United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended ~~September~~March 3031, ~~2015~~2016

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

For the transition period from to

Commission file number 333-150925-03

ATLAS RESOURCES PUBLIC #18-2008 (A) L.P.

(Name of small business issuer in its charter)

Delaware		26-2202544
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Park Place Corporate Center One 1000 Commerce Drive, 4th Floor Pittsburgh, PA		15275
(Address of principal executive offices)		(zip code)

Issuer’s telephone number, including area code: (412)-489-0006

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 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 þ No ¨

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 þ No ¨

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,” “non accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer	¨	Accelerated filer	¨

Non-accelerated filer	¨	Smaller reporting company	þ

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

ATLAS RESOURCES PUBLIC #18-2008 (A) L.P.

(A Delaware Limited Partnership)

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

		PAGE
PART I.	FINANCIAL INFORMATION (Unaudited)
Item 1:
	Condensed Balance Sheets as of September 30, 2015 and December 31, 2014	3
	Condensed Balance Sheets as of March 31, 2016 and December 31, 2015	3
	Condensed Statements of Operations for the Three and Nine Months ended September 30, 2015 and 2014	4
	Condensed Statements of Operations for the Three Months ended March 31, 2016 and 2015	4
	Condensed Statements of Comprehensive Loss for the Three and Nine Months ended September 30, 2015 and 2014	5
	Condensed Statements of Comprehensive Loss for the Three Months ended March 31, 2016 and 2015	5
	Condensed Statement of Changes in Partners’ (Deficit) Capital for the Nine Months ended September 30, 2015	6
	Condensed Statement of Changes in Partners’ Deficit for the Three Months ended March 31, 2016	6
	Condensed Statements of Cash Flows for the Nine Months ended September 30, 2015 and 2014	7
	Condensed Statements of Cash Flows for the Three Months ended March 31, 2016 and 2015	7
	Notes to Condensed Financial Statements	8
Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1813
Item 4:	Controls and Procedures	2317
PART II.	OTHER INFORMATION
Item 1:	Legal Proceedings	2318
Item 6:	Exhibits	2419
SIGNATURES		2520
CERTIFICATIONS

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS RESOURCES PUBLIC #18-2008 (A) L.P.

CONDENSED BALANCE SHEETS

(Unaudited)

	September 30,2015			December 31,2014
	March 31,2016			December 31,2015
ASSETS
Current assets:
Cash	$	-		$	~~44,900~~-
Accounts receivable trade–affiliate		258,100			572,000
Account receivable trade-affiliate		178,700			256,900
Asset retirement receivable-affiliate		163,400			26,300
Current portion of derivative assets		200,800			241,600
Current portion of derivative assets		242,700			269,800
Total current assets		379,500			498,500
Total current assets		664,200			913,000
Gas and oil properties, net		2,611,900			2,651,600
Gas and oil properties, net		5,762,300			6,840,400
Long-term asset retirement receivable-affiliate		201,100			201,800
Long-term derivative assets		45,900			120,700
Total assets	$	3,192,500		$	3,351,900
	$	6,472,400		$	7,874,100
LIABILITIES AND PARTNERS’ DEFICIT
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable trade-affiliate	$	~~475~~759,~~300~~400		$	~~407~~694,~~200~~100
Accrued liabilities		3331,~~700~~800			2625,~~600~~500
Current portion of put premiums payable-affiliate		39,600			35,600
Put premiums payable-affiliate		29,600			43,600
Total current liabilities		~~548~~820,~~600~~800			~~469~~763,~~400~~200
Asset retirement obligations		34,~~989~~084,~~700~~300			34,~~825~~043,~~600~~900
Long-term put premiums payable-affiliate		10,200			40,700
Commitments and contingencies (Note 6)
Commitments and contingencies
Partners’ deficit:
Partners’ (deficit) capital:
Managing general partner’s deficit		(1,498,900	)		(1,426,300	)
Managing general partner’s deficit		(1,052,600	)		(746,400	)
Limited partners’ deficit (20,152.50 units)		(216,700	)		(32,900	)
Limited partners’ interest (20,152.50 units)		2,970,000			4,269,100
Accumulated other comprehensive income		3,000			4,000
Accumulated other comprehensive income		6,500			15,700
Total partners’ deficit		(1,712,600	)		(1,455,200	)
Total partners’ capital		1,923,900			3,538,400
Total liabilities and partners’ deficit	$	3,192,500		$	3,351,900
	$	6,472,400		$	7,874,100

See accompanying notes to condensed financial statements.

ATLAS RESOURCES PUBLIC #18-2008 (A) L.P.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months EndedSeptember 30,								Nine Months EndedSeptember 30,
		Three Months Ended
		2015				2014				2015			2014
		March 31,
REVENUES
			2016			2015
Natural gas and oil	$	391,700			$	712,600			$	1,481,500		$	3,156,400
REVENUES
Interest		-				-				-			100
Natural gas, oil and liquids		$	261,400			$	741,200
Gain on mark-to-market derivatives		~~88,300~~	36,500			-	22,300			~~141,200~~			-
Total revenues		~~480,000~~	297,900			~~712,600~~	763,500			~~1,622,700~~			~~3,156,500~~
COSTS AND EXPENSES
Production		~~515,600~~	436,100			~~639,400~~	598,900			~~1,687,100~~			~~2,016,800~~
Depletion		~~117,300~~	39,700			~~434,400~~	204,000			~~344,500~~			~~1,254,200~~
Impairment		733,600				-				733,600			-
Accretion of asset retirement obligations			41,100				62,600
Accretion of asset retirement obligation		38,900				38,100				164,100			114,500
General and administrative			37,400				46,300
General and administrative		41,200				45,500				131,100			132,600
Total costs and expenses			554,300				911,800
Total costs and expenses		1,446,600				1,157,400				3,060,400			3,518,100
Net loss		$	(256,400	)		$	(148,300	)
Net loss	$	(966,600	)		$	(444,800	)		$	(1,437,700	)	$	(361,600	)
Allocation of net loss:
Allocation of net (loss) income:
Managing general partner		$	(72,600	)		$	(27,100	)
Managing general partner	$	(177,000	)		$	(37,600	)		$	(285,200	)	$	199,900
Limited partners		$	(183,800	)		$	(121,200	)
Limited partners	$	(789,600	)		$	(407,200	)		$	(1,152,500	)	$	(561,500	)
Net loss per limited partnership unit		$	(9	)		$	(6	)
Net loss per limited partnership unit	$	(39	)		$	(20	)		$	(57	)	$	(28	)

See accompanying notes to condensed financial statements.

ATLAS RESOURCES PUBLIC #18-2008 (A) L.P.

CONDENSED STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)

	Three Months EndedSeptember 30,								Nine Months EndedSeptember 30,
		Three Months Ended
		2015				2014				2015			2014
		March 31,
Net loss	$	(966,600	)		$	(444,800	)		$	(1,437,700	)	$	(361,600	)
		2016				2015
Other comprehensive (loss) income:
Net loss		$	(256,400	)		$	(148,300	)
Unrealized holding gain on cash flow hedging contracts		-				175,000				-			32,400
Other comprehensive loss:
Difference in estimated hedge gains receivable		(13,200	)			(79,400	)			(35,100	)		(71,200	)
Difference in estimated hedge receivable			-				32,000
Less: Reclassification adjustment for realized gains of cash flow hedges in net loss		10,300				84,400				25,900			152,500
Reclassification adjustment to net loss of mark-to-market gains on cash flow hedges			(1,000	)			(35,000	)
Total other comprehensive (loss) income		(2,900	)			180,000				(9,200	)		113,700
Total other comprehensive loss			(1,000	)			(3,000	)
Comprehensive loss	$	~~(969,500~~$	)(257,400	)	$	~~(264,800~~$	)(151,300	)	$	~~(1,446,900~~	)	$	~~(247,900~~	)

See accompanying notes to condensed financial statements.

ATLAS RESOURCES PUBLIC #18-2008 (A) L.P.

CONDENSED STATEMENT OF CHANGES IN PARTNERS’ (DEFICIT) ~~CAPITAL~~

FOR THE ~~NINE~~THREE MONTHS ENDED

~~September~~March 3031, ~~2015~~2016

(Unaudited)

	ManagingGeneralPartner			LimitedPartners			Accumulated OtherComprehensiveIncome (Loss)			Total
Balance at December 31, 2014	$	(746,400	)	$	4,269,100		$	15,700		$	3,538,400
Balance at December 31, 2015	$	(1,426,300	)	$	(32,900	)	$	4,000		$	(1,455,200	)
Participation in revenues, costs and expenses:
Net production expenses		(5347,~~800~~100	)		(~~151~~127,~~800~~600	)		-			(~~205~~174,~~600~~700	)
Gain on mark-to-market derivatives		-			~~141~~36,~~200~~500			-			~~141~~36,~~200~~500
Depletion		(353,~~700~~800	)		(~~308~~35,~~800~~900	)		-			(~~344~~39,~~500~~700	)
Impairment		(114,000	)		(619,600	)		-			(733,600	)
Accretion of asset retirement obligations		(11,400	)		(29,700	)		-			(41,100	)
Accretion of asset retirement obligation		(45,400	)		(118,700	)		-			(164,100	)
General and administrative		(10,300	)		(27,100	)		-			(37,400	)
General and administrative		(36,300	)		(94,800	)		-			(131,100	)
Net loss		(72,600	)		(183,800	)		-			(256,400	)
Net loss		(285,200	)		(1,152,500	)		-			(1,437,700	)
Other comprehensive loss		-			-			(1,000	)		(1,000	)
Other comprehensive loss		-			-			(9,200	)		(9,200	)
Balance at March 31, 2016	$	(1,498,900	)	$	(216,700	)	$	3,000		$	(1,712,600	)
Distributions to partners		(21,000	)		(146,600	)		-			(167,600	)
Balance at September 30, 2015	$	(1,052,600	)	$	2,970,000		$	6,500		$	1,923,900

See accompanying notes to condensed financial statements.

ATLAS RESOURCES PUBLIC #18-2008 (A) L.P.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months EndedSeptember 30,
		Three Months Ended
		2015				2014
		March 31,
Cash flows from operating activities:
		2016				2015
Net loss	$	(1,437,700	)		$	(361,600	)
Cash flows from operating activities:
Adjustments to reconcile net loss to net cash provided by operating activities:
Net loss		$	(256,400	)		$	(148,300	)
Depletion		344,500				1,254,200
Adjustments to reconcile net loss to net cash provided by operating activities:
Impairment		733,600				-
Depletion			39,700				204,000
Non-cash loss on derivative value		66,200				81,100
Non cash loss (gain) on derivative value			25,800				(25,300	)
Accretion of asset retirement obligation		164,100				114,500
Accretion of asset retirement obligations			41,100				62,600
Changes in operating assets and liabilities:
Asset retirement obligations settled			(700	)			-
Decrease in accounts receivable trade-affiliate		313,900				557,900
Changes in operating assets and liabilities:
Increase in asset retirement receivable-affiliate		(137,100	)			(26,300	)
Decrease in accounts receivable trade-affiliate			78,200				12,700
Increase (decrease) in accounts payable trade-affiliate		68,200				(15,300	)
Decrease (increase) in asset retirement receivable-affiliate			700				(75,400	)
Increase (decrease) in accrued liabilities		7,000				(9,200	)
Increase in accounts payable trade-affiliate			65,300				-
Asset retirement obligations settled		-				(28,600	)
Increase in accrued liabilities			6,300				3,600
Net cash provided by operating activities		~~122,700~~	-			~~1,566,700~~	33,900
Cash flows from investing activities:
Purchase of tangible equipment		-				(3,700	)
Net cash used in investing activities			-				-
Proceeds from the sale of tangible equipment		-				1,100
Cash flows from financing activities:
Proceeds from the sale of oil and gas properties		-				1,003,800
Distributions to partners			-				(41,600	)
Net cash provided by investing activities		-				1,001,200
Net cash used in financing activities			-				(41,600	)
Cash flows from financing activities:
Net change in cash			-				(7,700	)
Distributions to partners		(167,600	)			(2,876,200	)
Cash at beginning of period			-				44,900
Net cash used in financing activities		(167,600	)			(2,876,200	)
Cash at end of period		$	-			$	37,200
Net change in cash and cash equivalents		(44,900	)			(308,300	)
Cash and cash equivalents at beginning of period		44,900				467,600
Cash and cash equivalents at end of period	$	-			$	159,300

See accompanying notes to condensed financial statements.

ATLAS RESOURCES PUBLIC #18-2008 (A) L.P.

NOTES TO CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2015~~2016

(Unaudited)

NOTE 1 - DESCRIPTION OF BUSINESS

Atlas Resources Public #18-2008 (A) L.P. (the “Partnership”) is a Delaware limited partnership, formed on April 8, 2008 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP). Unless the context otherwise requires, references to “the Partnership,” “we,” “us” and “our”, refer to Atlas Resources Public #18-2008 (A) L.P.

~~On February 27, 2015, the MGP’s ultimate parent,~~ Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership, was acquired by Targa Resources Corp. and distributed to Atlas Energy’s unitholders 100% of the limited liability company interests in ARP’s general partner, Atlas Energy Group, LLC (“Atlas Energy Group”; ~~NYSE~~OTCQX: ATLS). ~~Atlas~~manages ~~Energy Group became a separate, publicly traded company and the ultimate parent of the MGP as a result of the distribution. Following the distribution, Atlas Energy Group continues to manage~~ ARP’s operations and activities through its ownership of ARP’s general partner interest.

The Partnership has drilled and currently operates wells located in Pennsylvania, Tennessee, Indiana, West Virginia and Ohio. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy Group ~~(February 27~~, ~~2015 and prior, Atlas Energy),~~ for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas, oil and ~~oil~~NGL. Produced natural gas, oil and ~~oil~~NGL is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.

The accompanying condensed financial statements, which are unaudited, except that the balance sheet at December 31, 2014 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in the Partnership’s Form 10-K. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014. The results of operations for the three and nine months ended September 30, 2015 may not necessarily be indicative of the results of operations for the full year ended December 31, 2015.

The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues.

The prices at which the Partnership’s natural gas, oil and ~~oil~~NGL will be sold are uncertain and the Partnership is not guaranteed a specific ~~natural gas~~ price for the sale of its ~~natural gas~~ production. Changes in natural gas, oil and ~~oil~~NGL prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas, oil and ~~oil~~NGL prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas, oil and ~~oil~~NGL that the Partnership can produce economically.

~~Historically,~~Liquidity ~~there has been no need to borrow funds from the MGP to fund operations as the amount of funds generated by the Partnership’s operations has been adequate to fund future operations~~ and ~~distributions~~Capital toResources the partners. However, recent declines in commodity prices may challenge the Partnership’s ability to pay its obligations as they become due and its intention to produce its wells until they are depleted, as they may become uneconomical to produce. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP has planned, as necessary, to continue the Partnership’s operations and to fund the Partnership’s operations for at least the next 12 months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to the Partnership’s ability to continue as a going concern.

The Partnership is generally limited to the amount of funds generated by the cash flow from its operations to fund its obligations and make distributions, if any, to its partners.

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines throughout 2015 and have continued to decline and remain low in 2016. The extreme ongoing volatility in the energy industry and commodity prices will likely continue to impact the Partnership’s outlook. The Partnership has experienced downward revisions of its natural gas and oil reserves volumes and values due to the significant declines in commodity prices. The MGP continues to implement various cost saving measures to reduce the Partnership’s operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be opportunistic and aggressive in managing the Partnership’s cost structure and, in turn, liquidity to meet its operating needs. To the extent commodity prices remain low or decline further, or the Partnership experiences other disruptions in the industry, the Partnership’s ability to fund its operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate the Partnership’s operations.

Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from the Partnership’s operations have been adequate to fund its obligations and distributions to its partners. However, the recent significant declines in commodity prices have challenged the Partnership’s ability to fund its operations and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP intends, as necessary, to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to the Partnership’s ability to continue as a going concern. To the extent commodity prices remain low or decline further, ARP experiences disruptions in the financial markets impacting its respective longer-term access to or cost of capital, or ARP experiences any of the other impacts to its liquidity discussed below, the MGP’s ability to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months, as necessary, may be impacted.

ARP’s revolving credit facility is currently in the process of its semi-annual redetermination. Based on projected market conditions, continued declines in commodity prices and recent conversations with its administrative agent, ARP expects that its borrowing base will be redetermined to a level below its outstanding borrowings as of March 31, 2016. If ARP’s borrowing base is redetermined below its current outstanding borrowings and ARP is unable to repay the deficiency or deposit additional collateral to eliminate such deficiency, or if ARP experiences any other event of default on its debt obligations, or if other debt agreements cross-default, and the lenders accelerate the maturity of any other outstanding debts, the MGP, may not have sufficient liquidity to continue the Partnership’s operations and to fund the Partnership’s obligations, and as a result, there would be substantial doubt regarding the Partnership’s ability to continue as a going concern.

If, however, the MGP were to decide to liquidate our operations, the liquidation valuation of the Partnership’s assets and liabilities would be determined by an independent expert. It is possible that based on such determination, we would not be able to make any liquidation distributions to our limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners.

The condensed financial statements, which are unaudited, except for the balance sheet at December 31, 2015, which is derived from audited financial statements, have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to those rules and regulations, although we believe that the disclosures made are adequate to make the information not misleading. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015. The results of operations for the three months ended March 31, 2016 may not necessarily be indicative of the results of operations for the year ended December 31, 2016.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. Management has considered for disclosure any material subsequent events through the date the financial statements were issued.

In addition to matters discussed further in this note, the Partnership’s significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership’s annual report on Form 10-K for the year ended December 31, 2014 filed with the Securities and Exchange Commission (“SEC”).

Use of Estimates

The preparation of the Partnership’s financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, ~~asset~~ impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three ~~and nine~~ months ended ~~September~~March 3031, ~~2015~~2016 and ~~2014~~2015 represent actual results in all material respects ~~(See “-Revenue Recognition”)~~.

Accounts Receivable

Accounts receivable on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of the Partnership’s accounts receivable, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At September 30, 2015 and December 31, 2014, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for uncollectible accounts receivable.

Gas and Oil Properties

Gas and oil properties are stated at cost. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.

The Partnership follows the successful efforts method of accounting for gas and oil producing activities. Oil and natural gas liquids (“NGLs”) are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six Mcf of natural gas. Mcf is defined as one thousand cubic feet.

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The Partnership recorded depletion expense on natural gas and oil properties of $344,500 and $1,254,200 for the nine months ended September 30, 2015 and 2014, respectively.

~~Upon~~Gas ~~the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts~~ and ~~the~~Oil ~~resultant~~Properties gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depletion within its balance sheets.

The following is a summary of gas and oil properties at the dates indicated:

	September 30,			December 31,
	March 31,			December 31,
	2015			2014
	2016			2015
Proved properties:
Leasehold interests	$	2,387,700		$	2,387,700
Wells and related equipment		212,713,600			212,713,600
Total natural gas and oil properties		215,101,300			215,101,300
Accumulated depletion and impairment		(~~209~~212,~~339~~489,~~000~~400	)		(~~208~~212,~~260~~449,~~900~~700	)
Gas and oil properties, net	$	52,~~762~~611,~~300~~900		$	62,~~840~~651,~~400~~600

~~Impairment~~As a result of ~~Long-Lived~~the ~~Assets~~recent significant declines in commodity prices and associated recorded impairment charges, remaining net book value of gas and oil properties on our balance sheet at March 31, 2016 and December 31, 2015 was primarily related to the estimated salvage value of such properties. The estimated salvage values were based on the MGP’s historical experience in determining such values.

The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount of that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of the Partnership’s gas and oil properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by the discounted cash flows) and the carrying value of the assets.

The determination of natural gas and oil reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.

During the three and nine months ended September 30, 2015, the Partnership recognized $733,600 of impairment related to gas and oil properties. There was no gas and oil properties impairment recorded for the three and nine months ended September 30, 2015 and 2014. The impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at September 30, 2015. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement.

Derivative Instruments

The Partnership’s MGP enters into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (See Note 4). The derivative instruments recorded on the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 will be reclassified to the statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within partners’ capital on the Partnership’s balance sheets and reclassified to the Partnership’s statements of operations at the time the originally hedged physical transactions affected earnings.

Asset Retirement Obligations

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells (See Note 3). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depletion.

Income Taxes

The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the accompanying financial statements. The federal and state income taxes related to the Partnership were immaterial to the financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the accompanying financial statements.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s MGP does not believe it has any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Partnership has not recognized any potential interest or penalties in its financial statements for the three and nine months ended September 30, 2015 and 2014.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of September 30, 2015.

Working Interest

The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 10% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

Revenue Recognition

The Partnership generally sells natural gas, crude oil and NGLs at prevailing market prices. Typically, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.

The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices (See “-Use of Estimates”). During the prior quarter ended September 30, 2014, the Partnership identified an error in its revenue recognition process. As a result, the Partnership overstated its June 30, 2014 unbilled revenues by $96,700. As a result, revenue and net income is overstated by $96,700 for the three and six months ended June 30, 2014. In adjusting for the overstatement of revenue and net income that existed at June 30, 2014, the third quarter revenue is understated by $96,700 and net loss is overstated for the three month period ended September 30, 2014. In addition, there was no impact on Partnership distributions. Refer to the Partnership’s Form 10-Q for the quarter ended September 30, 2014 for further explanation of this error. The Partnership had unbilled revenues at September 30, 2015 and December 31, 2014 of $237,700 and $499,800, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s financial statements and, at September 30, 2015, only include changes in the fair value of unsettled derivative contracts which, prior to January 1, 2015, were accounted for as cash flow hedges (See Note 4). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss).

Recently Issued Accounting Standards

In ~~January~~August ~~2015~~2014, the ~~Financial Accounting Standards Board (“~~FASB”) ~~issued~~updated ~~Accounting~~the ~~Standards~~accounting ~~Update~~guidance ~~(“ASU”)~~related ~~2015-01,~~to ~~Income~~the ~~Statement~~evaluation –of ~~Extraordinary~~whether ~~and~~there ~~Unusual~~is ~~Items~~substantial ~~(Subtopic~~doubt ~~225-20):~~about ~~Simplifying~~an ~~Income~~entity’s ~~Statement~~ability ~~Presentation~~to bycontinue ~~Eliminating~~as ~~the~~a ~~Concept~~going ~~of Extraordinary Items (“Update 2015-01”)~~concern. The ~~amendments~~updated inaccounting ~~Update~~guidance ~~2015-01~~requires ~~simplify~~an ~~the~~entity’s ~~income~~management ~~statement~~to ~~presentation~~evaluate ~~requirements~~whether inthere ~~Subtopic~~are ~~225-20~~conditions byor ~~eliminating~~events ~~the~~that ~~concept~~raise ofsubstantial ~~extraordinary~~doubt ~~items.~~about ~~Extraordinary~~its ~~items~~ability ~~are~~to ~~events~~continue ~~and~~as ~~transactions~~a ~~that~~going ~~are~~concern ~~distinguished~~within byone ~~their~~year ~~unusual~~from ~~nature~~the ~~and~~date by the ~~infrequency~~financial ofstatements ~~their occurrence. The amendments in Update 2015-01~~ are ~~effective~~issued ~~for fiscal years,~~ and ~~interim~~provide ~~periods~~footnote ~~within those fiscal years~~disclosures, ~~beginning~~if ~~after December 15, 2015~~necessary. AThe ~~reporting~~updated ~~entity~~guidance ~~may~~is ~~apply~~effective ~~the~~as ~~amendments~~of ~~prospectively.~~January A1, ~~reporting~~2017 ~~entity~~and ~~may also apply~~ the ~~amendments~~Partnership ~~retrospectively~~is tocurrently ~~all prior periods presented~~ in the ~~financial~~process ~~statements.~~of ~~Early~~determining ~~adoption is permitted provided that~~ the ~~guidance~~impact ~~is applied from the beginning~~ of ~~the~~providing ~~fiscal year of adoption. The Partnership will adopt~~ the ~~requirements~~enhanced ofdisclosures, ~~Update~~as ~~2015-01 upon its effective date of January 1~~applicable, ~~2016,~~within ~~and it does not anticipate it having a material impact on~~ its financial ~~position, results of operations or related disclosures~~statements.

In ~~August~~May 2014, the FASB ~~issued~~updated ~~ASU~~the ~~2014-15,~~accounting ~~Presentation~~guidance ofrelated ~~Financial~~to ~~Statements~~revenue ~~– Going Concern (Subtopic 205-40) (“Update 2014-15”)~~recognition. The ~~amendments~~updated inaccounting ~~Update~~guidance ~~2014-15~~provides ~~provide~~a ~~U.S.~~single, ~~GAAP~~contract-based ~~guidance~~revenue onrecognition ~~the~~model ~~responsibility~~to ofhelp animprove ~~entity’s~~financial ~~management~~reporting inby ~~evaluating~~providing ~~whether~~clearer ~~there~~guidance ison ~~substantial~~when ~~doubt~~an ~~about the~~ entity’s ~~ability~~should torecognize ~~continue~~revenue, ~~as a going concern~~ and ~~about~~by ~~related~~reducing ~~footnote~~the ~~disclosures.~~number ~~For~~of ~~each~~standards ~~reporting~~to ~~period,~~which an entity’s ~~management~~has ~~will be required~~ to ~~evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued~~refer. In ~~doing~~July so2015, the ~~amendments~~FASB invoted ~~Update~~to ~~2014-15~~defer ~~should reduce diversity in~~ the ~~timing~~effective ~~and~~date ~~content~~by ofone ~~footnote~~year ~~disclosures.~~to ~~The amendments in Update 2014-~~December 15, ~~are~~2017 ~~effective~~ for ~~the~~ annual ~~period~~reporting ~~ending~~periods beginning after ~~December~~that ~~15,~~date. ~~2016,~~The ~~and~~updated ~~for~~accounting ~~annual~~guidance ~~and~~provides ~~interim~~companies ~~periods~~with ~~thereafter.~~alternative ~~Early~~methods ~~adoption~~of ~~is permitted~~adoption. The Partnership ~~will~~is ~~adopt~~currently in the ~~requirements~~process of ~~Update~~determining ~~2014-15~~the ~~upon~~impact ~~its~~that ~~effective~~the ~~date~~updated inaccounting ~~2016,~~guidance ~~and~~will ithave ~~does not anticipate it having a material impact~~ on its financial ~~position,~~statements ~~results~~and ofits ~~operations~~method orof ~~related disclosures~~adoption.

12NOTE 3 - DERIVATIVE INSTRUMENTS

InThe ~~May 2014~~MGP, ~~the~~on ~~FASB~~behalf issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the ~~Accounting Standards Codification. In addition~~Partnership, ~~the~~uses ~~existing requirements for the recognition of~~ a ~~gain~~number ~~or loss on the transfer~~ of ~~nonfinancial~~different ~~assets~~derivative ~~that are not in a contract with a customer (for example~~instruments, ~~assets~~principally ~~within~~put ~~the~~contracts ~~scope of Topic 360, Property, Plant~~ and ~~Equipment~~swaps, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in ~~Update~~connection 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with ~~a customer, identify~~ the ~~performance~~Partnership’s ~~obligations~~commodity ~~in the contract, determine the transaction~~ price, ~~allocate~~risk ~~the~~management ~~transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations~~activities. The ~~These~~Partnership ~~requirements~~does ~~are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is~~ not ~~permitted.~~apply Onhedge ~~July~~accounting ~~9, 2015, the FASB decided~~ to ~~defer~~any ~~the effective date~~ of ~~ASU~~its ~~2014-09~~derivative ~~by one year~~instruments. As a result, ~~public~~gains ~~entities would apply the new revenue standard to annual reporting periods beginning after December 15, 2017,~~ and tolosses ~~interim~~associated ~~periods within that reporting period,~~ with ~~the~~derivative ~~option~~instruments toare ~~adopt~~recognized ~~the~~in ~~standard as of the original effective date~~earnings. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2018, and is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.

~~NOTE~~The 3Partnership enters into commodity put contracts and swaps to achieve more predictable cash flows by hedging the Partnership’s exposure to changes in commodity prices. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated ~~ASSET~~over-the-counter ~~RETIREMENT~~futures ~~OBLIGATIONS~~contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. These contracts have been recorded at their fair values.

The ~~estimated~~Partnership ~~liability~~reflected ~~for~~net ~~asset~~derivative ~~retirement~~assets ~~obligations was based~~ on ~~the~~its ~~MGP’s~~balance ~~historical~~sheets ~~experience~~of in$200,800 ~~plugging~~ and ~~abandoning wells~~$241,600 ~~the~~at ~~estimated~~March ~~remaining lives of those wells based on reserve estimates~~31, ~~external~~2016 ~~estimates as to the cost to plug~~ and ~~abandon~~December ~~the~~31, wells in the future and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its gas and oil properties2015, ~~the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets~~respectively.

The MGP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within the Partnership near the end of their useful life. On a partnership-by-partnership basis, the MGP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells and current and future costs. Generally, the MGP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon the MGP’s decision to retain all future distributions to the limited partners of the Partnership, the MGP will assume the related asset retirement obligations of the limited partners. As of September 30, 2015, the MGP has withheld $163,400 of net production revenue for future plugging and abandonment costs.10

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

	Three Months EndedSeptember 30,					Nine Months EndedSeptember 30,
		2015		2014			2015		2014
Asset retirement obligation at beginning of period	$	3,950,800	$	2,640,200		$	3,825,600	$	2,572,500
Accretion expense		38,900		38,100			164,100		114,500
Asset retirement obligations settled		-		(19,900	)		-		(28,600	)
Asset retirement obligation at end of period	$	3,989,700	$	2,658,400		$	3,989,700	$	2,658,400

NOTE 4 - DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally swaps, collars and options, in connection with the Partnership’s commodity price risk management activities. Management enters into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.

The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheets of $288,600 and $390,500 at September 30, 2015, and December 31, 2014, respectively. As a result of the put options, the Partnership recorded a net deferred gain on its balance sheet in accumulated other comprehensive income of $6,500 as of September 30, 2015. During the nine months ended September 30, 2015, $141,200 of net gains were recorded by the Partnership and allocated only to the limited partners. Of the $6,500 of deferred gains in accumulated other comprehensive income on the Partnership’s balance sheet at September 30, 2015, the Partnership will reclassify $5,600 of gains to its statement of operations over the next twelve month period as these contracts expire with the remaining gains of $900 being reclassified to the Partnership’s statements of operations in later periods as the remaining contracts expire.

The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated:

	Three Months EndedSeptember 30,						Nine Months EndedSeptember 30,
		Three Months Ended
	2015			2014			2015			2014
		March 31,
Loss reclassified from accumulated other comprehensive income into natural gas and oil revenues	$	(10,300	)	$	(84,400	)	$	(25,900	)	$	(152,500	)
		2016			2015
Gain subsequent to December 31, 2014 recognized in gain on mark-to-market derivatives	$	88,300		$	-		$	141,200		$	-
Gains reclassified from accumulated other comprehensive income into natural gas and oil revenues		$	1,000		$	35,000
Gains subsequent to hedge accounting recognized in gain on mark-to-market derivatives		$	36,500		$	22,300

~~The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices.~~ At ~~any~~March ~~point in time~~31, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions2016, ~~but may be settled by~~ the ~~physical~~Partnership ~~delivery~~had of the following commodity. derivatives:

At September 30, 2015, the Partnership had the following commodity derivatives:

Natural Gas Fixed Price Swaps - Limited Partners

ProductionPeriod EndingDecember 31,	Volumes		AverageFixed Price		Fair ValueAsset (2)
	(MMBtu)(1)		(per MMBtu)(1)
2015		45,000	$	4.22	$	73,300
2016		56,700	$	4.46	$	126,600
2016		75,600		4.46		124,400
					$	197,700

Natural Gas Put Options - Limited Partners

ProductionPeriod EndingDecember 31,	Volumes		AverageFixed Price		Fair ValueAsset (2)
	(MMBtu)(1)		(per MMBtu)(1)
2015		13,300	$	4.00	$	18,700
2016		38,500	$	4.15	$	74,200
2016		53,200		4.15		72,200
Limited Partner’s Commodity Derivatives, net					$	200,800
					$	90,900
				Total net assets	$	288,600

(1)

“MMBtu” represents million British Thermal Units.

(2)

Fair value based on forward NYMEX natural gas prices, as applicable.

At ~~September~~March 3031, ~~2015~~2016, ~~ARP~~the MGP had a secured hedge facility agreement with a syndicate of banks under which the Partnership has the ability to enter into derivative contracts to manage its exposure to commodity price movements. Under ~~ARP~~the MGP’s revolving credit facility, ~~ARP~~the Partnership is required to utilize this secured hedge facility for future commodity risk management activity. The Partnership’s obligations under the facility are secured by mortgages on its gas and oil properties and first priority security interests in substantially all of its assets and are guaranteed by ~~ARP~~the MGP. ~~ARP~~The MGP administers the commodity price risk management activity for the Partnership under the secured hedge facility. The secured hedge facility agreement contains covenants that limit the Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions, including a sale of all or substantially all of its assets. As of ~~September~~March 3031, ~~2015~~2016, only the Partnership’s natural gas swaps are included in the secured hedge facility.

~~Put~~As ~~Premiums~~the ~~Payable~~underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three months ended March 31, 2016 and 2015 for hedge ineffectiveness.

During June 2012, a premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At September 30, 2015 and December 31, 2014, $39,600 and $35,600, respectively, of the put premiums were recorded as short-term payables to affiliate and $10,200 and $40,700, respectively, were recorded as long-term payables to affiliate. 11

15Accumulated Other Comprehensive Income

~~NOTE~~As 5a -result ~~FAIR~~of ~~VALUE~~the OFput ~~FINANCIAL~~options, ~~INSTRUMENTS~~swaps and the unrealized gains recognized in income in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred gain on its balance sheet in accumulated other comprehensive income of $3,000 as of March 31, 2016. Included in accumulated other comprehensive income are unrealized gains of $57,700, net of the MGP interest, that were recognized in income as a result of gas and oil property impairments during prior periods. During the three months ended March 31, 2016, $4,700 of net losses were recorded by the Partnership and allocated only to the limited partners. Of the remaining $3,000 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $3,000 of net gains to the Partnership’s statements of operations over the next twelve month period.

~~The~~NOTE ~~Partnership~~4 ~~has~~- ~~established~~FAIR aVALUE ~~hierarchy~~OF toFINANCIAL ~~measure~~INSTRUMENTS its financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

~~Level~~The 1Partnership ~~– Unadjusted~~uses ~~quoted~~a ~~prices~~market inapproach ~~active~~fair ~~markets~~value ~~for~~methodology ~~identical,~~to ~~unrestricted~~value the assets and liabilities ~~that~~for its outstanding derivative contracts. The fair value of a financial instrument depends on a number of factors, including the ~~reporting~~availability ~~entity~~of ~~has~~observable market data over the ~~ability~~contractual toterm ~~access~~of atthe underlying instrument. The Partnership separates the ~~measurement~~fair ~~date~~value of its financial instruments into three levels (Levels 1, 2 and 3) based on its assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. As of March 31, 2016 and December 31, 2015, all derivative financial instruments were classified as Level 2.

~~Level~~Information 2for –assets ~~Inputs~~measured ~~other~~at ~~than~~fair ~~quoted~~value ~~prices~~at ~~included~~March ~~within~~31, ~~Level~~2016 ~~1 that are observable for the asset~~ and ~~liability~~December or31, ~~can~~2015 bewas ~~corroborated~~as ~~with~~follows: ~~observable market data for substantially the entire contractual term of the asset or liability.~~

Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

	Level 1		Level 2		Level 3		Total
As of March 31, 2016
Derivative assets, gross
Commodity swaps	$	-	$	126,600	$	-	$	126,600
Commodity puts		-		74,200		-		74,200
Total derivative assets, gross	$	-	$	200,800	$	-	$	200,800

Assets and Liabilities Measured at Fair Value on a Recurring Basis

	Level 1		Level 2		Level 3		Total
As of December 31, 2015
Derivative assets, gross
Commodity swaps	$	-	$	147,200	$	-	$	147,200
Commodity puts		-		94,400		-		94,400
Total derivative assets, gross	$	-	$	241,600	$	-	$	241,600

~~The~~NOTE ~~Partnership~~5 ~~uses~~- aCERTAIN ~~market~~RELATIONSHIPS ~~approach~~AND ~~fair~~RELATED ~~value~~PARTY ~~methodology~~TRANSACTIONS to value the assets and liabilities for its outstanding derivative contracts (See Note 4). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. The fair values of these derivative instruments are calculated by utilizing commodity indices quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and the pricing formula utilized in the derivative instrument.

~~Information~~The ~~for~~Partnership ~~assets~~has ~~measured~~entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at ~~fair~~$75 ~~value~~per well per month. Monthly well supervision fees, which are included in production expense in the Partnership’s statements of operations, are payable at ~~September~~$975 30per well per month for Marcellus wells, ~~2015~~$1,500 per well per month for New Albany wells, and ~~December~~for 31all other wells a fee of $392 is charged per well per month for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of the working interest in a well. Transportation fees are included in production expenses in the Partnership’s statements of operations and are generally payable at 16% of the natural gas sales price. Direct costs, ~~2014~~which ~~was~~are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as ~~follows:~~reimbursement for all costs expended on the Partnership’s behalf.

	Level 1		Level 2		Level 3		Total
As of September 30, 2015
Derivative assets, gross
Commodity swaps	$	-	$	197,700	$	-	$	197,700
Commodity puts		-		90,900		-		90,900
Total derivative assets, gross	$	-	$	288,600	$	-	$	288,600

	Level 1		Level 2		Level 3		Total
As of December 31, 2014
Derivative assets, gross
Commodity swaps	$	-	$	288,500	$	-	$	288,500
Commodity puts		-		102,000		-		102,000
Total derivative assets, gross	$	-	$	390,500	$	-	$	390,500

Other Financial Instruments

The estimated fair value of the Partnership’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership could realize upon the sale of such financial instruments. The Partnership’s other current assets and liabilities on its balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (See Note 3). There were no additional assets or liabilities that were measured at fair value on a nonrecurring basis for the three and nine months ended September 30, 2015 and 2014.

Management estimates the fair value of the Partnership’s long-lived assets in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances. During the three and nine months ended September 30, 2015, the Partnership recognized $733,600 of impairment related to gas and oil properties. No impairments were recognized during the three and nine months ended September 30, 2014.

NOTE 6 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Monthly well supervision fees, which are included in production expenses in the Partnership’s statements of operations, are payable at $975 per well per month for Marcellus wells, $1,500 per well per month for New Albany wells, and for all other wells a fee of $392 is charged per well per month for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of the working interest in a well. Transportation fees are included in production expenses in the Partnership’s statements of operations and are generally payable at 16% of the natural gas sales price. Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf.

The following table provides information with respect to these costs and the periods incurred:

	Three Months EndedSeptember 30,						Nine Months EndedSeptember 30,
		Three Months EndedMarch 31,
		2015			2014			2015		2014
		2016			2015
Administrative fees	$	~~23,700~~$	22,400	$	~~29,100~~$	29,300	$	~~79,000~~	$	~~86,700~~
Supervision fees		~~217,200~~	198,800		~~242,500~~	245,600		~~689,400~~		~~729,400~~
Transportation fees		~~64,500~~	50,000		~~71,000~~	96,600		~~206,600~~		~~346,700~~
Direct costs		~~251,400~~	202,300		~~342,300~~	273,700		~~843,200~~		~~986,600~~
Total	$	~~556,800~~$	473,500	$	~~684,900~~$	645,200	$	~~1,818,200~~	$	~~2,149,400~~

The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts ~~receivable~~payable trade-affiliate on the Partnership’s balance sheets includes the net production ~~revenues~~expenses due ~~from the MGP. Accounts payable trade-affiliate on the Partnership’s balance sheets include $407,200 relating~~ to ~~well construction for various Cowden wells due to~~ the MGP ~~at September 30, 2015 and December 31, 2014~~.

NOTE 76 - COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, ~~limited~~investor partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the Partnership ~~Agreement~~agreement. The MGP is not obligated to purchase more than 5% of the total outstanding units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.

Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of ~~September~~March 3031, ~~2015~~2016, the MGP has withheld $~~163~~201,~~400~~100 of net production revenue for future plugging and abandonment costs.

Legal Proceedings

The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.

Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their respective businesses. The MGP’s management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (UNAUDITED)

Forward-Looking Statements

When used in this Form 10-Q, the words “believes”, “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties, which could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

General

Atlas Resources Public #18-2008 (A) L.P. ~~(“we”, “us” or the “Partnership”)~~ is a Delaware limited partnership, formed on April 8, 2008 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP). Unless the context otherwise requires, references to “the Partnership,” “we,” “us” and “our”, refer to Atlas Resources Public #18-2008 (A) L.P.

~~On February 27, 2015, the MGP’s ultimate parent,~~ Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership, was acquired by Targa Resources Corp. and distributed to Atlas Energy’s unitholders 100% of the limited liability company interests in ARP’s general partner, Atlas Energy Group, LLC ~~(“Atlas~~manages Energy Group”; NYSE: ATLS). Atlas Energy Group became a separate, publicly traded company and the ultimate parent of the MGP as a result of the distribution. Following the distribution, Atlas Energy Group continues to manage ARP’s operations and activities through its ownership of the ARP’s general partner interest.

We have drilled and currently operate wells located in Pennsylvania, Tennessee, Indiana, West Virginia and Ohio. We have no employees and rely on our MGP for management, which in turn, relies on its parent company, Atlas Energy Group ~~(February 27~~, ~~2015 and prior, Atlas Energy),~~ for administrative services.

We intend to continue to produce our wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. We expect that no other wells will be drilled and no additional funds will be required for drilling.

Overview

The following discussion provides information to assist in understanding our financial condition and results of operations. Our operating cash flows are generated from our wells, which produce primarily natural gas, but also some oil. Our produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. Our ongoing operating and maintenance costs have been and are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We pay our MGP, as operator, a monthly well supervision fee, which covers all normal and regularly recurring operating expenses for the production and sale of natural gas and oil such as:

well tending, routine maintenance and adjustment;

reading meters, recording production, pumping, maintaining appropriate books and records; and

preparation of reports for us and government agencies.

18The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials and brine disposal. If these expenses are incurred, we pay cost for third-party services, materials and a competitive charge for services performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production, our MGP, as operator, may retain $200 per month, per well, to cover the estimated future plugging and abandonment costs of the well. As of March 31, 2016, our MGP has withheld $201,100 of net production revenues for this purpose.

The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials and brine disposal. If these expenses are incurred, we pay cost for third-party services, materials and a competitive charge for services performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production, our MGP, as operator, may retain $200 per month per well to cover the estimated future plugging and abandonment costs of the well. As of September 30, 2015, our MGP has withheld $163,400 of net production revenues for this purpose.

Markets and Competition

The availability of a ready market for natural gas and oil produced by us, and the price obtained, depends on numerous factors beyond our control, including the extent of domestic production, imports of foreign natural gas and oil, political instability or terrorist acts in gas and oil producing countries and regions, market demand, competition from other energy sources, the effect of federal regulation on the sale of natural gas and oil in interstate commerce, other governmental regulation of the production and transportation of natural gas and oil and the proximity, availability and capacity of pipelines and other required facilities. Our MGP is responsible for selling our production. During ~~2014~~2016 and ~~the first nine months of~~ 2015, we experienced no problems in selling our natural gas and oil. Product availability and price are the principal means of competing in selling natural gas and oil production. While it is impossible to accurately determine our comparative position in the industry, we do not consider our operations to be a significant factor in the industry.

1914

Results of Operations

The following table sets forth information relating to our production revenues, volumes, sales prices, production costs, and depletion during the periods indicated:

	Three Months EndedSeptember 30,							Nine Months EndedSeptember 30,
		Three Months Ended
		2015			2014				2015		2014
		March 31,
Production revenues (in thousands):
		2016			2015
Gas	$	384			678				1,425		3,114
Production revenues (in thousands):
Oil		-			35				14		42
Gas		$	255		$	705
Liquid gas		8			-				43		-
Oil			2			11
Total	$	392			713				1,482		3,156
Liquid gas			4			25
Production volumes:
Total		$	261		$	741
Gas (Mcf/day) (1)		2,846			3,169				2,808		3,066
Production volumes:
Oil (bbl/day) (1)		-			4				1		2
Gas (mcf/day) (1)			1,898			3,056
Liquid (bbls/day) (1)		8			-				9		-
Oil (bbl/day) (1)			1			3
Total (Mcfe/day) (1)		2,894			3,193				2,868		3,078
Liquid (bbls/day) (1)			7			13
Average sales prices: (2)
Total (mcfe/day) (1)			1,946			3,152
Gas (per Mcf) (1) (3) (4)	$	1.68			2.76				2.09		3.82
Average sales prices (2)
Oil (per bbl) (1)	$	-			96.13				44.15		94.38
Gas (per mcf) (1) (3)		$	1.58		$	2.77
Liquids (per bbl) (1)	$	11.77			-				17.28		-
Oil (per bbl) (1)		$	32.48		$	44.42
Production costs:
Liquids (per bbl) (1)		$	7.64		$	0.94
As a percent of revenues (4)		134	%		79	%			114	%	64	%
Production costs:
Per Mcfe (1)	$	1.94			2.18				2.15		2.40
As a percent of revenues			167	%		81	%
Depletion per Mcfe	$	0.44			1.48				0.44		1.49
Per mcfe (1)		$	2.47		$	2.11
Depletion per mcfe		$	0.22		$	0.65

(1) “Mcf” represents thousand cubic feet, “~~Mcfe~~mcfe” represents thousand cubic feet equivalent, and “bbl” represents barrels. Bbl is converted to ~~Mcfe~~mcfe using the ratio of six ~~Mcfs~~mcfs to one bbl.

(2)	Average sales prices represent accrual basis pricing after adjusting for the effect of previously recognized gains resulting from prior period impairment charges.

(3) Average gas prices are calculated by including in total revenue derivative gains previously recognized into income in connection with prior period impairment charges and dividing by the total volume for the period. Previously recognized derivative gains were $5618,200 and $3057,~~500~~900 for the three months ended ~~September~~March 3031, ~~2015~~2016 and ~~2014, respectively. Previously recognized derivative gains were $175,500 and $81,100 for the nine months ended September 30,~~ 2015 ~~and 2014~~, respectively.

~~(4)~~Natural ~~The~~Gas ~~average~~Revenues. ~~sales~~Our ~~price~~natural gas revenues were $254,900 and ~~production~~$704,700 ~~costs~~for asthe three months ended March 31, 2016 and 2015, respectively, a ~~percentage~~decrease of ~~revenues~~$449,800 ~~for~~(64%). The $449,800 decrease in natural gas revenues for the three months ended ~~September~~March 3031, ~~2014~~2016 ~~has~~as ~~been~~compared ~~adjusted~~to the prior year similar period was attributable to ~~reflect~~a $96262,100 decrease in production volumes and a $187,700 decrease in our natural gas sales prices after the effect of ~~additional~~financial ~~revenue~~hedges, which were driven by market conditions. Our production volumes decreased to 1,898 mcf per day for the three months ended March 31, 2016 from 3,056 mcf per day for the three months ended March 31, 2015, a decrease of 1,158 mcf per day (38%). The overall decrease in natural gas production volumes for the three months ended March 31, 2016 as compared to the prior year similar period resulted primarily from the normal decline inherent in the life of a well in addition to well shut-in due to it being uneconomical to continue production in the current pricing environment.

~~Natural~~Oil ~~Gas~~ Revenues. ~~During~~We ~~the~~drilled ~~quarter~~wells ~~ended~~primarily ~~September 30, 2014, management identified an error in the process used~~ to ~~estimate~~produce ~~our unbilled revenue. As a result,~~ natural gas ~~revenue for the three months ended September 30~~, ~~2014~~rather ~~includes~~than ~~an adjustment to reduce natural gas revenue by $96~~oil,~~700.~~ ~~The~~but ~~adjustment~~some iswells ~~the~~have ~~result~~limited ofoil ~~overestimating our unbilled revenues as of June 30, 2014~~production. ~~Refer to the Partnership’s Form 10-Q for the quarter ended September 30, 2014 for further explanation of this error.~~ Our ~~unadjusted~~oil ~~natural gas~~ revenues were $~~383~~1,~~600~~900 and $~~774~~11,~~200~~600 for the three months ended ~~September~~March 3031, ~~2015~~2016 and ~~2014~~2015, respectively, a decrease of $~~390~~9,~~600~~700 (5084%). The $~~390~~9,~~600~~700 decrease in ~~natural~~oil ~~gas~~ revenues for the three months ended ~~September~~March 3031, ~~2015~~2016 as compared to the prior year similar period was attributable to a $~~321~~9,~~600~~000 decrease in ~~our~~production ~~natural gas sales prices after the effect of financial hedges~~volumes, ~~which were driven by market conditions,~~ and a $~~69,000~~700 decrease in ~~production~~oil ~~volumes~~prices. Our production volumes decreased to ~~2,846~~1 ~~Mcf~~bbl per day for the three months ended ~~September~~March 3031, ~~2015~~2016 from 3~~,169~~ ~~Mcf~~bbls per day for the three months ended ~~September 30~~March 31, ~~2014~~2015, a decrease of ~~323~~2 ~~Mcf~~bbls per day (1067%). The overall decrease in natural gas production volumes for the three months ended September 30, 2015 as compared to the prior year similar period resulted primarily from the normal decline inherent in the life of a well and a decrease in the number of producing wells due to wells shut-in due to a decline in natural gas prices.

2015

~~Our~~Natural ~~natural~~Gas ~~gas~~Liquids ~~revenues~~Revenue. ~~were~~The ~~$1,424,600~~majority ~~and~~of ~~$3,114,500~~our ~~for~~wells ~~the~~produce ~~nine~~“dry ~~months ended September 30~~gas”, ~~2015~~which ~~and~~is ~~2014,~~composed ~~respectively,~~primarily aof ~~decrease~~methane ofand ~~$1,689,900~~requires ~~(54%).~~no ~~The~~additional ~~$1,689,900~~processing ~~decrease~~before inbeing ~~natural~~transported ~~gas~~and ~~revenues~~sold ~~for~~to the ~~nine~~purchaser. ~~months~~Some ~~ended~~wells, ~~September 30~~however, ~~2015~~produce as“wet ~~compared~~gas”, towhich ~~the~~contains ~~prior~~larger ~~year~~amounts ~~similar~~of ~~period~~ethane ~~was~~and ~~attributable~~other toassociated ahydrocarbons ~~$1,428,100~~(i.e. ~~decrease in our~~ “natural gas ~~sales~~liquids”) ~~prices~~that ~~after~~must ~~the~~be ~~effect~~removed ofprior ~~financial~~to ~~hedges,~~transporting ~~which~~the ~~were~~gas. ~~driven~~Once byremoved, ~~market~~these ~~conditions,~~natural ~~and~~gas aliquids ~~$261,800~~are ~~decrease~~sold into ~~production~~various ~~volumes~~purchasers. Our ~~production~~natural ~~volumes~~gas ~~decreased~~liquids torevenues 2were $4,~~808~~600 ~~Mcf~~and ~~per~~$24,900 ~~day~~ for the ~~nine~~three months ended ~~September~~March 3031, ~~2015~~2016 ~~from~~and 32015,~~066~~ ~~Mcf per day for the nine months ended September 30~~respectively, ~~2014,~~ a decrease of ~~258~~$20,300 ~~Mcf per day~~ (882%). The ~~overall~~$20,300 decrease in ~~natural~~liquid ~~gas~~revenues ~~production volumes~~ for the ~~nine~~three months ended ~~September~~March 3031, ~~2015~~2016 as compared to the prior year similar period ~~resulted~~was ~~primarily~~attributable ~~from~~to ~~the~~a ~~normal~~$12,000 ~~decline~~decrease ~~inherent~~ in ~~the~~production ~~life~~volumes ofand a ~~well~~$8,300 decrease in liquid prices. Our production volumes were 7 and a13 ~~decrease~~bbls inper ~~the~~day ~~number~~for ofthe ~~producing~~three ~~wells~~months ~~due~~ended toMarch ~~wells~~31, ~~shut-in~~2016 ~~due~~and to2015, respectively, a ~~decline~~decrease inof ~~natural~~6 ~~gas~~bbls ~~prices~~per day (46%).

~~Oil~~Gain ~~Revenues~~on Mark-to-Market Derivatives. WeOn ~~drill~~January ~~wells~~1, ~~primarily~~2015, towe ~~produce~~discontinued ~~natural~~hedge ~~gas,~~accounting ~~rather~~for ~~than~~our ~~oil~~qualified commodity derivatives. As such, ~~but~~subsequent ~~some~~changes ~~wells~~in ~~have~~fair ~~limited~~value ~~oil~~of ~~production.~~these Wederivatives ~~had~~are norecognized ~~oil~~immediately ~~revenue~~within ~~for~~gain ~~the~~on ~~three~~mark-to-market ~~months~~derivatives ~~ended~~on ~~September~~our ~~30,~~statements ~~2015~~of operations. ~~Our~~The ~~oil~~fair ~~revenue~~values ~~was~~of ~~$35,100~~these ~~for~~commodity ~~the~~derivative ~~three~~instruments ~~months~~as ~~ended~~of ~~September~~December 3031, 2014., ~~Our~~which ~~production~~were ~~volumes~~recognized ~~for~~in ~~the~~accumulated ~~three~~other ~~months~~comprehensive ~~ended~~income ~~September~~within 30partners’ capital on our balance sheet, ~~2014~~will ~~was~~be 4reclassified ~~bbls~~to ~~per~~our ~~day.~~statements of operations in the future at the time the originally hedged physical transactions settle.

~~Our~~We ~~oil~~recognized ~~revenues~~gains ~~were~~on mark-to-market derivatives of $1436,~~300~~500 and $4122,~~900~~300, for the ~~nine~~three months ended ~~September~~March 3031, ~~2015~~2016 and ~~2014~~2015, respectively~~, a decrease of $27,600 (66%)~~. ~~The~~These ~~$27,600~~gains ~~decrease~~were indue ~~oil~~to ~~revenues~~mark-to-market ~~for~~gains ~~the~~primarily ~~nine~~related ~~months ended September 30, 2015 as compared~~ to the ~~prior~~change ~~year similar period was attributable to a $11,300 decrease~~ in ~~production~~natural ~~volumes~~gas ~~and a $16,300 decrease in oil~~ prices. ~~Our~~during ~~production volumes decreased to 1.63 bbls per day for~~ the ~~nine months ended September 30, 2015 from 2 bbl per day for the nine months ended September 30, 2014, a decrease of 0~~periods.37 ~~bbl per day (19%).~~

~~Natural~~Costs ~~Gas~~and ~~Liquids Revenue~~Expenses. ~~The~~Production ~~majority~~expenses ofwere ~~our~~$436,100 ~~wells~~and ~~produce “dry gas”~~$598,900 ~~which~~for isthe ~~composed~~three ~~primarily~~months ofended ~~methane~~March ~~and~~31, ~~requires~~2016 ~~no additional processing before being transported~~ and ~~sold to the purchaser. Some wells~~2015, ~~however~~respectively, ~~produce~~a ~~“wet~~decrease ~~gas”, which contains larger amounts~~ of ~~ethane~~$162,800 ~~and other associated hydrocarbons~~ (i27%).e. ~~“natural~~This ~~gas~~decrease ~~liquids”)~~was ~~that~~mostly ~~must~~due ~~be removed prior~~ to ~~transporting~~a ~~the~~decrease ~~gas.~~in ~~Once~~transportation ~~removed,~~costs ~~these~~due ~~natural gas liquids are sold~~ to ~~various~~the ~~purchasers.~~decline ~~Our~~in ~~natural~~revenue ~~gas liquids revenues were $8,100~~ and ~~$42,600~~a ~~for~~decrease ~~the~~in ~~three~~maintenance and ~~nine~~repair ~~months ended September 30, 2015, respectively~~expenses. ~~There was no natural gas liquid revenue for the three and nine months ended September 30, 2014.~~

~~Gain~~Depletion ~~(Loss)~~of ongas ~~Mark-to-Market~~and ~~Derivatives.~~oil Onproperties ~~January~~as 1,a ~~2015,~~percentage weof ~~discontinued~~gas ~~hedge~~and ~~accounting~~oil ~~for~~revenues ~~our~~was ~~qualified~~15% ~~commodity~~and ~~derivatives.~~28% Asfor ~~such,~~the ~~subsequent~~three ~~changes~~months inended ~~fair~~March ~~value~~31, of2016 ~~these~~and ~~derivatives~~2015, ~~are~~respectively. ~~recognized~~This ~~immediately~~change ~~within~~was ~~gain~~primarily ~~(loss)~~attributable ~~on mark-~~to~~-market~~ ~~derivatives~~changes ~~on our statements of operations. The fair values of these commodity derivative instruments as December 31, 2014, which were recognized~~ in ~~accumulated~~gas ~~other~~and ~~comprehensive~~oil ~~income~~reserve ~~within~~quantities ~~partners’~~and ~~capital~~to ona ~~our~~lesser ~~balance~~extent ~~sheet~~revenues, ~~will~~product beprices ~~reclassified~~and toproduction ~~our~~volumes ~~statements~~and ofchanges ~~operations~~ in the ~~future~~depletable atcost ~~the~~basis ~~time~~of ~~the~~gas ~~originally~~and ~~hedged~~oil ~~physical transactions settle~~properties.

WeGeneral ~~recognized~~and aadministrative ~~loss~~expenses ~~on mark-to-market derivatives of $88,300~~ for the three months ended ~~September~~March 3031, ~~2015.~~2016 ~~This~~and ~~loss~~2015 ~~was~~were ~~due~~$37,400 ~~primarily~~and to$46,300, ~~mark-to-market~~respectively, ~~gains~~a indecrease ~~the~~of ~~current~~$8,900 ~~quarter~~(19%). ~~primarily~~These ~~related~~expenses toinclude ~~the~~third-party ~~change~~costs infor ~~natural~~services ~~gas~~as ~~prices~~well ~~during~~as the ~~year.~~monthly ~~There~~administrative ~~were~~fees nocharged ~~gains~~by orour ~~losses~~MGP onand ~~mark-~~vary from period to~~-market~~ ~~derivatives~~period ~~during~~due to the ~~three~~costs ~~months~~charged ~~ended~~to ~~September~~us ~~30,~~and ~~2014~~services provided to us.

We recognized a loss on mark-to-market derivatives of $141,200 for the nine months ended September 30, 2015. This loss was due primarily to mark-to-market gains in the current quarter primarily related to the change in natural gas prices during the year. There were no gains or losses on mark-to-market derivatives during the nine months ended September 30, 2014.

Costs and Expenses. Production expenses were $515,600 and $639,400 for the three months ended September 30, 2015 and 2014, respectively, a decrease of $123,800 (19%). Production expenses were $1,687,100 and $2,016,800 for the nine months ended September 30, 2015 and 2014, respectively, a decrease of $329,700 (16%). The decreases for the three and nine months ended September 30, 2015 were mostly due to lower transportation and water hauling costs due to a decrease in the number of producing wells due to wells shut-in due to a decline in natural gas prices.

Depletion of oil and gas properties as a percentage of oil and gas revenues was 30% and 61% for the three months ended September 30, 2015 and 2014, respectively, and 23% and 40% for the nine months ended September 30, 2015 and 2014, respectively. These percentage changes are directly attributable to changes in revenues, oil and gas reserve quantities, product prices and production volumes and changes in the depletable cost basis of oil and gas properties.

General and administrative expenses for the three months ended September 30, 2015 and 2014 were $41,200 and $45,500, respectively, a decrease of $4,300 (9%). For the nine months ended September 30, 2015 and 2014, these expenses were $131,100 and $132,600, respectively, a decrease of $1,500 (1%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP. The decreases for the three and nine months ended September 30, 2015 are primarily due to third-party costs as compared to the prior year similar period and a decrease in the number of producing wells because of wells shut-in due to a decline in natural gas prices.

Impairment of gas and oil properties for the three and nine months ended September 30, 2015 was $733,600. There were no impairments of gas and oil properties for the three and nine months ended September 30, 2014. Periodically, we compare the carrying value of our proved developed gas and oil producing properties to their estimated fair market value. To the extent our carrying value exceeds the estimated fair market value, an impairment charge is recognized. As a result of this assessment, an impairment charge was recognized for the three and nine months ended September 30, 2015. This charge is based on reserve quantities, future market prices and our carrying value. We cannot provide any assurance that similar charges may or may not be taken in future periods.

Liquidity and Capital Resources

~~Cash~~We ~~provided~~are bygenerally ~~operating~~limited ~~activities decreased $1,444,000 in the nine months ended September 30, 2015~~ to ~~$122,700 as compared to $1,566,700 for~~ the ~~nine~~amount ~~months ended September 30, 2014. This decrease was primarily due to a decrease in net loss before depletion, accretion and impairment~~ of ~~$1,202,600,~~funds agenerated ~~decrease~~by in the ~~change in asset retirement receivable-affiliate of $244,000, a decrease in asset retirement obligations affiliate of $110,800 and a decrease in non-~~cash ~~gain~~flows ~~(loss)~~from onour ~~derivative value of $14~~operations,~~900.~~ ~~The~~which ~~decrease~~we ~~was~~believe ~~partially~~is ~~offset~~adequate byto anfund ~~increase~~future inoperations ~~the change in accounts payable trade-affiliate of $83,400, an increase in asset retirement obligations settled of $28,600,~~ and andistributions ~~increase in accrued liabilities of $16,300 for the nine months ended September 30, 2015 compared~~ to ~~the~~our ~~nine months ended September 30, 2014~~partners.

~~There~~The ~~was~~natural nogas, ~~cash~~oil ~~provided~~and bynatural ~~investing~~gas ~~activities~~liquids ~~for~~commodity ~~the~~price ~~nine~~markets ~~months~~have ~~ended~~suffered ~~September~~significant ~~30,~~declines throughout 2015 and have continued to decline and remain low in 2016. InThe extreme ongoing volatility in the ~~nine~~energy ~~months~~industry ~~ended~~and ~~September~~commodity ~~30,~~prices ~~2014,~~will ~~cash~~likely ~~provided~~continue byto ~~investing~~impact ~~activities~~our ~~was~~outlook. ~~$1,001,200,~~We ~~resulting~~have ~~from~~experienced ~~proceeds~~downward ~~from~~revisions of our natural gas and oil reserves volumes and values due to the ~~sale~~significant ofdeclines ~~miscellaneous~~in ~~tangible~~commodity ~~equipment~~prices. ofOur $1MGP continues to implement various cost saving measures to reduce our operating and general and administrative costs,~~100~~ including renegotiating contracts with contractors, suppliers and ~~the~~service ~~proceeds~~providers, ~~from~~reducing the ~~sale~~number of ~~the~~staff ~~Partnership’s~~and ~~Michigan~~contractors ~~oil~~and deferring and ~~gas~~eliminating ~~properties~~discretionary ofcosts. Our $1MGP will continue to be opportunistic and aggressive in managing our cost structure and,~~003~~ in turn,~~800~~ liquidity to meet our operating needs. To the extent commodity prices remain low or decline further, ~~partially~~or ~~offset~~we byexperience aother ~~purchase~~disruptions ofin ~~tangible~~the ~~equipment~~industry, ofour $3ability to fund our operations and make distributions may be further impacted,~~700.~~ and could result in the MGP’s decision to liquidate our operations.

~~Cash~~Historically, ~~used~~there inhas ~~financing~~been ~~activities~~no ~~decreased~~need ~~$2,708,600~~to ~~during~~borrow funds from the ~~nine~~MGP ~~months~~to ~~ended~~fund ~~September~~operations 30as the cash flow from our operations has been adequate to fund our obligations and distributions to our partners. However, ~~2015~~the recent significant declines in commodity prices have challenged our ability to ~~$167~~fund our operations and may make it uneconomical to produce our wells until they are depleted as we originally intended. Accordingly,~~600~~ ~~from~~the $2MGP determined that there is substantial doubt about our ability to continue as a going concern. The MGP intends,~~876~~ as necessary,~~200~~ to continue our operations and to fund our obligations for at least the ~~nine~~next twelve months. ~~ended~~The ~~September~~MGP ~~30,~~has ~~2014.~~concluded ~~This~~that ~~decrease~~such ~~was~~undertaking ~~due~~is sufficient to alleviate the doubt as to our ability to continue as a ~~decrease~~going concern. To the extent commodity prices remain low or decline further, ARP experiences disruptions in ~~cash~~the ~~distributions~~financial markets impacting its respective longer-term access to ~~partners~~or cost of capital, or ARP experiences any of the other impacts to its liquidity discussed below, the MGP’s ability to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months, as necessary, may be impacted.

Our MGP may withhold funds for future plugging and abandonment costs. Through September 30, 2015, our MGP has withheld $163,400 of funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow at any one time may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties. 16

WeARP’s ~~are~~revolving ~~generally~~credit ~~limited~~facility tois currently in the ~~amount~~process of ~~funds~~its ~~generated~~semi-annual byredetermination. ~~the~~Based ~~cash~~on ~~flows~~projected ~~from~~market ~~our operations~~conditions, ~~which~~continued wedeclines ~~believe~~in iscommodity ~~adequate~~prices ~~to fund future operations~~ and ~~distributions~~recent toconversations ~~our~~with ~~partners.~~its ~~Historically~~administrative agent, ~~there~~ARP ~~has~~expects ~~been~~that noits ~~need~~borrowing tobase ~~borrow~~will ~~funds~~be ~~from~~redetermined ~~our MGP~~ to ~~fund~~a ~~operations.~~level ~~However,~~below ~~recent~~its ~~declines~~outstanding inborrowings ~~commodity~~as ~~prices~~of ~~may~~March ~~challenge~~31, ~~the~~2016. If ~~Partnership~~ARP’s ~~ability~~borrowing tobase ~~pay~~is ~~its~~redetermined ~~obligations~~below asits ~~they~~current ~~become~~outstanding ~~due~~borrowings and ~~its~~ARP ~~intention~~is unable to ~~produce~~repay ~~its~~the ~~wells~~deficiency ~~until~~or ~~they~~deposit ~~are~~additional ~~depleted~~collateral to eliminate such deficiency, asor ~~they~~if ~~may~~ARP ~~become~~experiences ~~uneconomical~~any toother ~~produce.~~event ~~Accordingly,~~of ~~the~~default ~~MGP~~on ~~determined~~its ~~that~~debt ~~there~~obligations, isor ~~substantial~~if ~~doubt~~other ~~about~~debt ~~the~~agreements ~~Partnership’s~~cross-default, ~~ability~~and tothe ~~continue~~lenders asaccelerate athe ~~going~~maturity ~~concern.~~of ~~The~~any ~~MGP~~other ~~has~~outstanding ~~planned~~debts, asthe ~~necessary~~MGP, may not have sufficient liquidity to continue the Partnership’s operations and to fund the Partnership’s ~~operations~~obligations, ~~for~~and atas ~~least~~a ~~the~~result, ~~next~~there 12would ~~months.~~be ~~The~~substantial ~~MGP has concluded that such undertaking is sufficient to alleviate the~~ doubt asregarding to the Partnership’s ability to continue as a going concern.

Cash provided by operating activities decreased $33,900 in the three months ended March 31, 2016 to zero as compared to $33,900 for the three months ended March 31, 2015. This decrease was primarily due to a decrease in net earnings before depletion and accretion of $293,900 and a decrease in asset retirement obligations settled of $700. The decrease was partially offset by an increase in the change in asset retirement receivable-affiliate of $76,100, the change in accounts receivable trade-affiliate of $65,500, the change in accounts payable trade-affiliate of $65,300, the change in non-cash gain (loss) on derivative value of $51,100, and an increase in accrued liabilities of $2,700 for the three months ended March 31, 2016 compared to the three months ended March 31, 201

Cash used in financing activities decreased $41,600 during the three months ended March 31, 2016 to zero from $41,600 for the three months ended March 31, 2015. This decrease was due to a decrease in cash distributions to partners.

Our MGP may withhold funds for future plugging and abandonment costs. Through March 31, 2016, our MGP has withheld $201,100 of funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow at any one time may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

Critical Accounting Policies

~~The~~For ~~discussion~~a ~~and~~more ~~analysis~~complete ofdiscussion ~~our financial condition and results~~ of ~~operations~~the isaccounting ~~based~~policies upon our financial statements, which have been prepared in accordance with U.S. GAAP. On an on-going basis, we evaluate our estimates, including those related to our asset retirement obligations, depletion and ~~certain accrued receivables and liabilities. We base our~~ estimates ~~on historical experience and on various other assumptions~~ that we believe reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. A discussion of significant accounting policies we have ~~adopted~~identified ~~and~~as ~~followed~~critical in the preparation of our condensed consolidated financial statements, isplease ~~included~~refer ~~within “Notes~~ to ~~Financial~~our ~~Statements”~~Management’s inDiscussion ~~Part~~and I,Analysis ~~Item 1,~~of “Financial ~~Statements”~~Condition inand ~~this~~Results ~~quarterly~~of ~~report~~Operations ~~and~~ in our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2014~~2015.

ITEM 4.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of ~~September~~March 3031, ~~2015~~2016, our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There have been no changes in the Partnership’s internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

2318

ITEM 6.

EXHIBITS

EXHIBIT INDEX

Exhibit No.		Description
4(a)		Amended and Restated Certificate and Agreement of Limited Partnership for Atlas Resources Public #18-2008 (A) L.P.(1)
4.2		Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #18-2008 L.P. (A) (1)
10.1		Drilling and Operating Agreement for Atlas Resources Public #18-2008 (A) L.P. (1)
31.1		Certification Pursuant to Rule 13a-14/15(d)-14
31.1		Rule 13a-14/15(d)-14 (a) Certification
31.2		Certification Pursuant to Rule 13a-14/15(d)-14
31.2		Rule 13a-14/15(d)-14 (a) Certification
32.1		Section 1350 Certification
32.2		Section 1350 Certification
101		Interactive Data File

(1) Filed on October 15, 2008 in the Form S-~~1/A~~1A Registration Statement dated October 15, 2008, File No. 333-150925-03

2419

SIGNATURES

Pursuant to the requirements of the Securities of the Exchange Act of 1934, ~~this~~the ~~report~~registrant has ~~been~~duly ~~signed~~caused ~~below~~this byreport ~~the~~to ~~following~~be ~~person~~signed on its behalf ofby the ~~registrant~~undersigned, ~~and~~thereunto induly ~~the capacities and on the dates indicated~~authorized.

	ATLAS RESOURCES PUBLIC #18-2008 (A) L.P.	~~ATLAS RESOURCES PUBLIC #18-2008 (A) L.P.~~
		By: ATLAS RESOURCES, LLC, General Partner
	By:		Atlas Resources, LLC, its
Date: November 23, 2015		By:/s/ FREDDIE M. KOTEK
			Managing General Partner
		Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President
Date: May 23, 2016	By:		/s/ FREDDIE M. KOTEK
Date: November 23, 2015		By:/s/ JEFFREY M. SLOTTERBACK
			Freddie M. Kotek, Chief Executive Officer and President of the Managing General Partner
		Jeffrey M. Slotterback, Chief Financial Officer

Date: May 23, 2016

By:

/s/ JEFFREY M. SLOTTERBACK

Jeffrey M. Slotterback

Chief Financial Officer of the

Managing General Partner

Filing Compare · Atlas Resources Public #18-2008 (A) L.P.