30,	2010
Future cash inflows	$	276,906,562
Future production costs		(97,516,211	)
Future development costs		(2,489,767	)
Future income tax expense		(13,742,566	)
		163,158,018
Discount at ten percent		(86,295,916	)
Standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes	$	76,862,102

Changes in the standardized measure of discounted future net cash flows for the year ended June 30, 2010 are as follows:

June 30,	2010
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, discoveries and other additions		25,306,911
Accretion of discount		10,485,350
Development costs incurred during the year		2,488,936
Changes in estimated development costs		123,721
Sales of oil and gas produced during the year, net of production costs		(26,967,717	)
Revisions of previous reserve estimates		5,359,995
Net change in prices		(45,811,539	)
Net change in income taxes		27,781,589
Timing and other		27,320,154
Standardized measure of discounted future net cash flows at June 30, 2010	$	76,862,102

52

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, 2010, in accordance with Statements on Standards for Accounting and Review Services issued by the American Institute of Certified Public Accountants. All information included in this financial statement 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 statement 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 USA, LLP

April 28, 2011

53

MEWBOURNE DEVELOPMENT CORPORATION

BALANCE SHEET

December 31, 2010

(Unaudited)

Assets
Current assets
Cash and cash equivalents	$	2,142,803
Accounts receivable, related party		6,378,072
Total current assets		8,520,875
Investments in partnerships		1,040,411
Oil and gas properties - full-cost method, net		79,059,987
Total assets	$	88,621,273
Liabilities and stockholder’s equity
Current liabilities
Accounts payable, related party	$	3,050,593
Total current liabilities		3,050,593
Asset retirement obligation		3,114,545
Deferred income taxes		5,044,222
Total liabilities		11,209,360
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		76,220,651
Total stockholder’s equity		77,411,913
Total liabilities and stockholder’s equity	$	88,621,273

See accompanying notes to financial statements.

54

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.

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. 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 interests 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 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 no ceiling write-down required at December 31, 2010.

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 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 and cash equivalents, accounts receivable, and accounts payable approximate their fair value because of their short-term nature.

55

MEWBOURNE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED BALANCE SHEET—(Continued)

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. The Company does not consolidate the financial statements of the entities in which they have an investment as they do not meet the criteria for consolidation as prescribed by FASB ASC 810-10-25 regarding variable interest entities.

Asset Retirement Obligations

The Company 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 Company 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 Company recognizes accretion expense in connection with the discounted liability over the remaining life of the well.

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.

Subsequent Events

In preparation of its financial statements, the Company considered subsequent events through April 28, 2011, which was the date the Company’s balance sheet was available to be issued.

New Accounting Principles

In June 2009, FASB amended ASC 810-10-65 (Consolidation). Amended ASC 810-10-65 relates to the consolidation of variable interest entities. It eliminates the quantitative approach previously required for determining the primary beneficiary of a variable interest entity and requires ongoing qualitative reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. This guidance also requires additional disclosures about an enterprise’s involvement in variable interest entities. The Company adopted the amended standard July 1, 2010, resulting in no effect on its financial position, operations or cash flows.

56

MEWBOURNE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED BALANCE SHEET—(Continued)

2. Oil and Gas Properties

Oil and gas properties consist of the following:

December 31,	2010
Proved oil and gas properties	$	143,863,799
Unproved oil and gas properties		375,529
Accumulated depreciation, depletion and amortization		(65,179,341	)
Net oil and gas properties	$	79,059,987

3. Long-Term Debt

On June 1, 2010, the Company, along with Mewbourne Oil Company, Mewbourne Financial Corporation and Mewbourne Holdings, Inc., as co-borrowers entered into a revolving credit facility including a Loan Agreement and Promissory Note with a maximum principal amount of $20,000,000 (the “Line of Credit”) maturing June 1, 2014. On September 1, 2011, the line of credit will convert to a declining line of credit and the maximum available credit will reduce by $1,666,667 each calendar quarter until maturity on June 1, 2014. Interest is to be calculated on a per annum basis at a rate equal to the prime rate less .25%. The Loan Agreement contains certain covenants which apply to the Company and the other co-borrowers pertaining to the maintenance of minimum cash and cash equivalents and minimum value of proved oil and gas reserves. The Loan Agreement is uncollateralized; however, the Company has given a negative pledge to the bank. At December 31, 2010, the Company’s affiliated co-borrower Mewbourne Oil Company had outstanding borrowings of $12,000,000 and $8,000,000 was available for borrowing under the Line of Credit.

4. Asset Retirement Obligation

The Company 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 Company 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.

A reconciliation of the Company’s liability for well plugging and abandonment costs for the year ended is as follows:

December 31,	2010
Balance at June 30, 2010	$	2,896,238
Liabilities incurred during period		142,288
Accretion expense		76,019
Balance at December 31, 2010	$	3,114,545

57

MEWBOURNE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED BALANCE SHEET—(Continued)

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, 2010, federal and state income taxes payable to the Stockholder were $222,429 which is included in accounts payable, related party in the accompanying balance sheet.

The deferred tax liability at December 31, 2010 is primarily attributable to the differences in the book and tax basis of 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, 2010, the Company had a funding requirement of approximately $10,114,702 to Mewbourne Energy Partners 10-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, 2010, accounts receivable, related party consists of revenues receivable from MOC and accounts payable, related party consists of $2,828,164 payable to MOC for expenses and $222,429 payable to the Stockholder for income taxes. The Company considers the amounts receivable from MOC to be fully collectible.

58

MEWBOURNE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED BALANCE SHEET—(Continued)

8. Supplemental Oil and Gas Information

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, 2010 are as follows:

December 31,	2010
Proved property costs	$	55,921,599
Unproved property costs		375,529
Producing assets		86,410,675
Other		1,531,525
Total capitalized costs		144,239,328
Accumulated depreciation, depletion and amortization		(65,179,341	)
Net capitalized costs	$	79,059,987

Costs incurred in property acquisitions and development activities during the year ended December 31, 2010 are as follows:

December 31,	2010
Proved property acquisition costs	$	2,356,204
Development costs		6,574,899
Total	$	8,931,103

Depletion, depreciation and amortization per equivalent unit of oil production for the year ended December 31, 2010 was $8.55.

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, 2010 through December 31, 2010. There have been no favorable or adverse events that have caused a significant change in estimated proved reserves since December 31, 2010. 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, 2010.

59

MEWBOURNE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED BALANCE SHEET—(Continued)

Changes in proved oil and gas reserves for the year ended December 31, 2010 is as follows:

	Gas (MMcf)			Oil (MBbls)
Proved reserves at June 30, 2010		42,681			1,204
Revisions to previous estimates		(27	)		18
Extensions, discoveries and other additions		3,635			368
Production		(2,157	)		(112	)
Proved reserves at December 31, 2010		44,132			1,478

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 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 December 31, 2010 and the year-end costs as of December 31, 2010 and 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, 2010 is $75.58 per barrel and $4.89 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, 2010 is as follows:

December 31,	2010
Future cash inflows	$	327,350,406
Future production costs		(111,370,922	)
Future development costs		(2,447,597	)
Future income tax expense		(22,139,579	)
		191,392,308
Discount at 10%		(100,274,905	)
Standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes	$	91,117,403

60

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, 2010 are as follows:

December 31,	2010
Standardized measure of discounted future net cash flows at June 30, 2010	$	76,862,102
Change in value of previous year reserves due to:
Value of reserves added due to extensions, discoveries and other additions		15,850,152
Accretion of discount		17,690,058
Development costs incurred during the year		1,274,388
Changes in estimated development costs		20,076
Sales of oil and gas produced during the year, net of production costs		(15,635,529	)
Revisions of previous reserve estimates		149,364
Net change in prices		12,627,886
Net change in income taxes		17,241,453
Timing and other		(34,962,547	)
Standardized measure of discounted future net cash flows at December 31, 2010	$	91,117,403

61

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, 2010

2. Statement of operations of the Registrant for the period beginning February 9, 2010 (date of inception) through December 31, 2010

3. Statement of changes in partners’ capital of the Registrant for the period beginning February 9, 2010 (date of inception) through December 31, 2010

4. Statement of cash flows of the Registrant for the period beginning February 9, 2010 (date of inception) through December 31, 2010

5. Notes to financial statements of the Registrant

6. Balance sheet of MD as of June 30, 2010

7. Notes to balance sheet of MD as of June 30, 2010

8. Unaudited balance sheet of MD as of December 31, 2010

9. Notes to unaudited balance sheet of MD as of December 31, 2010

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.

62

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 10-A, L.P.
Date: April 28, 2011
	By:	/s/ Curtis W. Mewbourne
	Name:	Curtis W. Mewbourne
	Title:	Chief Executive Officer
		Mewbourne Development Corporation,
		Managing General Partner of the Registrant

63

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 10-A, L.P., dated February 9, 2010 and filed with the Secretary of State of the State of Delaware on February 12, 2010
3.2	Certificate of Amendment to Certificate of Limited Partnership of Mewbourne Energy Partners 10-A, L.P., dated July 20, 2010 and filed with the Secretary of State of the State of Delaware on July 23, 2010
3.3	Certificate of Amendment to Certificate of Limited Partnership of Mewbourne Energy Partners 10-A, L.P., dated August 2, 2010 and filed with the Secretary of State of the State of Delaware on August 6, 2010
3.4	Certificate of Correction Filed to Correct a Certain Error in the Certificate of Amendment to Certificate of Limited Partnership of Mewbourne Energy Partners 10-A, L.P., dated December 16, 2010 and filed with the Secretary of State of the State of Delaware on December 16, 2010
4.1	Agreement of Partnership, dated February 9, 2010
10.1	Drilling Program Agreement among Mewbourne Development Corporation, Mewbourne Oil Company and Mewbourne Energy Partners 10-A, L.P., dated August 2, 2010
10.2	Operating Agreement between Mewbourne Energy Partners 10-A, L.P., Mewbourne Development Corporation and Mewbourne Oil Company, dated August 2, 2010
10.3	Gas Marketing Agreement between Mewbourne Oil Company, Mewbourne Energy Partners 10-A, L.P. and Mewbourne Development Corporation, dated August 2, 2010