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 ~~March~~June 3130, 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 March 31, 2016 and December 31, 2015	3
	Condensed Balance Sheets as of June 30, 2016 and December 31, 2015	3
	Condensed Statements of Operations for the Three Months ended March 31, 2016 and 2015	4
	Condensed Statements of Operations for the Three and Six Months ended June 30, 2016 and 2015	4
	Condensed Statements of Comprehensive Loss for the Three Months ended March 31, 2016 and 2015	5
	Condensed Statements of Comprehensive Loss for the Three and Six Months ended June 30, 2016 and 2015	5
	Condensed Statement of Changes in Partners’ Deficit for the Three Months ended March 31, 2016	6
	Condensed Statement of Changes in Partners’ Deficit for the Six Months ended June 30, 2016	6
	Condensed Statements of Cash Flows for the Three Months ended March 31, 2016 and 2015	7
	Condensed Statements of Cash Flows for the Six Months ended June 30, 2016 and 2015	7
	Notes to Condensed Financial Statements	8
Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
Item 4:	Controls and Procedures	1719
PART II.	OTHER INFORMATION
Item 1:	Legal Proceedings	1819
Item 6:	Exhibits	1920
SIGNATURES		2021
CERTIFICATIONS

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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

CONDENSED BALANCE SHEETS

(Unaudited)

	March 31,2016			December 31,2015
	June 30,2016			December 31,2015
ASSETS
Current assets:
Cash	$	-		$	-
Account receivable trade-affiliate		~~178~~179,~~700~~300			256,900
Current portion of derivative assets		~~200~~80,~~800~~200			241,600
Total current assets		~~379~~259,500			498,500
Gas and oil properties, net		2,~~611~~579,~~900~~200			2,651,600
Long-term asset retirement receivable-affiliate		~~201~~306,100			201,800
Total assets	$	3,~~192~~144,~~500~~800		$	3,351,900
LIABILITIES AND PARTNERS’ DEFICIT
Current liabilities:
Accounts payable trade-affiliate	$	~~759~~1,~~400~~031,100		$	694,100
Accrued liabilities		3128,~~800~~200			25,500
Put premiums payable-affiliate		2917,~~600~~400			43,600
Total current liabilities		~~820~~1,~~800~~076,700			763,200
Asset retirement obligations		4,~~084~~125,~~300~~400			4,043,900
Commitments and contingencies (Note 6)
Partners’ deficit:
Managing general partner’s deficit		(1,~~498~~574,~~900~~700)	)		(1,426,300	)
Limited partners’ deficit (20,152.50 units)		(~~216~~484,~~700~~500)	)		(32,900	)
Accumulated other comprehensive income		31,~~000~~900			4,000
Total partners’ deficit		(12,~~712~~057,~~600~~300)	)		(1,455,200	)
Total liabilities and partners’ deficit	$	3,~~192~~144,~~500~~800		$	3,351,900

See accompanying notes to condensed financial statements.

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

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

		Three Months Ended
	Three Months EndedJune 30,								Six Months EndedJune 30,
		March 31,
		2016				2015				2016		2015
			2016			2015
REVENUES
REVENUES
Natural gas, oil and liquids	$	262,100			$	348,600			$	523,500	$	1,089,800
Natural gas, oil and liquids		$	261,400			$	741,200
(Loss) gain on mark-to-market derivatives		(43,100)				30,600				(6,600)		52,900
Gain on mark-to-market derivatives			36,500				22,300
Total revenues		219,000				379,200				516,900		1,142,700
Total revenues			297,900				763,500
COSTS AND EXPENSES
COSTS AND EXPENSES
Production		448,700				572,600				884,800		1,171,500
Production			436,100				598,900
Depletion		32,700				23,200				72,400		227,200
Depletion			39,700				204,000
Accretion of asset retirement obligations		41,100				62,600				82,200		125,200
Accretion of asset retirement obligations			41,100				62,600
General and administrative		40,100				43,600				77,500		89,900
General and administrative			37,400				46,300
Total costs and expenses		562,600				702,000				1,116,900		1,613,800
Total costs and expenses			554,300				911,800
Net loss	$	(343,600)			$	(322,800	)		$	(600,000)	$	(471,100	)
Net loss		$	(256,400	)		$	(148,300	)
Allocation of net loss:
Allocation of net loss:
Managing general partner	$	(75,800)			$	(81,100	)		$	(148,400)	$	(108,200	)
Managing general partner		$	(72,600	)		$	(27,100	)
Limited partners	$	(267,800)			$	(241,700	)		$	(451,600)	$	(362,900	)
Limited partners		$	(183,800	)		$	(121,200	)
Net loss per limited partnership unit	$	(13)			$	(12	)		$	(22)	$	(18	)
Net loss per limited partnership unit		$	(9	)		$	(6	)

See accompanying notes to condensed financial statements.

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

CONDENSED STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)

		Three Months Ended
	Three Months EndedJune 30,								Six Months EndedJune 30,
		March 31,
		2016				2015				2016		2015
		2016				2015
Net loss	$	(343,600)			$	(322,800	)		$	(600,000)	$	(471,100	)
Net loss		$	(256,400	)		$	(148,300	)
Other comprehensive loss:
Other comprehensive loss:
Difference in estimated hedge receivable		-				(53,900	)			-		(21,900	)
Difference in estimated hedge receivable			-				32,000
Reclassification adjustment to net loss of mark-to-market (losses) gains on cash flow hedges		(1,100)				50,600				(2,100)		15,600
Reclassification adjustment to net loss of mark-to-market gains on cash flow hedges			(1,000	)			(35,000	)
Total other comprehensive loss		(1,100)				(3,300	)			(2,100)		(6,300	)
Total other comprehensive loss			(1,000	)			(3,000	)
Comprehensive loss	$	(344,700)			$	(326,100	)		$	(602,100)	$	(477,400	)
Comprehensive loss		$	(257,400	)		$	(151,300	)

See accompanying notes to condensed financial statements.

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

CONDENSED STATEMENT OF CHANGES IN PARTNERS’ DEFICIT

FOR THE ~~THREE~~SIX MONTHS ENDED

~~March~~June 3130, 2016

(Unaudited)

	ManagingGeneralPartner			LimitedPartners			Accumulated OtherComprehensiveIncome (Loss)			Total
Balance at December 31, 2015	$	(1,426,300	)	$	(32,900	)	$	4,000		$	(1,455,200	)
Participation in revenues, costs and expenses:
Net production expenses		(4797,~~100~~200)	)		(~~127~~264,~~600~~100)	)		-			(~~174~~361,~~700~~300)	)
Gain on mark-to-market derivatives		-			36,500			-			36,500
Loss on mark-to-market derivatives		-			(6,600)			-			(6,600)
Depletion		(37,~~800~~000)	)		(3565,~~900~~400)	)		-			(3972,~~700~~400)	)
Accretion of asset retirement obligations		(1122,~~400~~700)	)		(2959,~~700~~500)	)		-			(4182,~~100~~200)	)
General and administrative		(1021,~~300~~500)	)		(2756,~~100~~000)	)		-			(3777,~~400~~500)	)
Net loss		(72148,~~600~~400)	)		(~~183~~451,~~800~~600)	)		-			(~~256~~600,~~400~~000)	)
Other comprehensive loss		-			-			(12,~~000~~100)	)		(12,~~000~~100)	)
Balance at March 31, 2016	$	(1,498,900	)	$	(216,700	)	$	3,000		$	(1,712,600	)
Balance at June 30, 2016	$	(1,574,700)		$	(484,500)		$	1,900		$	(2,057,300)

See accompanying notes to condensed financial statements.

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

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended
	Six months Ended
	March 31,
	June 30,
	2016			2015
Cash flows from operating activities:
Net loss	$	(~~256~~600,~~400~~000)	)	$	(~~148~~471,~~300~~100	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		3972,~~700~~400			~~204~~227,~~000~~200
Non cash loss (gain) on derivative value		25,800			(25,300	)
Non cash loss on derivative value		133,100			66,400
Accretion of asset retirement obligations		4182,~~100~~200			62125,~~600~~200
Asset retirement obligations settled		(700)	)		-
Changes in operating assets and liabilities:
Decrease in accounts receivable trade-affiliate		7877,~~200~~600			12269,~~700~~100
Decrease (increase) in asset retirement receivable-affiliate		700			(75,400	)
Increase in asset retirement receivable-affiliate		(104,300)			(98,100	)
Increase in accounts payable trade-affiliate		65337,~~300~~000			-
Increase in accrued liabilities		6,300			3,600
Increase (decrease) in accrued liabilities		2,700			(2,400	)
Net cash provided by operating activities		-			33116,~~900~~300
Cash flows from investing activities:
Net cash used in investing activities		-			-
Cash flows from financing activities:
Distributions to partners		-			(41144,~~600~~300)	)
Net cash used in financing activities		-			(41144,~~600~~300)	)
Net change in cash		-			(728,~~700~~000)	)
Cash at beginning of period		-			44,900
Cash at end of period	$	-		$	3716,~~200~~900

See accompanying notes to condensed financial statements.

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

NOTES TO CONDENSED FINANCIAL STATEMENTS

~~March~~June 3130, 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~~OTC: ~~ARP~~ARPJ). Unless the context otherwise requires, references to “the Partnership,” “we,” “us” and “our”, refer to Atlas Resources Public #18-2008 (A) L.P.

Atlas Energy Group, LLC (“Atlas Energy Group”; ~~OTCQX~~OTC: ATLS) manages 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, for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas, oil and NGL. Produced natural gas, oil and 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 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 and six months ended June 30, 2016 may not necessarily be indicative of the results of operations for the year ended December 31, 2016.

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

Liquidity and Capital Resources

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. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted the Partnership’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on the Partnership’s liquidity position. In addition, the Partnership has experienced significant downward revisions of its natural gas and oil reserves volumes and values due to the 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 strategic 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.

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~~Historically, ~~condensed~~there ~~financial~~has ~~statements,~~been ~~which~~no ~~are~~need ~~unaudited,~~to ~~except~~borrow ~~for~~funds from the ~~balance~~MGP ~~sheet~~to atfund ~~December~~operations ~~31,~~as ~~2015,~~the ~~which~~cash isflow ~~derived~~ from ~~audited~~the ~~financial~~Partnership’s ~~statements,~~operations have been ~~prepared~~adequate ~~pursuant~~ to ~~the~~fund ~~rules~~its obligations and ~~regulations~~distributions ofto ~~the~~its ~~Securities~~partners. ~~and~~However, ~~Exchange~~the ~~Commission~~recent ~~and~~significant ~~accounting~~declines ~~principles generally accepted~~ in ~~the~~commodity ~~United~~prices ~~States~~have ofchallenged ~~America~~the ~~(“U.S.~~Partnership’s ~~GAAP”)~~ability ~~for~~to ~~interim~~fund ~~reporting.~~its ~~Certain~~operations ~~information~~ and ~~note~~may ~~disclosures~~make ~~normally~~it ~~included~~uneconomical infor ~~annual~~the ~~financial~~Partnership ~~statements~~to ~~prepared~~produce inits ~~accordance~~wells ~~with~~until ~~U.S.~~they ~~GAAP~~are ~~have~~depleted ~~been~~as ~~condensed~~the orPartnership ~~omitted~~originally ~~pursuant~~intended. toAccordingly, ~~those~~the ~~rules~~MGP ~~and~~determined ~~regulations,~~that ~~although~~there weis ~~believe~~substantial ~~that~~doubt about the ~~disclosures~~Partnership’s ~~made~~ability ~~are adequate~~ to ~~make~~continue ~~the~~as ~~information~~a ~~not~~going ~~misleading~~concern. ~~These~~ ~~interim~~The ~~financial~~MGP ~~statements~~intends, ~~should~~as benecessary, ~~read~~to incontinue ~~conjunction with~~ the ~~audited~~Partnership’s ~~financial~~operations ~~statements~~ and ~~notes~~to ~~thereto~~fund ~~presented in~~ the Partnership’s ~~Annual~~obligations ~~Report~~for onat ~~Form~~least ~~10-K~~the ~~for~~next twelve months. To the ~~year~~extent ~~ended~~commodity ~~December~~prices ~~31,~~remain ~~2015.~~low ~~The~~or ~~results~~decline offurther ~~operations~~or ~~for~~ARP ~~the~~is ~~three~~unsuccessful ~~months~~in ~~ended~~completing ~~March~~its ~~31,~~Restructuring ~~2016~~(as ~~may~~defined ~~not~~below) ~~necessarily~~or bethe ~~indicative~~Plan of(as defined below), the ~~results~~MGP’s ofability ~~operations~~to ~~for~~continue the ~~year~~Partnership’s ~~ended~~operations ~~December 31,~~may ~~2016~~be further impacted.

ARP Restructuring and Chapter 11 Bankruptcy Proceedings

On July 25, 2016, ARP and certain of its subsidiaries, including the MGP, and Atlas Energy Group, solely with respect to certain sections thereof, entered into a restructuring support agreement with ARP’s lenders (the “Restructuring Support Agreement”) to support ARP’s restructuring that will reduce debt on its balance sheet (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”). The Plan will position ARP for the future and is expected to be completed before the end of the third quarter of 2016, after which ARP should emerge from Chapter 11 (as defined below), backed by its stakeholders, committed to investing capital to develop its exploration and production assets, as well as its tax-advantaged drilling partnership program.

On July 27, 2016, ARP and certain of its subsidiaries, including the MGP, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”). The cases commenced thereby are being jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.” Interested parties should refer to the information and the limitations and qualifications discussed in the disclosure statement related to the Restructuring which was filed as Exhibit 99.1 to ARP’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 25, 2016.

The MGP intends to continue to operate the Partnership’s businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, it is contemplated that all suppliers, vendors, employees, royalty owners, trade partners and landlords will be unimpaired and will be satisfied in full in the ordinary course of business, and the MGP’s existing trade contracts and terms will be maintained. To assure ordinary course operations, the MGP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to the Partnership, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.

The Partnership is not a party to the Restructuring Support Agreement. The ARP Restructuring is not expected to materially impact the MGP or its ability to perform as the managing general partner and operator of the Partnership’s operations. On July 26, 2016, the MGP adopted certain amendments to our partnership agreement, in accordance with the MGP’s ability to amend our partnership agreement to cure an ambiguity in or correct or supplement any provision of our partnership agreement as may be inconsistent with any other provision, to provide that bankruptcy and insolvency events, such as the MGP’s Chapter 11 filing, with respect to the managing general partner will not cause the managing general partner to cease to serve as the managing general partner of the Partnership nor cause the termination of the Partnership.

Atlas Energy Group is not a party to the ARP Restructuring. Atlas Energy Group remains controlled by the same ownership group and management team and thus, the ARP Restructuring is not expected to have a material impact on the ability of Atlas Energy Group management to operate ARP or the other Atlas Energy Group businesses.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the Partnership’s condensed 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 condensed financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s condensed financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, impairments, fair value of derivative instruments and the probability of forecasted transactions. 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. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions 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 months ended March 31, 2016 and 2015 represent actual results in all material respects.

Gas and Oil Properties

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

	March 31,			December 31,
	June 30,			December 31,
	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		(212,~~489~~522,~~400~~100	)		(212,449,700	)
Gas and oil properties, net	$	2,~~611~~579,~~900~~200		$	2,651,600

As a result of the recent significant declines in commodity prices and associated recorded impairment charges, the remaining net book value of gas and oil properties on our condensed balance ~~sheet~~sheets at ~~March~~June 3130, 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.

Recently Issued Accounting Standards

In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management 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 and provide footnote disclosures, if necessary. The updated guidance is effective as of January 1, 2017 and the Partnership is currently in the process of determining the impact of providing the enhanced disclosures, as applicable, within its condensed financial statements.

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. The Partnership is currently in the process of determining the impact that the updated accounting guidance will have on its condensed financial statements and its method of adoption.

NOTE 3 - DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally put contracts and swaps, in connection with the Partnership’s commodity price risk management activities. The Partnership does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized in earnings.

The Partnership 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 New York Mercantile Stock Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures 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 Partnership reflected net derivative assets on its balance sheets of $200,800 and $241,600 at March 31, 2016 and December 31, 2015, respectively.

The ~~following~~Partnership ~~table~~reflected ~~summarizes~~net ~~the~~derivative ~~gains~~assets oron ~~losses~~its ~~recognized~~condensed ~~within~~balance ~~the~~sheets ~~statements~~ of ~~operations~~$80,200 ~~for~~and ~~derivative~~$241,600 ~~instruments~~at ~~previously~~June ~~designated~~30, as2016 ~~cash~~and ~~flow~~December ~~hedges~~31, ~~for~~2015, ~~the~~respectively. ~~periods indicated:~~

	Three Months Ended
	March 31,
	2016		2015
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 following table summarizes the commodity derivative activity and presentation in the condensed statements of operations for the periods indicated:

At March 31, 2016, the Partnership had the following commodity derivatives:

	Three Months Ended June 30,					Six Months Ended June 30,
		2016		2015			2016		2015
Gains reclassified from accumulated other comprehensive income into natural gas and oil revenues	$	1,100	$	(50,600	)	$	2,100	$	(15,600	)
(Losses) gains subsequent to hedge accounting recognized in (loss) gain on mark-to-market derivatives	$	(43,100)	$	30,600		$	(6,600)	$	52,900

At June 30, 2016, the Partnership had the following commodity derivatives:

Natural Gas Fixed Price Swaps - Limited Partners

ProductionPeriod EndingDecember 31,

Volumes(3)

AverageFixed Price

Fair ValueAsset (2)

(MMBtu)(1)

(per MMBtu)(1)

2016

5637,~~700~~800

4.46

~~126~~54,~~600~~500

Natural Gas Put Options - Limited Partners

ProductionPeriod EndingDecember 31,

Volumes(3)

AverageFixed Price

Fair ValueAsset (2)

(MMBtu)(1)

(per MMBtu)(1)

2016

3822,~~500~~700

4.15

7425,~~200~~700

Limited Partner’s Commodity Derivatives, net

~~200~~80,~~800~~200

(1)

“MMBtu” represents million British Thermal Units.

(2)

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

At(3) March 31, 2016, 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 the MGP’s revolving credit facility, the Partnership is required to utilize this secured hedge facility for future commodity risk management activity. The ~~Partnership’s~~production ~~obligations~~volume 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 the MGP. The MGP administers the commodity price risk management activity for ~~the~~2016 ~~Partnership~~include ~~under~~ the ~~secured~~remaining ~~hedge~~six ~~facility.~~months 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~~2016 orbeginning ~~substantially~~July ~~all of its assets. As of March 31~~1, 2016~~, only the Partnership’s natural gas swaps are included in the secured hedge facility~~.

AsAt June 30, 2016, the ~~underlying~~MGP ~~prices~~had ~~and~~a ~~terms~~secured inhedge facility agreement with a syndicate of banks under which the Partnership’s has the ability to enter into derivative contracts ~~were~~to ~~consistent~~manage ~~with~~its exposure to commodity price movements. Under the ~~indices~~MGP’s ~~used~~revolving credit facility, the Partnership is required to ~~sell~~utilize ~~its~~this ~~natural~~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 the MGP. 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, ~~there~~grant ~~were~~liens, nomake ~~gains~~loans or ~~losses~~investments, ~~recognized~~make ~~during~~distributions if a default under the ~~three~~secured ~~months~~hedge ~~ended~~facility ~~March~~agreement 31exists 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 June 30, 2016, ~~and~~only ~~2015~~the ~~for~~Partnership’s natural gas swaps are included in the secured hedge ~~ineffectiveness~~facility.

An event of default occurred under the secured hedging facility agreement upon the MGP’s filing of voluntary petitions for relief under Chapter 11. The lenders under the secured hedge facility agreed to forbear from exercising remedies in respect of such event of default while the Chapter 11 filings are pending and, upon occurrence of the effective date of the Plan contemplated by the Restructuring Support Agreement, such event of default will no longer be deemed to exist or to continue under the secured hedge facility.

~~Accumulated~~In ~~Other~~addition, ~~Comprehensive~~it ~~Income~~will be an event of default under the MGP’s revolving credit facility if the MGP breaches an obligation governed by the secured hedge facility, and the effect of such breach is to cause amounts owing under swap agreements governed by the secured hedge facility to become immediately due and payable.

As ~~a result of~~ the ~~put~~underlying ~~options,~~prices ~~swaps~~ and ~~the~~terms ~~unrealized gains recognized~~ in ~~income~~the inPartnership’s ~~prior~~derivative ~~periods~~contracts ~~due~~were toconsistent ~~natural~~with ~~gas and oil property impairments,~~ the ~~Partnership~~indices ~~recorded~~used ato ~~net~~sell ~~deferred gain on~~ its ~~balance~~natural ~~sheet~~gas inand ~~accumulated other comprehensive income of $3~~oil,~~000~~ asthere ofwere ~~March~~no ~~31, 2016. Included in accumulated other comprehensive income are unrealized~~ gains ofor ~~$57,700,~~losses ~~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 and six months ended ~~March~~June 3130, 2016, ~~$4,700 of net losses were recorded by the Partnership~~ and ~~allocated~~2015 ~~only~~for tohedge ~~the limited partners~~ineffectiveness. 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.

NOTE 4 - FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership uses a market approach fair value methodology to value ~~the assets and liabilities for~~ its outstanding derivative contracts. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. The Partnership separates the fair 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~~June 3130, 2016 and December 31, 2015, all derivative financial instruments were classified as Level 2.

Information for assets measured at fair value at ~~March~~June 3130, 2016 and December 31, 2015 was as follows:

Level 1

Level 2

Level 3

Total

As of March 31, 2016

As of June 30, 2016

Derivative assets, gross

Commodity swaps

~~126~~54,~~600~~500

Commodity puts

7425,~~200~~700

Total derivative assets, gross

~~200~~80,~~800~~200

	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

NOTE 5 - 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 condensed statements of operations, are payable at $75 per well per month. Monthly well supervision fees, which are included in production expense in the Partnership’s condensed 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 condensed 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 condensed 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 EndedMarch 31,
	Three Months EndedJune 30,						Six Months EndedJune 30,
		2016			2015			2016		2015
Administrative fees	$	$24,800	~~22,400~~	$	$26,000	~~29,300~~	$	47,200	$	55,300
Supervision fees		208,800	~~198,800~~		226,600	~~245,600~~		407,600		472,200
Transportation fees		50,900	~~50,000~~		45,500	~~96,600~~		100,900		142,100
Direct costs		204,300	~~202,300~~		318,100	~~273,700~~		406,600		591,800
Total	$	$488,800	~~473,500~~	$	$616,200	~~645,200~~	$	962,300	$	1,261,400

The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts payable trade-affiliate on the Partnership’s condensed balance sheets includes the net production expenses due to the MGP.

NOTE 6 - COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, 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. 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 ~~March~~June 3130, 2016, the MGP has withheld $~~201~~306,100 of net production revenue for future plugging and abandonment costs.

Legal Proceedings

The Partnership isand aaffiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising out of the ordinary course of its business. Management ~~believes~~and the MGP’s management believe that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s or the MGP’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. 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~~OTCQX: ~~ARP~~ARPJ). Unless the context otherwise requires, references to “the Partnership,” “we,” “us” and “our”, refer to Atlas Resources Public #18-2008 (A) L.P.

Atlas Energy Group, LLC (“Atlas Energy Group”) manages 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, 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.

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 ~~March~~June 3130, 2016, our MGP has withheld $~~201~~306,100 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 2016 and 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.

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 Ended
	Three Months EndedJune 30,								Six Months EndedJune 30,
		March 31,
		2016				2015				2016			2015
		2016				2015
Production revenues (in thousands):
Production revenues (in thousands):
Gas	$	262			$	336			$	517		$	1,041
Gas		$	255			$	705
Oil		-				3				3			14
Oil			2				11
Liquid gas		-				9				3			34
Liquid gas			4				25
Total	$	262			$	348			$	523		$	1,089
Total		$	261			$	741
Production volumes:
Production volumes:
Gas (mcf/day) (1)		1,806				2,524				1,857			2,789
Gas (mcf/day) (1)			1,898				3,056
Oil (bbl/day) (1)		-				1				-			2
Oil (bbl/day) (1)			1				3
Liquid (bbls/day) (1)		-				7				3			10
Liquid (bbls/day) (1)			7				13
Total (mcfe/day) (1)		1,806				2,572				1,875			2,861
Total (mcfe/day) (1)			1,946				3,152
Average sales prices: (2)
Average sales prices (2)
Gas (per mcf) (1) (3)	$	1.73			$	1.73			$	1.65		$	2.30
Gas (per mcf) (1) (3)		$	1.58			$	2.77
Oil (per bbl) (1)	$	31.77			$	43.01			$	32.25		$	44.15
Oil (per bbl) (1)		$	32.48			$	44.42
Liquids (per bbl) (1)	$	-			$	15.57			$	5.90		$	19.45
Liquids (per bbl) (1)		$	7.64			$	0.94
Production costs:
Production costs:
As a percent of revenues		171	%			169	%			169	%		107	%
As a percent of revenues			167	%			81	%
Per mcfe (1)	$	2.73			$	7.07			$	2.59		$	2.26
Per mcfe (1)		$	2.47			$	2.11
Depletion per mcfe	$	0.20			$	0.29			$	0.21		$	0.44
Depletion per mcfe		$	0.22			$	0.65

(1)	“Mcf” represents thousand cubic feet, “mcfe” represents thousand cubic feet equivalent, and “bbl” represents barrels. Bbl is converted to mcfe using the ratio of six 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 for the three months ended June 30, 2016 and 2015 were $1821,~~200~~400 and $5761,~~900~~500, respectively. Previously recognized derivative gains for the ~~three~~six months ended ~~March~~June 3130, 2016 and 2015, were $39,600 and $119,400, respectively.

Natural Gas Revenues. Our natural gas revenues were $~~254~~261,~~900~~200 and $~~704~~336,~~700~~400 for the three months ended ~~March~~June 3130, 2016 and 2015, respectively, a decrease of $~~449~~75,~~800~~200 (6422%). The $~~449~~75,~~800~~200 decrease in natural gas revenues for the three months ended ~~March~~June 3130, 2016 as compared to the prior year similar period was attributable to a $~~262~~146,~~100~~800 decrease in production volumes, ~~and~~partially offset by a $~~187~~71,~~700~~600 ~~decrease~~increase in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions. Our production volumes decreased to 1,~~898~~806 mcf per day for the three months ended ~~March~~June 3130, 2016 from 32,~~056~~524 mcf per day for the three months ended ~~March~~June 3130, 2015, a decrease of ~~1,158~~718 mcf per day (3840%). The overall decrease in natural gas production volumes for the three months ended ~~March~~June 3130, 2016 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 ~~addition~~the tonumber ~~well~~of ~~shut-in~~producing wells due to itwells ~~being~~shut-in ~~uneconomical~~due to ~~continue~~a ~~production~~decline in ~~the~~natural ~~current~~gas ~~pricing environment~~prices.

~~Oil~~Our ~~Revenues. We drilled wells primarily to produce~~ natural gas, ~~rather than oil, but some wells have limited oil production. Our oil~~ revenues were $1518,~~900~~000 and $111,~~600~~041,000 for the ~~three~~six months ended ~~March~~June 3130, 2016 and 2015, respectively, a decrease of $9523,~~700~~000 (8450%). The $9523,~~700~~000 decrease in ~~oil~~natural gas revenues for the ~~three~~six months ended ~~March~~June 3130, 2016 as compared to the prior year similar period was attributable to a $9178,~~000~~900 decrease in ~~production~~our ~~volumes~~natural gas sales prices after the effect of financial hedges, which were driven by market conditions, and a $~~700~~344,100 decrease in ~~oil~~production ~~prices~~volumes. Our production volumes decreased to 1,857 ~~bbl~~mcf per day for the ~~three~~six months ended ~~March~~June 3130, 2016 from 32,789 ~~bbls~~mcf per day for the ~~three~~six months ended ~~March 31~~June 30, 2015, a decrease of 2932 ~~bbls~~mcf per day (6733%). The overall decrease in natural gas production volumes for the six months ended June 30, 2016 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.

~~Natural~~Oil ~~Gas Liquids Revenue~~Revenues. ~~The~~We ~~majority~~drill ~~of our~~ wells ~~produce “dry gas”, which is composed~~ primarily ~~of methane and requires no additional processing before being transported and sold~~ to ~~the purchaser. Some wells, however,~~ produce ~~“wet~~natural gas”, ~~which~~rather ~~contains~~than ~~larger amounts of ethane and other associated hydrocarbons (i.e. “natural gas liquids”) that must be removed prior to transporting the gas. Once removed~~oil, ~~these~~but ~~natural~~some ~~gas~~wells ~~liquids~~have ~~are~~limited ~~sold~~oil ~~to various purchasers~~production. Our ~~natural~~oil ~~gas liquids~~ revenues were $~~4,600~~900 and $242,~~900~~700 for the three months ended ~~March~~June 3130, 2016 and 2015, respectively, a decrease of $201,~~300~~800 (8267%). The $201,~~300~~800 decrease in ~~liquid~~oil revenues for the three months ended ~~March~~June 3130, 2016 as compared to the prior year similar period was attributable to a $121,~~000~~500 decrease in production volumes, and a $8,300 decrease in ~~liquid~~oil prices. Our production volumes ~~were~~decreased 7to ~~and~~0.31 13bbl ~~bbls~~ per day for the three months ended ~~March~~June 3130, 2016 ~~and~~from ~~2015~~0.70 bbls per day for the three months ended June 30, ~~respectively~~2015, a decrease of 60.39 bbls per day (4656%).

~~Gain~~Our onoil ~~Mark-to-Market~~revenues ~~Derivatives.~~were On$2,800 ~~January~~and 1$14,300 ~~2015~~for the six months ended June 30, we2016 ~~discontinued~~and ~~hedge~~2015, ~~accounting~~respectively, ~~for~~a ~~our~~decrease ~~qualified~~of ~~commodity~~$11,500 ~~derivatives~~(81%). AsThe ~~such~~$11,500 ~~subsequent~~decrease ~~changes~~ in ~~fair~~oil ~~value~~revenues offor ~~these~~the ~~derivatives~~six ~~are~~months ~~recognized~~ended ~~immediately~~June ~~within~~30, ~~gain~~2016 onas ~~mark-~~compared to~~-market~~ ~~derivatives~~the onprior ~~our~~year ~~statements~~similar ofperiod ~~operations.~~was ~~The~~attributable ~~fair~~to ~~values~~a of$10,500 ~~these~~decrease ~~commodity~~in ~~derivative~~production ~~instruments~~volumes asand ofa ~~December 31~~$1,000 ~~2014,~~decrease ~~which~~in ~~were~~oil ~~recognized~~prices. inOur ~~accumulated~~production ~~other~~volumes ~~comprehensive~~decreased ~~income~~to ~~within~~0.47 ~~partners’~~bbls ~~capital~~per onday ~~our~~for ~~balance~~the ~~sheet,~~six ~~will~~months beended ~~reclassified~~June to30, ~~our~~2016 ~~statements~~from of1.78 ~~operations~~bbl inper day for the ~~future~~six atmonths ~~the~~ended ~~time~~June ~~the~~30, ~~originally~~2015, ~~hedged~~a ~~physical~~decrease ~~transactions~~of ~~settle~~1.31 bbl per day (74%).

WeNatural ~~recognized~~Gas ~~gains~~Liquids onRevenue. ~~mark-to-market~~The ~~derivatives~~majority of ~~$36~~our wells produce “dry gas”,~~500~~ which is composed primarily of methane and ~~$22,300,~~requires ~~for~~no additional processing before being transported and sold to the ~~three~~purchaser. ~~months~~Some ~~ended~~wells, ~~March~~however, 31produce “wet gas”, ~~2016~~which contains larger amounts of ethane and ~~2015,~~other ~~respectively~~associated hydrocarbons (i.e. ~~These~~“natural ~~gains~~gas ~~were~~liquids”) ~~due~~that tomust ~~mark-~~be removed prior to~~-market~~ ~~gains~~transporting ~~primarily~~the ~~related~~gas. Once removed, these natural gas liquids are sold to ~~the~~various ~~change~~purchasers. inOur natural gas ~~prices~~liquids ~~during~~revenues were $0 and $9,500 for the ~~periods~~three months ended June 30, 2016 and 2015, respectively, a decrease of $9,500 (100%).

~~Costs~~Our ~~and~~natural ~~Expenses.~~gas ~~Production~~liquids ~~expenses~~revenues were $~~436~~2,~~100~~700 and $~~598~~34,~~900~~400 for the ~~three~~six months ended ~~March~~June 3130, 2016 and 2015, respectively, a decrease of $~~162~~31,~~800~~700 (2792%). ~~This~~The $31,700 decrease ~~was~~in ~~mostly~~liquid ~~due~~revenues tofor athe ~~decrease~~six inmonths ~~transportation~~ended ~~costs~~June ~~due~~30, 2016 as compared to the ~~decline~~prior year similar period was attributable to a $25,500 decrease in ~~revenue~~production volumes and a $6,200 decrease in ~~maintenance~~liquid prices. Our production volumes were 3 and ~~repair~~10 ~~expenses.~~bbls per day for the six months ended June 30, 2016 and 2015, respectively, a decrease of 7 bbls per day (70%).

~~Depletion~~(Loss) ofGain ~~gas~~on ~~and~~Mark-to-Market ~~oil properties as a percentage of gas and oil revenues was 15% and 28% for the three months ended March 31, 2016 and 2015, respectively~~Derivatives. ~~This~~We ~~change~~recognize ~~was primarily attributable to~~ changes in ~~gas~~fair ~~and~~value ~~oil~~of ~~reserve~~our ~~quantities~~derivatives ~~and~~immediately towithin again ~~lesser~~on ~~extent~~mark-to-market ~~revenues,~~derivatives ~~product~~on ~~prices~~our ~~and~~condensed ~~production~~statements ~~volumes and changes in the depletable cost basis~~ of ~~gas and oil properties~~operations.

~~General~~We recognized a loss on mark-to-market derivatives of $43,100 and ~~administrative~~a ~~expenses~~gain of $30,600, for the three months ended ~~March~~June 3130, 2016 and 2015 ~~were $37~~,~~400~~ ~~and~~respectively. ~~$46,300,~~We ~~respectively,~~recognized a ~~decrease~~loss on mark-to-market derivatives of $86,~~900~~600 ~~(19%).~~and ~~These~~a ~~expenses~~gain ~~include~~of ~~third-party~~$52,900 ~~costs~~ for ~~services~~the assix ~~well~~months asended ~~the~~June ~~monthly~~30, ~~administrative~~2016 ~~fees~~and ~~charged~~2015, byrespectively. ~~our~~These ~~MGP~~changes ~~and~~were ~~vary~~due ~~from~~to ~~period~~ mark-to-market ~~period~~changes ~~due~~primarily related to the ~~costs~~change ~~charged~~in tonatural usgas ~~and~~prices ~~services~~during ~~provided~~the ~~to us~~periods.

~~Liquidity~~Costs and ~~Capital~~Expenses. Production ~~Resources~~expenses were $448,700 and $572,600 for the three months ended June 30, 2016 and 2015, respectively, a decrease of $123,900 (22%). Production expenses were $884,800 and $1,171,500 for the six months ended June 30, 2016 and 2015, respectively, a decrease of $286,700 (24%). The decreases for the three and six months ended June 30, 2016 as compared to the prior year similar period were mostly due to lower transportation costs due to a decrease in the realized price of natural gas, lower supervision fees, and lower direct costs.

WeDepletion ~~are~~of ~~generally~~oil ~~limited~~and togas ~~the~~properties ~~amount~~as a percentage of ~~funds~~oil ~~generated~~and bygas revenues was 12% and 7% for the ~~cash~~three ~~flows~~months ~~from~~ended ~~our~~June ~~operations~~30, ~~which~~2016 weand ~~believe~~2015, isrespectively, ~~adequate~~and to14% ~~fund~~and ~~future~~19% ~~operations~~for the six months ended June 30, 2016 and ~~distributions~~2015, respectively. These percentage changes are directly attributable to ~~our~~changes ~~partners.~~in revenues, oil and gas reserve quantities, product prices and production volumes and changes in the depletable cost basis of oil and gas properties.

~~The~~General ~~natural gas, oil~~ and ~~natural~~administrative ~~gas~~expenses ~~liquids~~for ~~commodity~~the ~~price~~three ~~markets~~months ~~have~~ended ~~suffered~~June ~~significant~~30, ~~declines~~2016 ~~throughout~~and 2015 ~~and~~were ~~have~~$40,100 ~~continued to decline~~ and ~~remain~~$43,600, ~~low~~respectively, ina ~~2016.~~decrease ~~The~~of ~~extreme~~$3,500 ~~ongoing volatility in the energy industry and commodity prices will likely continue to impact our outlook~~(8%). WeFor ~~have experienced downward revisions of our natural gas and oil reserves volumes and values due to~~ the ~~significant~~six ~~declines~~months inended ~~commodity~~June ~~prices.~~30, ~~Our~~2016 ~~MGP continues to implement various cost saving measures to reduce our operating~~ and ~~general and administrative costs~~2015, ~~including~~these ~~renegotiating~~expenses ~~contracts~~were ~~with contractors~~$77,500 ~~suppliers~~ and ~~service~~$89,900, ~~providers~~respectively, ~~reducing~~a ~~the~~decrease ~~number~~ of ~~staff~~$12,400 ~~and~~(14%). ~~contractors~~These ~~and~~expenses ~~deferring~~include ~~and~~third-party ~~eliminating discretionary~~ costs~~. Our~~ ~~MGP~~for ~~will~~services ~~continue~~as towell beas ~~opportunistic~~the ~~and~~monthly ~~aggressive~~administrative infees ~~managing~~charged ~~our~~by ~~cost structure and, in turn, liquidity to meet~~ our ~~operating needs~~MGP. ToThe ~~the~~decreases ~~extent~~for ~~commodity~~the ~~prices~~three ~~remain~~and ~~low~~six ormonths ~~decline~~ended ~~further~~June 30, or2016 weas ~~experience~~compared ~~other~~to ~~disruptions in~~ the ~~industry,~~prior ~~our~~year ~~ability~~similar toperiod ~~fund~~are ~~our~~primarily ~~operations~~due ~~and~~to ~~make~~third-party ~~distributions~~costs ~~may~~as becompared ~~further~~to ~~impacted, and could result in~~ the ~~MGP’s~~prior ~~decision~~year tosimilar ~~liquidate our operations~~period.

Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from our operations has been adequate to fund our obligations and distributions to our partners. However, the recent significant declines in commodity prices have challenged our ability to fund our operations and may make it uneconomical to produce our wells until they are depleted as we originally intended. Accordingly, the MGP determined that there is substantial doubt about our ability to continue as a going concern. The MGP intends, as necessary, to continue our operations and to fund our obligations for at least the next twelve months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to our 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~~Liquidity ~~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~~Capital ~~conversations~~Resources 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,~~We ~~however,~~are generally limited to the ~~MGP~~amount ~~were~~of tofunds ~~decide~~generated toby ~~liquidate~~the cash flow from our operations to fund our obligations and make distributions, if any, to our partners. Prices for oil and natural gas began to decline significantly during the ~~liquidation~~fourth ~~valuation~~quarter of ~~the~~2014 ~~Partnership’s~~and ~~assets~~have continued to decline and ~~liabilities~~remain ~~would~~low bein ~~determined~~2016. byThese anlower ~~independent~~commodity ~~expert~~prices have negatively impacted our revenues, earnings and cash flows. ItSustained islow ~~possible~~commodity ~~that~~prices ~~based~~will have a material and adverse effect on ~~such~~our ~~determination~~liquidity position. In addition, we ~~would~~have ~~not~~experienced besignificant ~~able~~downward revisions of its natural gas and oil reserves volumes and values due to ~~make~~the ~~any~~declines ~~liquidation~~in ~~distributions~~commodity prices. The MGP continues to implement various cost saving measures to reduce our ~~limited~~operating ~~partners.~~and Ageneral ~~liquidation~~and ~~could~~administrative ~~result~~costs, inincluding renegotiating contracts with contractors, suppliers and service providers, reducing the ~~transfer~~number of ~~the~~staff ~~post-liquidation~~and ~~assets~~contractors and ~~liabilities~~deferring ofand ~~the~~eliminating ~~Partnership~~discretionary costs. The MGP will continue to ~~the~~be ~~MGP~~strategic in managing our cost structure and, ~~would~~in ~~occur~~turn, ~~without~~liquidity ~~any~~to ~~further~~meet ~~contributions~~our ~~from~~operating needs. To the extent commodity prices remain low or ~~distributions~~decline further, or we experience other disruptions in the industry, our ability to fund our operations and make distributions may be further impacted, and could result in the ~~limited~~MGP’s ~~partners~~decision to liquidate our operations.

~~Cash~~If, ~~provided by operating activities decreased $33~~however,~~900~~ in the ~~three~~MGP ~~months~~were ~~ended~~to ~~March~~decide ~~31, 2016~~ to ~~zero~~liquidate asour ~~compared to $33~~operations,~~900~~ ~~for~~ the ~~three~~liquidation ~~months~~valuation ~~ended~~of ~~March 31,~~our ~~2015.~~assets ~~This~~and ~~decrease~~liabilities ~~was~~would ~~primarily~~be ~~due~~determined toby aan ~~decrease~~independent inexpert. ~~net~~It ~~earnings~~is ~~before~~possible ~~depletion~~that ~~and~~based ~~accretion~~on ofsuch ~~$293~~determination,~~900~~ ~~and~~we awould ~~decrease~~not inbe ~~asset~~able ~~retirement~~to ~~obligations~~make ~~settled~~any ofliquidation ~~$700.~~distributions ~~The~~to ~~decrease~~our ~~was~~limited ~~partially~~partners. ~~offset~~A byliquidation ancould ~~increase~~result in the ~~change~~transfer ~~in asset retirement receivable-affiliate~~ of ~~$76,100,~~ the ~~change~~post-liquidation inassets ~~accounts~~and ~~receivable~~liabilities ~~trade-affiliate~~ of ~~$65,500,~~ the ~~change~~Partnership into ~~accounts payable trade-affiliate of $65,300,~~ the ~~change~~MGP ~~in non-cash gain (loss) on derivative value of $51,100,~~ and anwould ~~increase~~occur inwithout ~~accrued~~any ~~liabilities~~further ofcontributions ~~$2,700~~from ~~for~~or ~~the~~distributions ~~three months ended March 31, 2016 compared~~ to the ~~three~~limited ~~months ended March 31, 201~~partners.

~~Cash~~Historically, ~~used~~there inhas ~~financing~~been ~~activities~~no ~~decreased~~need ~~$41,600~~to ~~during~~borrow funds from the ~~three~~MGP ~~months~~to ~~ended~~fund ~~March~~operations ~~31,~~as ~~2016~~the tocash ~~zero~~flow from ~~$41~~our operations have been adequate to fund our obligations and distributions to our partners. However,~~600~~ the recent significant declines in commodity prices have challenged our ability to fund our operations and may make it uneconomical for ~~the~~us ~~three~~to ~~months~~produce ~~ended~~our ~~March 31,~~wells ~~2015~~until they are depleted as we originally intended. ~~This~~Accordingly, ~~decrease~~the ~~was~~MGP ~~due~~determined that there is substantial doubt about our ability to continue as a ~~decrease~~going inconcern. ~~cash~~The ~~distributions~~MGP intends, as necessary, to ~~partners~~continue our operations and to fund our obligations for at least the next twelve months. To the extent commodity prices remain low or decline further or ARP is unsuccessful in completing its Restructuring (as defined below) or the Plan (as defined below), the MGP’s ability to continue our operations may be further impacted.

~~Our~~ARP ~~MGP~~Restructuring ~~may withhold funds for future plugging~~ and ~~abandonment~~Chapter ~~costs.~~11 ~~Through~~Bankruptcy 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. Proceedings

Cash provided by operating activities decreased $116,300 in the six months ended June 30, 2016 to zero as compared to $116,300 for the six months ended June 30, 2015. This decrease was primarily due to a decrease in net earnings before depletion and accretion of $326,700, a decrease in the change in accounts receivable trade-affiliate of $191,500, a decrease in the change in asset retirement receivable-affiliate of $6,200, and a decrease in asset retirement obligations settled of $700. The decrease was partially offset by an increase in the change in accounts payable trade-affiliate of $337,000, the change in non-cash loss on derivative value of $66,700, and an increase in accrued liabilities of $5,100 for the six months ended June 30, 2016 compared to the six months ended June 30, 2015.

Cash used in financing activities decreased $144,300 during the six months ended June 30, 2016 to zero from $144,300 for the six months ended June 30, 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 June 30, 2016, our MGP has withheld $306,100 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

~~For~~See aNote ~~more~~2 ~~complete~~to ~~discussion of the accounting policies and estimates that we have identified as critical in the preparation of~~ our condensed ~~consolidated~~ financial statements, ~~please refer to our Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K~~ for ~~the~~additional ~~fiscal~~information ~~year~~related ~~ended~~to ~~December~~recently ~~31,~~issued ~~2015~~accounting standards.

For a more complete discussion of the accounting policies and estimates that we have identified as critical in the preparation of our condensed financial statements, please refer to our Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the fiscal year ended December 31, 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 ~~March~~June 3130, 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

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.

1819

ITEM 6.

EXHIBITS

EXHIBIT INDEX

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

~~(1) Filed on October 15, 2008 in the Form S-1A Registration Statement dated October 15, 2008, File No. 333-150925-03~~20

SIGNATURES

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

	ATLAS RESOURCES PUBLIC #18-2008 (A) L.P.
	By:	Atlas Resources, LLC, its
		Managing General Partner
Date: May 23, 2016	By:	/s/ FREDDIE M. KOTEK
Date: August 15, 2016	By:	/s/ FREDDIE M. KOTEK
		Freddie M. Kotek, Chief Executive Officer and President of the Managing General Partner

Date: May 23, 2016	By:	/s/ JEFFREY M. SLOTTERBACK
Date: August 15, 2016	By:	/s/ JEFFREY M. SLOTTERBACK
		Jeffrey M. Slotterback Chief Financial Officer of the Managing General Partner

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