UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2013

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from___________________ to ___________________ 

Commission File No. 000-54370

MEWBOURNE ENERGY PARTNERS 10-A, L.P.

Delaware	27-1903816
(State or jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)
3901 South Broadway, Tyler, Texas	75701
(Address of principal executive offices)	(Zip code)

Registrant’s Telephone Number, including area code:  (903) 561-2900 

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 of 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):

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

Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

MEWBOURNE ENERGY PARTNERS 10-A, L.P.
INDEX
Part 1  -  Financial Information				Page No.
	Item 1.  Financial Statements
		Condensed Balance Sheets -
			June 30, 2013  (Unaudited) and December 31, 2012	3
		Condensed Statements of Operations (Unaudited) -
			For the three months ended June 30, 2013 and 2012
			and the six months months ended June 30, 2013 and 2012	4
		Condensed Statement of Changes In Partners' Capital (Unaudited) -
			For the six months ended June 30, 2013	5
		Condensed Statements of Cash Flows (Unaudited) -
			For the six months ended June 30, 2013 and 2012	6
		Notes to Condensed Financial Statements		7
	Item 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations			9
	Item 3.  Quantitative and Qualitative Disclosures about Market Risk			12
	Item 4.  Disclosure Controls and Procedures			12
Part II  -  Other Information
	Item 1.  Legal Proceedings			13
	Item 6.  Exhibits and Reports on Form 8-K			13

2

MEWBOURNE ENERGY PARTNERS 10-A, L.P.

Part I - Financial Information

Item 1.  Financial Statements

CONDENSED BALANCE SHEETS

	June 30, 2013				December 31, 2012
	(Unaudited)
ASSETS
Cash and cash equivalents	$	459		$	594
Accounts receivable, affiliate		2,067,335			2,187,316
Prepaid state taxes		12,500			7,500
Total current assets		2,080,294			2,195,410
		68,950,527			68,632,760
Less accumulated depreciation, depletion,
amortization and impairment		(33,378,164	)		(28,768,268	)
		35,572,363			39,864,492
Total assets	$	37,652,657		$	42,059,902
LIABILITIES AND PARTNERS' CAPITAL
Accounts payable, affiliate	$	210,169		$	329,395
Total current liabilities		210,169			329,395
Asset retirement obligation		737,490			730,604
Partners' capital		36,704,998			40,999,903
Total liabilities and partners' capital	$	37,652,657		$	42,059,902

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

3

 

MEWBOURNE ENERGY PARTNERS 10-A, L.P.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	For the				For the
	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Revenues and other income:
Oil sales	$	2,280,703	$	3,387,960	$	4,025,512	$	8,411,486
Gas sales		1,043,174		1,280,957		2,268,251		3,362,082
Interest income		1,131		142		1,131		358
Total revenues and other income		3,325,008		4,669,059		6,294,894		11,773,926
Expenses:
Lease operating expense		296,569		332,830		649,942		793,014
Production taxes		73,693		131,384		96,606		518,307
Administrative and general expense		128,441		269,961		266,338		647,847
Depreciation, depletion, and amortization		975,281		1,783,323		1,889,256		3,985,230
Cost ceiling write-down		1,757,285		1,754,823		2,720,640		1,754,823
Asset retirement obligation accretion		7,586		7,225		15,242		14,586
Total expenses		3,238,855		4,279,546		5,638,024		7,713,807
Net income	$	86,153	$	389,513	$	656,870	$	4,060,119
Basic and diluted net income per
partner interest
(14,600 interests outstanding)	$	5.90	$	26.68	$	44.99	$	278.09

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

4

MEWBOURNE ENERGY PARTNERS 10-A, L.P.

CONDENSED STATEMENT OF CHANGES IN PARTNERS' CAPITAL

For the six months ended June 30, 2013

(Unaudited)

	Total
Balance at December 31, 2012	$	40,999,903
Cash distributions		(4,951,775	)
Net income		656,870
Balance at June 30, 2013	$	36,704,998

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

5

MEWBOURNE ENERGY PARTNERS 10-A, L.P.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
	2013			2012
Cash flows from operating activities:
Net income	$	656,870		$	4,060,119
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion, and amortization		1,889,256			3,985,230
Cost ceiling write-down		2,720,640			1,754,823
Asset retirement obligation accretion		15,242			14,586
Changes in operating assets and liabilities:
Accounts receivable, affiliate		119,981			3,649,193
Prepaid state taxes		(5,000	)		(2,500	)
Accounts payable, affiliate		(119,226	)		29,750
Net cash provided by operating activities		5,277,763			13,491,201
Cash flows from investing activities:
Purchase and development of oil and gas properties		(326,123	)		(931,585	)
Net cash used in investing activities		(326,123	)		(931,585	)
Cash flows from financing activities:
Cash distributions to partners		(4,951,775	)		(13,750,001	)
Net cash used in financing activities		(4,951,775	)		(13,750,001	)
Net decrease in cash  and cash equivalents		(135	)		(1,190,385	)
Cash and cash equivalents, beginning of period		594			3,088,905
Cash and cash equivalents, end of period	$	459		$	1,898,520
Supplemental Cash Flow Information:
Non-cash changes to net oil & gas properties related to
asset retirement obligation liabilities	$	(8,356	)	$	(2,320	)

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

6

MEWBOURNE ENERGY PARTNERS 10-A, L.P.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

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. During the first quarter of 2012, all general partner equity interests were converted to limited partner equity interests. In accordance with the laws of the State of Delaware, Mewbourne Development Corporation (“MD”), a Delaware Corporation, has been appointed as the Partnership’s managing general partner. MD has no significant equity interest in the Partnership.

2.           Summary of Significant Accounting Policies

Reference is hereby made to the Registrant’s Annual Report on Form 10-K for 2012, which contains a summary of significant accounting policies followed by the Partnership in the preparation of its financial statements.  These policies are also followed in preparing the quarterly report included herein.

In the opinion of management, the accompanying unaudited financial statements contain all adjustments of a normal recurring nature necessary to present fairly our financial position, results of operations, cash flows and partners’ capital for the periods presented.  The results of operations for the interim periods are not necessarily indicative of the final results expected for the full year.

3.           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 June 30, 2013 and 2012 all capitalized costs were subject to amortization. Proceeds from the sale or other disposition of properties are credited to the full cost pool. 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 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 cost ceiling write-downs of $2,720,640 and $1,754,323 at June 30, 2013 and 2012, respectively. These were due to lower average oil and gas prices for the preceding twelve months.

7

4.           Asset Retirement Obligations

The Partnership has recognized an estimated asset retirement obligation liability (ARO) 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 six months ended June 30, 2013 and the year ended December 31, 2012 is as follows:

	June 30,			December 31,
	2013			2012
Balance, beginning of period	$	730,604		$	694,291
Liabilities incurred		35			16,169
Liabilities reduced due to revisions		(8,391	)		(9,130	)
Accretion expense		15,242			29,274
Balance, end of period	$	737,490		$	730,604

5.           Related Party Transactions

In accordance with the laws of the State of Delaware, Mewbourne Development Corporation (“MD”), a Delaware Corporation, has been appointed as the Partnership’s managing general partner. MD has no significant equity interest in the Partnership. Mewbourne Oil Company (“MOC”) is operator of oil and gas properties owned by the Partnership.  Mewbourne Holdings, Inc. is the parent of both MD and MOC.  Substantially all transactions are with MD and MOC.

In the ordinary course of business, MOC will incur certain costs that will be passed on to 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. Services and 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 will pay to MD a management fee in the amount equal to .75% of the subscriptions by the investor partners to the Partnership.  The Partnership will include the management fee as part of the full cost pool pursuant to 4-10(c)(2) of Regulation S-X.

In accordance with the Partnership agreement, 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.

8

The Partnership participates in oil and gas activities through the Program. The Partnership and MD are the parties to the Program, and the costs and revenues are allocated between them as follows:

	Partnership			MD
Revenues:
Proceeds from disposition of depreciable and depletable properties		75	%		25	%
All other revenues		75	%		25	%
Costs and expenses:
Organization and offering costs (1)		0	%		100	%
Lease acquisition costs (1)		0	%		100	%
Tangible and intangible drilling costs (1)		100	%		0	%
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)   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.

Item 2.           Management’s Discussion and Analysis of Financial Condition and Results of Operations

Liquidity and Capital Resources

Mewbourne Energy Partners 10-A, L.P. (“the Partnership”) was formed February 9, 2010. The offering of limited and general partnership interests began May 1, 2010 and concluded August 2, 2010, with total investor contributions of $73,000,000. During 2012, all general partner equity interests were converted to limited partner equity interests.

Future capital requirements and operations will be conducted with available funds generated from oil and gas activities.  No bank borrowing is anticipated.  The Partnership had net working capital of $1,870,125at June 30, 2013.

During the six months ended June 30, 2013, the Partnership made cash distributions to the investor partners in the amount of $4,951,775 as compared to $13,750,001for the six months ended June 30, 2012. The Partnership expects that cash distributions will continue during 2013 as additional oil and gas revenues are sufficient to produce cash flows from operations.

The sale of crude oil and natural gas produced by the Partnership will be affected by a number of factors that are beyond the Partnership’s control.  These factors include the price of crude oil and natural gas, the fluctuating supply of and demand for these products, competitive fuels, refining, transportation, extensive federal and state regulations governing the production and sale of crude oil and natural gas, and other competitive conditions.  It is impossible to predict with any certainty the future effect of these factors on the Partnership.

9

Results of Operations

For the three months ended June 30, 2013 as compared to the three months ended June 30, 2012:

	Three Months Ended June 30,
	2013		2012
Oil sales	$	2,280,703	$	3,387,960
Barrels produced		25,035		38,632
Average price/bbl	$	91.10	$	87.70
Gas sales	$	1,043,174	$	1,280,957
Mcf produced		199,081		321,128
Average price/mcf	$	5.24	$	3.99

Oil and gas revenues.  As shown in the above table, total oil and gas sales fell by $1,345,040, a 28.8% decrease, for the three months ended June 30, 2013 as compared to the three months ended June 30, 2012.

Of this decrease, revenues declined by $1,238,695 and $639,520 from decreases in the volumes of oil and gas sold, respectively. Volumes fell by 13,597 barrels (bbls) and 122,047 thousand cubic feet (mcf) for the three months ended June 30, 2013 as compared to the three months ended June 30, 2012.

These decreases were partially offset by increases of $131,438 and $401,737from increases in the average prices of oil and gas sold, respectively. The average prices rose to $91.10 from $87.70 per bbl and to $5.24 from $3.99 per mcf for the three months ended June 30, 2013 as compared to the three months ended June 30, 2012.

Lease operations.  Lease operating expense during the three month period ended June 30, 2013 fell to $296,569 from $332,830 for the three month period ended June 30, 2012 due to fewer well repairs and workovers.

Production taxes.  Production taxes during the three month period ended June 30, 2013 decreased to $73,693 from $131,384for the three month period ended June 30, 2012 due to production tax credits and lower overall oil and gas revenue.

Administrative and general expense.  Administrative and general expense for the three month period ended June 30, 2013 decreased to $128,441 from $269,961 for the three month period ended June 30, 2012 due to decreased administrative expenses allocable to the Partnership.

Depreciation, depletion and amortization.  Depreciation, depletion and amortization for the three month period ended June 30, 2013 decreased to $975,281 from $1,783,323 for the three month period ended June 30, 2012 due to the decreased production volumes for the three month period ended June 30, 2013.

Cost ceiling write-down.  There were cost ceiling write-downs of $1,757,285 and $1,754,323 at June 30, 2013 and 2012, respectively. These were due to lower average oil and gas prices for the preceding twelve months.

10

Results of Operations

For the six months ended June 30, 2013 as compared to the six months ended June 30, 2012:

	Six Months Ended June 30,
	2013		2012
Oil sales	$	4,025,512	$	8,411,486
Barrels produced		45,267		89,516
Average price/bbl	$	88.93	$	93.97
Gas sales	$	2,268,251	$	3,362,082
Mcf produced		422,292		709,765
Average price/mcf	$	5.37	$	4.74

Oil and gas revenues.  As shown in the above table, total oil and gas sales fell by $5,479,805, a 46.5% decrease, for the six months ended June 30, 2013 as compared to the six months ended June 30, 2012.

Of this decrease, revenues declined by $3,934,983 and $1,544,100 from decreases in the volumes of oil and gas sold, respectively. Volumes fell by 44,249 barrels (bbls) and 287,473 thousand cubic feet (mcf) for the six months ended June 30, 2013 as compared to the six months ended June 30, 2012.

Also contributing to the decrease was $450,991 due to a decline in the average price of oil sold. The average price fell to $88.93from $93.97 per bbl for the six months ended June 30, 2013 as compared to the six months ended June 30, 2012.

These decreases were partially offset by an increase of $450,269from a rise in the average price of gas sold. The average price rose to $5.37 from $4.74 for the six months ended June 30, 2013 as compared to the six months ended June 30, 2012.

Lease operations.  Lease operating expense during the six month period ended June 30, 2013 fell to $649,942 from $793,014 for the six month period ended June 30, 2012 due to fewer well repairs and workovers.

Production taxes.  Production taxes during the six month period ended June 30, 2013 decreased to $96,606 from $518,307for the six month period ended June 30, 2012 due to production tax credits and lower overall oil and gas revenue.

Administrative and general expense.  Administrative and general expense for the six month period ended June 30, 2013 decreased to $266,338 from $647,847 for the six month period ended June 30, 2012 due to decreased administrative expenses allocable to the Partnership.

Depreciation, depletion and amortization.  Depreciation, depletion and amortization for the six month period ended June 30, 2013 decreased to $1,889,256 from $3,985,230 for the six month period ended June 30, 2012 due to the decreased production volumes for the six month period ended June 30, 2013.

Cost ceiling write-down.  There were cost ceiling write-downs of $2,720,640 and $1,754,823 at June 30, 2013 and 2012, respectively. These were due to lower average oil and gas prices for the preceding twelve months.

11

Item 3.         Quantitative and Qualitative Disclosures about Market Risk

1.    Interest Rate Risk

The Partnership Agreement allows borrowings from banks or other financial sources of up to 20% of the total capital contributions to the Partnership without investor approval. Should the Partnership elect to borrow monies for additional development activity on Partnership properties, it will be subject to the interest rate risk inherent in borrowing activities. Changes in interest rates could significantly affect the Partnership’s results of operations and the amount of net cash flow available for partner distributions. Also, to the extent that changes in interest rates affect general economic conditions, the Partnership will be affected by such changes.

2.    Commodity Price Risk

The Partnership does not expect to engage in commodity futures trading or hedging activities or enter into derivative financial instrument transactions for trading or other speculative purposes.  The Partnership currently expects to sell a significant amount of its production from successful oil and gas wells on a month-to-month basis at market prices. Accordingly, the Partnership is at risk for the volatility in commodity prices inherent in the oil and gas industry, and the level of commodity prices will have a significant impact on the Partnership’s results of operations. For the six months ended June 30, 2013, a 10% change in the price received for oil and gas production would have had an approximate $629,000 impact on revenue.

 3.    Exchange Rate Risk

The Partnership currently has no income from foreign sources or operations in foreign countries that would subject it to currency exchange rate risk. The Partnership does not currently expect to purchase any prospects located outside of either the United States or United States coastal waters in the Gulf of Mexico.

Item 4.           Disclosure Controls and Procedures

MD maintains a system of controls and procedures designed to provide reasonable assurance as to the reliability of the financial statements and other disclosures included in this report, as well as to safeguard assets from unauthorized use or disposition.  MD’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of its disclosure controls and procedures with the assistance and participation of other members of management.  Based upon that evaluation, MD’s Chief Executive Officer and Chief Financial Officer concluded that its disclosure controls and procedures are effective for gathering, analyzing and disclosing the information the Partnership is required to disclose in the reports it files under the Securities Exchange Act of 1934 within the time periods specified in the SEC’s rules and forms. Since MD’s December 31, 2012 annual report on internal control over financial reporting, and for the quarter ended June 30, 2013, there have been no changes in MD’s internal controls or in other factors which have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

12

Part II –  Other Information

Item 1.           Legal Proceedings

From time to time, the Registrant may be a party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, the Partnership does not expect these matters to have a material effect on its financial position or results of operations.

Item 6.            Exhibits and Reports on Form 8-K
	(a)	Exhibits filed herewith
		31.1	Certification of CEO Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.
		31.2	Certification of CFO Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.
		32.1	Certification of CEO Pursuant to Section 906 of Sarbanes-Oxley Act of 2002.
		32.2	Certification of CFO Pursuant to Section 906 of Sarbanes-Oxley Act of 2002.
		101	The following materials from the Partnership's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013 formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Balance Sheets, (ii) the Condensed Statements of Operations, (iii) the Condensed Statements of Cash Flows, (iv) the Condensed Statement of Changes in Partners’ Capital and (v) related notes.
	(b)	Reports on Form 8-K
			None.

13

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Partnership has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.

Mewbourne Energy Partners 10-A, L.P.
By:	Mewbourne Development Corporation
	Managing General Partner

Date:    August 14, 2013

By:	/s/ Alan Clark
	Alan Clark, Treasurer and Controller

14

INDEX TO EXHIBITS

EXHIBIT NUMBER	DESCRIPTION
31.1	Certification of CEO Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.
31.2	Certification of CFO Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.
32.1	Certification of CEO Pursuant to Section 906 of Sarbanes-Oxley Act of 2002.
32.2	Certification of CFO Pursuant to Section 906 of Sarbanes-Oxley Act of 2002.
101	The following materials from the Partnership's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013 formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Balance Sheets, (ii) the Condensed Statements of Operations, (iii) the Condensed Statements of Cash Flows, (iv) the Condensed Statement of Changes in Partners’ Capital and (v) related notes.

15