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~~ 30March 31, ~~2014~~2015

¨	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 000-52615

ATLAS AMERICA SERIES 27-2006 L.P.

(Name of small business issuer in its charter)

Delaware		20-5242075
(State or other jurisdiction ofincorporation or organization)		(I.R.S. EmployerIdentification No.)
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
Park Place Corporate Center One1000 Commerce Drive, 4th FloorPittsburgh, PA		15275
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 AMERICA SERIES 27-2006 L.P.

(A Delaware Limited Partnership)

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

		PAGE	~~PAGE~~
PART I.	FINANCIAL INFORMATION (Unaudited)
Item 1:
	Condensed Balance Sheets as of September 30, 2014 and December 31, 2013		3
	Condensed Balance Sheets as of March 31, 2015 and December 31, 2014	3
	Condensed Statements of Operations for the Three and Nine Months ended September 30, 2014 and 2013		4
	Condensed Statements of Operations for the Three Months ended March 31, 2015 and 2014	4
	Condensed Statements of Comprehensive (Loss) Income for the Three and Nine Months ended September 30, 2014 and 2013		5
	Condensed Statements of Comprehensive (Loss) Income for the Three Months ended March 31, 2015 and 2014	5
	Condensed Statement of Changes in Partners’ Capital for the Nine Months ended September 30, 2014		6
	Condensed Statement of Changes in Partners’ Capital for the Three Months ended March 31, 2015	6
	Condensed Statements of Cash Flows for the Nine Months ended September 30, 2014 and 2013		7
	Condensed Statements of Cash Flows for the Three Months ended March 31, 2015 and 2014	7
	Notes to Condensed Financial Statements	8	8
Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16	19
Item 4:	Controls and Procedures	19	22
PART II.	OTHER INFORMATION
Item 1:	Legal Proceedings	20	23
Item 6:	Exhibits	21	24
SIGNATURES		22	25
CERTIFICATIONS

PART I. FINANCIAL INFORMATION

ITEM I. FINANCIAL STATEMENTS

ATLAS AMERICA SERIES 27-2006 L.P.

CONDENSED BALANCE SHEETS

(Unaudited)

	September 30,2014			December 31,2013
	March 31,2015			December 31,2014
ASSETS
Current assets:
Cash and cash equivalents	$	-		$	~~62,800~~-
Accounts receivable trade–affiliate		~~309~~150,~~700~~300			~~379~~200,~~400~~000
Asset retirement receivable-affiliate		34,400			-
Asset retirement receivable–affiliate		45,600			34,400
Accounts receivable monetized gains-affiliate		-			24,100
Current portion of derivative assets		23,600			20,500
Current portion of derivative assets		5,600			2,900
Total current assets		219,500			254,900
Total current assets		349,700			469,200
Gas and oil properties, net		3,283,800			3,330,200
Oil and gas properties, net		5,304,300			5,545,000
Long-term derivative assets		16,600			17,100
Long-term derivative assets		11,800			15,300
	$	3,519,900		$	3,602,200
	$	5,665,800		$	6,029,500
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	912,~~900~~800		$	109,~~400~~700
Current portion of put premiums payable-affiliate		513,600			-13,100
Total current liabilities		1526,~~500~~400			1022,~~400~~800
Asset retirement obligation		3,353,100			3,210,500
Asset retirement obligations		4,466,700			4,403,700
Long-term put premiums payable-affiliate		1711,~~900~~300			2715,~~400~~000
Commitments and contingencies
Partners’ capital:
Managing general partner’s interest		~~717~~(343,~~900~~500	)		~~828~~(294,~~700~~000	)
Limited partners’ interest (2,840 units)		1(648,~~571,500~~400	)		1(554,~~956,~~700	)
Accumulated other comprehensive loss		(10,100	)		(4,200	)
Accumulated other comprehensive income		7,400			9,400
Total partners’ capital		2(984,~~279,300~~500	)		2(839,~~781,200~~300	)
	$	53,~~665~~519,~~800~~900		$	63,~~029~~602,~~500~~200

See accompanying notes to condensed financial statements.

ATLAS AMERICA SERIES 27-2006 L.P.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months EndedSeptember 30,						Nine Months EndedSeptember 30,
	Three Months Ended
	2014			2013			2014		2013
	March 31,
REVENUES
	2015			2014
Natural gas and oil	$	362,900		$	548,600		$	1,544,000	$	1,693,800
REVENUES
Total revenues		362,900			548,600			1,544,000		1,693,800
Natural gas and oil	$	309,200		$	599,400
COSTS AND EXPENSES
Gain on mark-to-market derivatives		5,900			-
Production		301,600			335,300			943,700		990,400
Total revenues		315,100			599,400
Depletion		85,900			316,200			240,700		945,400
COSTS AND EXPENSES
Accretion of asset retirement obligation		47,600			44,900			142,900		134,800
Production		297,200			319,400
General and administrative		47,200			53,500			137,100		157,000
Depletion		46,400			75,200
Total costs and expenses		482,300			749,900			1,464,400		2,227,600
Accretion of asset retirement obligation		63,000			47,600
Net (loss) income	$	(119,400	)	$	(201,300	)	$	79,600	$	(533,800	)
General and administrative		51,700			48,000
Allocation of net (loss) income:
Total costs and expenses		458,300			490,200
Managing general partner	$	(27,200	)	$	(24,900	)	$	58,500	$	(54,300	)
Net (loss) income	$	(143,200	)	$	109,200
Limited partners	$	(92,200	)	$	(176,400	)	$	21,100	$	(479,500	)
Allocation of net (loss) income:
Net (loss) income per limited partnership unit	$	(33	)	$	(62	)	$	7	$	(169	)
Managing general partner	$	(49,500	)	$	45,300
Limited partners	$	(93,700	)	$	63,900
Net (loss) income per limited partnership unit	$	(33	)	$	23

See accompanying notes to condensed financial statements.

ATLAS AMERICA SERIES 27-2006 L.P.

CONDENSED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(Unaudited)

	Three Months EndedSeptember 30,						Nine Months EndedSeptember 30,
	Three Months Ended
	2014			2013			2014			2013
	March 31,
Net (loss) income	$	(119,400	)	$	(201,300	)	$	79,600		$	(533,800	)
	2015			2014
Other comprehensive income (loss):
Net (loss) income	$	(143,200	)	$	109,200
Unrealized holding gain (loss) on cash flow hedging contracts		7,600			3,900			(13,600	)		(15,700	)
Other comprehensive loss:
Difference in estimated hedge gains receivable		(2,000	)		14,300			33,100			62,600
Unrealized holding loss on cash flow hedging contracts		-			(22,600	)
Reclassification adjustment for gains realized in net loss from cash flow hedges		(2,600	)		(18,600	)		(25,400	)		(62,300	)
Difference in estimated hedge gains receivable		3,300			38,600
Total other comprehensive income (loss)		3,000			(400	)		(5,900	)		(15,400	)
Reclassification adjustment for gains realized in net (loss) income from cash flow hedges		(5,300	)		(21,900	)
Comprehensive (loss) income	$	(116,400	)	$	(201,700	)	$	73,700		$	(549,200	)
Total other comprehensive loss		(2,000	)		(5,900	)
Comprehensive (loss) income	$	(145,200	)	$	103,300

See accompanying notes to condensed financial statements.

ATLAS AMERICA SERIES 27-2006 L.P.

CONDENSED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE ~~NINE~~THREE MONTHS ENDED

~~September 30~~March 31, ~~2014~~2015

(Unaudited)

	ManagingGeneralPartner			LimitedPartners			~~AccumulatedOtherComprehensiveLoss~~Accumulated OtherComprehensiveIncome (Loss)			Total
Balance at December 31, 2013	$	828,700		$	1,956,700		$	(4,200	)	$	2,781,200
Balance at December 31, 2014	$	(294,000	)	$	(554,700	)	$	9,400		$	(839,300	)
Participation in revenues and expenses:
Participation in revenues, costs and expenses:
Net production revenues		~~193~~2,600			~~406~~9,~~700~~400			-			~~600~~12,~~300~~000
Depletion		(44,000	)		(196,700	)		-			(240,700	)
Gain on mark-to-market derivatives		-			5,900			-			5,900
Accretion of asset retirement obligation		(46,500	)		(96,400	)		-			(142,900	)
Depletion		(14,800	)		(31,600	)		-			(46,400	)
General and administrative		(44,600	)		(92,500	)		-			(137,100	)
Accretion of asset retirement obligation		(20,500	)		(42,500	)		-			(63,000	)
Net income		58,500			21,100			-			79,600
General and administrative		(16,800	)		(34,900	)		-			(51,700	)
Other comprehensive loss		-			-			(5,900	)		(5,900	)
Net loss		(49,500	)		(93,700	)		-			(143,200	)
Distributions to partners		(169,300	)		(406,300	)		-			(575,600	)
Other comprehensive loss		-			-			(2,000	)		(2,000	)
Balance at September 30, 2014	$	717,900		$	1,571,500		$	(10,100	)	$	2,279,300
Balance at March 31, 2015	$	(343,500	)	$	(648,400	)	$	7,400		$	(984,500	)

See accompanying notes to condensed financial statements.

ATLAS AMERICA SERIES 27-2006 L.P.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months EndedSeptember 30,
	Three Months Ended
	2014			2013
	March 31,
	2015			2014
Cash flows from operating activities:
Net income (loss)	$	79,600		$	(533,800	)
Net (loss) income	$	(143,200	)	$	109,200
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion		~~240~~46,~~700~~400			~~945~~75,~~400~~200
Non cash loss on derivative value		15,100			89,900
Non cash (gain) loss on derivative value		(7,800	)		3,100
Accretion of asset retirement obligation		~~142~~63,~~900~~000			~~134~~47,~~800~~600
Changes in operating assets and liabilities:
Decrease in accounts receivable-trade affiliate		69,700			48,600
Decrease (increase) in accounts receivable-trade affiliate		49,700			(135,100	)
(Decrease) increase in accrued liabilities		(500	)		10,700
Increase in asset retirement receivable-affiliate		(11,200	)		-
Asset retirement receivable-affiliate		(34,400	)		-
Increase in accrued liabilities		3,100			10,000
Asset retirement obligations settled		(300	)		-
Net cash provided by operating activities		-			110,000
Net cash provided by operating activities		512,800			695,600
Cash flows from financing activities:
Distributions to partners		~~(575,600~~-	)		(~~724~~172,~~500~~800	)
Net cash used in financing activities		~~(575,600~~-	)		(~~724~~172,~~500~~800	)
Net decrease in cash and cash equivalents		(62,800	)		(28,900	)
Net change in cash and cash equivalents		-			(62,800	)
Cash and cash equivalents at beginning of period		~~62,800~~-			2862,~~900~~800
Cash and cash equivalents at end of period	$	-		$	-

See accompanying notes to condensed financial statements.

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO CONDENSED FINANCIAL STATEMENTS

~~September~~March 3031, ~~2014~~2015

(Unaudited)

NOTE 1 - DESCRIPTION OF BUSINESS

Atlas America Series 27-2006 L.P. (the “Partnership”) is a Delaware limited partnership, formed on July 21, 2006 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).

On ~~October~~February 1327, ~~2014~~2015, the MGP’s ultimate parent, Atlas Energy, L.P. (“Atlas Energy”) ~~(NYSE: ATLS)~~, ~~and~~which ~~its~~was ~~midstream~~a ~~subsidiary,~~publicly ~~Atlas~~traded ~~Pipeline~~master-limited ~~Partners~~partnership, ~~L.P.~~was ~~(“APL”), entered into definitive agreements to be~~ acquired by Targa Resources Corp. and ~~Targa~~distributed ~~Resources Partners LP, respectively. Immediately prior~~ to ~~the acquisition,~~ Atlas Energy’s ~~will distribute to its~~ unitholders 100% of the limited liability company interests in ARP’s general partner, ~~which has changed its name to~~ Atlas Energy Group, LLC (“~~New~~ Atlas Energy Group”; NYSE: ATLS). Atlas ~~and~~Energy ~~will~~Group ~~become~~became a separate, publicly traded company and the ultimate parent of the MGP as a result of the distribution. ~~New~~Following ~~Atlas~~the ~~will~~distribution, ~~hold all of~~ Atlas Energy’s ~~non-midstream~~Group ~~holdings,~~continues ~~which~~to ~~includes~~manage ~~the Partnership~~ARP’s ~~business~~operations asand ~~well~~activities asthrough ~~the~~its ~~general~~ownership ~~partner~~of ~~interest,~~the ~~incentive distribution rights and Atlas Energy~~ARP’s ~~limited~~general partner interest ~~in ARP~~.

InThe ~~March~~Partnership ~~2012,~~has ~~Atlas~~drilled ~~Energy~~and ~~contributed~~currently tooperates ~~ARP,~~wells alocated ~~newly-formed~~in ~~exploration~~New York, Pennsylvania and ~~production~~Tennessee. ~~master~~The ~~limited~~Partnership ~~partnership,~~has ~~substantially~~no ~~all~~employees ofand ~~Atlas~~relies ~~Energy’s~~on ~~natural~~the ~~gas~~MGP ~~and~~for ~~oil~~management, ~~development~~which ~~and~~in ~~production~~turn, ~~assets~~relies ~~and~~on its ~~partnership~~parent ~~management~~company, ~~business~~Atlas Energy (after February 27, ~~including~~2015, ~~ownership~~Atlas ofEnergy ~~the~~Group), ~~MGP~~for administrative services.

On February 17, 2011, Atlas Energy, a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of APL, completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business, its oil and gas exploration, development and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, certain well interests in Pennsylvania and Michigan and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the “Transferred Business”).

The Partnership has drilled and currently operates wells located in New York, Pennsylvania and Tennessee. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy, for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil 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 for the balance sheet at December 31, ~~2013~~2014, which 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, ~~2013~~2014. The results of operations for the three ~~and nine~~ months ended ~~September 30~~March 31, ~~2014~~2015 may not necessarily be indicative of the results of operations for the year ended December 31, ~~2014~~2015.

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, ~~2013~~2014 filed with the Securities and Exchange Commission (“SEC”).

Use of Estimates

~~Preparation~~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 ~~much~~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, ~~2014~~2015 and ~~2013~~2014 represent actual results in all material respects (~~see~~See “Revenue Recognition” ~~for further description~~).

Accounts Receivable ~~and Allowance for Possible Losses~~

InAccounts ~~evaluating~~receivable on the ~~need~~balance ~~for~~sheets anconsist ~~allowance~~solely ~~for~~of ~~possible~~the ~~losses~~trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its 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~~March 3031, ~~2014~~2015 and December 31, ~~2013~~2014, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for ~~possible~~uncollectible ~~losses~~accounts receivable.

~~Oil~~Gas and ~~Gas~~Oil Properties

~~Oil~~Gas and ~~gas~~oil properties are stated at cost. Maintenance and repairs ~~that~~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 ~~oil~~gas and ~~gas~~oil producing activities. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six ~~million~~Mcf ~~cubic feet (“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 $~~240~~46,~~700~~400 and $~~945~~75,~~400~~200 for the ~~nine~~three months ended ~~September~~March 3031, ~~2014~~2015 and ~~2013~~2014, respectively.

Upon the sale or retirement of a complete field of a proved property, the ~~Partnership~~cost ~~eliminates~~is ~~the~~eliminated ~~cost~~ from the property accounts and the resultant 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 ~~depreciation and~~ depletion within its balance sheets. As a result of retirements, the Partnership reclassified $137,200 from oil and gas properties to accumulated depletion for the nine months ended September 30, 2014. Upon the sale of an entire interest, a gain or loss is recognized in the statement of operations.

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

	September 30,			December 31,
	March 31,			December 31,
	2014			2013
	2015			2014
Proved properties:
Leasehold interests	$	1,684,000		$	1,~~687~~684,~~400~~000
Wells and related equipment		8586,~~775~~777,~~000~~900			8586,~~908~~777,~~800~~900
Total natural gas and oil properties		8788,~~459~~461,~~000~~900			8788,~~596~~461,~~200~~900
Accumulated depletion and impairment		(8285,~~154~~178,~~700~~100	)		(8285,~~051~~131,~~200~~700	)
Oil and gas properties, net	$	5,304,300		$	5,545,000
Gas and oil properties, net	$	3,283,800		$	3,330,200

Impairment of Long-Lived Assets

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 ~~oil~~gas and ~~gas~~oil properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, ~~depreciation~~ and ~~amortization~~impairment ~~and abandonment~~ 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 and the carrying value of the assets.

The determination of ~~oil and~~ 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. ~~There were no impairments of oil and gas properties for the three and nine months ended September 30, 2014 and 2013 or during the year ended December 31, 2013.~~

There was no gas and oil properties impairment recorded for the three months ended March 31, 2015 and 2014. During the year ended December 31, 2014, the Partnership recognized an impairment charge of $2,826,200. This 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 December 31, 2014. 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.

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 7% 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 and crude oil at prevailing market prices. ~~Generally~~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 and crude oil, 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, ~~NGL’s,~~ 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. ~~During the current quarter, the Partnership identified a material weakness in its revenue recognition process~~ (See ~~Item~~“Use 4:of ~~Controls~~Estimates” ~~and~~for ~~Procedures~~further description). AsThe ~~a result of the weakness, the~~ Partnership ~~overestimated~~had ~~its June 30, 2014~~ unbilled revenues byat ~~$26,800.~~March ~~As a result~~31, ~~revenue~~2015 and ~~net~~December ~~income is overstated by $26~~31,~~800~~ ~~for the three and six months ended June 30,~~ 2014. ~~In adjusting for the overstatement~~ of ~~revenue~~$163,600 and ~~net income that existed at June 30~~$223,900 ~~2014~~respectively, ~~during~~which ~~the~~have ~~third~~been ~~quarter~~offset ~~of 2014 revenue is understated~~ by $2613,~~800~~000 and ~~net loss is overstated for the three month period ended September 30~~$23,900, ~~2014. In addition~~respectively, ~~there was no impact on Partnership distributions. As~~ of ~~September~~amounts ~~30,~~due ~~2014,~~to the ~~weakness~~MGP, ~~has~~with ~~been remediated and~~ the ~~Partnership~~net ~~had~~amount ~~unbilled~~presented ~~revenues~~as ~~at September 30, 2014 and December 31, 2013 of $203,700 and $283,900 respectively, which were included in~~ accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive (Loss) Income

Comprehensive (loss) income includes net (loss) income 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 (loss) income. These changes, other than net (loss) income, are referred to as “other comprehensive ~~income (~~loss)” on the Partnership’s financial statements and, ~~for~~at ~~the~~March ~~Partnership~~31, 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 loss.

Recently Adopted Accounting Standards

In February 2013, the Financial Accounting Standards Board (the “FASB”) issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership adopted the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures.

Recently Issued Accounting Standards

In ~~August~~January ~~2014~~2015, the Financial Accounting Standards Board (“FASB”) issued ASU ~~2014~~2015-1501, ~~Presentation~~Income ofStatement ~~Financial~~– ~~Statements~~Extraordinary –and ~~Going~~Unusual ~~Concern~~Items (Subtopic ~~205~~225-4020): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items (“Update ~~2014~~2015-1501”). The amendments in Update ~~2014~~2015-1501 ~~provide~~simplify ~~U.S.~~the ~~GAAP~~income ~~guidance~~statement onpresentation ~~the~~requirements ~~responsibility~~in ofSubtopic an225-20 ~~entity’s~~by ~~management~~eliminating inthe ~~evaluating~~concept ~~whether~~of ~~there~~extraordinary isitems. ~~substantial~~Extraordinary ~~doubt~~items ~~about~~are ~~the~~events ~~entity’s~~and ~~ability~~transactions tothat ~~continue~~are asdistinguished aby ~~going~~their ~~concern~~unusual nature and ~~about~~by ~~related~~the ~~footnote~~infrequency ~~disclosures~~of their occurrence. ~~For~~Eliminating ~~each~~the ~~reporting~~extraordinary ~~period,~~classification ansimplifies ~~entity’s~~income ~~management~~statement ~~will~~presentation beby ~~required~~altogether toremoving ~~evaluate~~the ~~whether~~concept ~~there~~of ~~are~~extraordinary ~~conditions~~items orfrom ~~events~~consideration. ~~that~~The ~~raise~~amendments ~~substantial~~in ~~doubt~~Update ~~about~~2015-01 ~~its~~are ~~ability~~effective tofor ~~continue~~fiscal asyears, aand ~~going~~interim ~~concern~~periods within ~~one~~those ~~year~~fiscal ~~from~~years, ~~the~~beginning ~~date~~after ~~the~~December ~~financial~~15, ~~statements~~2015. ~~are~~A ~~issued.~~reporting Inentity ~~doing~~may ~~so,~~apply the amendments inprospectively. ~~Update~~A ~~2014-15~~reporting ~~should~~entity ~~reduce~~may ~~diversity~~also inapply the ~~timing~~amendments ~~and~~retrospectively ~~content~~to ofall ~~footnote~~prior ~~disclosures.~~periods ~~The~~presented ~~amendments~~ in ~~Update~~the ~~2014-15~~financial ~~are~~statements. ~~effective~~Early ~~for~~adoption ~~the~~is ~~annual~~permitted ~~period~~provided ~~ending~~that ~~after~~the ~~December~~guidance ~~15,~~is ~~2016,~~applied ~~and~~from ~~for~~the ~~annual~~beginning ~~periods~~of ~~and~~the ~~interim~~fiscal ~~periods~~year ~~thereafter.~~of ~~Early~~ adoption ~~is permitted~~. The Partnership will adopt the requirements of Update ~~2014~~2015-1501 upon its effective date of January 1, 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In May 2014, the FASB 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, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, 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 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 obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. 11

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) (“Update 2014-15”). The amendments in Update 2014-15 provide GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management 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. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date in 2016, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In May 2014, the FASB 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, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, 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 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 obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures. On April 1, 2015, the FASB tentatively decided to defer the effective date of ASU 2014-09 by one year. As a result, public entities would apply the new revenue standard to annual reporting periods beginning after December 15, 2017, and to interim periods within that reporting period, with early adoption permitted.

NOTE 3 - ASSET RETIREMENT OBLIGATIONS

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells. It also recognizes a liability for future asset retirement obligations 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.

The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in cost estimates, 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 the Partnership’s gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets.

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 March 31, 2015, the MGP has withheld $45,600 of net production revenue for future plugging and abandonment costs.

~~NOTE~~A 3reconciliation -of ~~ASSET~~the ~~RETIREMENT~~Partnership’s ~~OBLIGATION~~liability for well plugging and abandonment costs for the periods indicated is as follows:

The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in cost estimates, remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The associated asset retirement costs from revisions are capitalized as part of the carrying amount of the long-lived asset. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its oil and gas properties, the Partnership has determined that there are no other material retirement obligations associated with tangible long-lived assets.

	Three Months Ended
	March 31,
	2015		2014
Asset retirement obligations at beginning of period	$	4,403,700	$	3,210,500
Accretion expense		63,000		47,600
Asset retirement obligations at end of period	$	4,466,700	$	3,258,100

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, 2014, the MGP withheld $34,400 of net production revenue for future plugging and abandonment costs.

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

	Three Months EndedSeptember 30,				Nine Months EndedSeptember 30,
	2014		2013		2014			2013
Asset retirement obligation at beginning of period	$	3,305,500	$	3,395,900	$	3,210,500		$	3,306,000
Liabilities settled		-		-		(300	)		-
Accretion expense		47,600		44,900		142,900			134,800
Asset retirement obligation at end of period	$	3,353,100	$	3,440,800	$	3,353,100		$	3,440,800

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. To manage the risk of regional commodity price differences, the Partnership occasionally enters into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to New York Mercantile Exchange (“NYMEX”), the Partnership receives or pays a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. 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.

On January 1, 2015, the Partnership discontinued hedge accounting for its qualified commodity derivatives. As such, changes in fair value of these derivatives after December 31,2014 are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within partners’ capital on the Partnership’s balance sheet, will be reclassified to the Partnership’s statements of operations in the future at the time the originally hedged physical transactions affect earnings.

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 $40,200 and $37,600 at March 31, 2015 and December 31, 2014, respectively.

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 Ended
	March 31,
	2015		2014
Gains reclassified from accumulated other comprehensive income into natural gas and oil revenues	$	5,300	$	21,900
Gains subsequent to December 31, 2014 recognized in gain on mark-to-market derivatives	$	5,900	$	-

The ~~MGP~~Partnership ~~formally~~enters ~~documents~~into ~~all~~commodity ~~relationships~~future ~~between~~option ~~hedging instruments~~ and ~~the~~collar ~~items~~contracts ~~being~~to ~~hedged,~~achieve ~~including~~more ~~its~~predictable ~~risk~~cash ~~management~~flows ~~objective~~by ~~and strategy for undertaking the~~ hedging ~~transactions.~~its ~~This~~exposure ~~includes~~to ~~matching~~changes ~~the~~in commodity ~~derivative~~prices. ~~contracts~~At toany ~~the~~point ~~forecasted~~in ~~transactions. The MGP assesses~~time, ~~both~~such atcontracts ~~the~~may ~~inception~~include ofregulated ~~the~~NYMEX ~~derivative~~futures and onoptions ancontracts ~~ongoing~~and ~~basis,~~non-regulated ~~whether~~ over-the-counter ~~derivative~~futures ~~was~~contracts ~~effective~~with inqualified ~~offsetting changes in the forecasted cash flow of the hedged item~~counterparties. IfNYMEX ~~the~~contracts ~~MGP~~are ~~determines~~generally ~~that~~settled awith ~~derivative~~offsetting ispositions, ~~not~~but ~~effective~~may ~~as a hedge or that it has ceased to~~ be ansettled ~~effective~~by ~~hedge due to~~ the ~~loss~~physical delivery of ~~adequate correlation between~~ the ~~hedging~~commodity. ~~instrument~~Crude ~~and~~oil ~~the~~contracts ~~underlying item being hedged, the MGP will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which~~ are ~~determined~~based byon ~~management~~a ofWest ~~the~~Texas ~~MGP~~Intermediate ~~through the utilization of market data, will be recognized immediately within gain~~ (~~loss~~“WTI”) ~~on mark-to-market derivatives in the Partnership’s statements of operations~~index. ~~For~~NGL ~~derivatives~~fixed ~~qualifying~~price asswaps ~~hedges,~~are ~~the~~priced ~~Partnership~~based ~~recognizes~~on ~~the~~a ~~effective~~WTI ~~portion~~crude ~~of changes in fair value of derivative instruments as accumulated other comprehensive income and reclassifies the portion relating to the Partnership’s commodity derivatives to gas and~~ oil ~~production revenues within the Partnership’s statements of operations as the underlying transactions are settled~~index. ~~For~~These ~~non-qualifying~~contracts ~~derivatives~~have ~~and~~been ~~for~~recorded ~~the~~at ~~ineffective~~their ~~portion of qualifying derivatives, the Partnership recognizes changes in~~ fair ~~value within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations as they occur~~values.

~~The~~At ~~Partnership~~March ~~enters into derivative contracts with various financial institutions~~31, ~~utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association~~2015, ~~Inc. These contracts allow for rights of offset at~~ the ~~time~~Partnership ofhad ~~settlement of~~ the ~~derivatives.~~following ~~Due~~commodity ~~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 $17,400 and $18,200 at September 30, 2014 and December 31, 2013, respectively.

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 point in time, such contracts may include regulated New York Mercantile 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. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

At September 30, 2014, the Partnership had the following commodity derivatives:

Natural Gas Put Options

ProductionPeriod EndingDecember 31,	Volumes		~~Average FixedPrice~~		Average Fixed Price		~~Fair ValueAsset (2)~~		Fair ValueAsset (2)
	(MMBtu) (1)		~~(per MMBtu) (1)~~		(per MMBtu) (1)
2014	6,000		$	3.80			$	300
2015		14,700			$	4.00			$	18,000
2015	19,100			4.00				7,300
2016		19,600				4.15				22,200
2016	19,200			4.15				9,800
									$	40,200
							$	17,400

(1)	“MMBtu” represents million British Thermal Units.

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

~~Effects~~As ofthe ~~Derivative~~underlying ~~Instruments~~prices onand ~~Statements~~terms ofin ~~Operations:~~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, 2015 and 2014 for hedge ineffectiveness.

~~The~~Put ~~following~~Premiums ~~table summarizes the gain or loss recognized in the statements of operations for the three and nine months ended September 30, 2014 and 2013:~~ Payable

	Three Months EndedSeptember 30,				Nine Months EndedSeptember 30,
	2014		2013		2014		2013
Gain from cash flow hedges reclassified from accumulated other comprehensive income (loss) into natural gas and oil revenues	$	2,600	$	18,600	$	25,400	$	62,300

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 March 31, 2015 and December 31, 2014, the put premiums were recorded as short-term payables to affiliate, of $13,600 and $13,100, respectively, and long-term payables to affiliate of $11,300 and $15,000, respectively.

AsAccumulated ~~the~~Other ~~underlying~~Comprehensive 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 and nine months ended September 30, 2014 and 2013 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges. Income

~~Monetized~~As ~~Gains~~a result of the put options, the Partnership recorded a net deferred gain on its balance sheet in accumulated other comprehensive income of $7,400 as of March 31, 2015. During the three months ended March, 31, 2015, $4,000 of net gains were recorded by the Partnership and allocated only to the limited partners. Of the remaining $7,400 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $5,900 of net gains to the Partnership’s statements of operations over the next twelve month period and the remaining $1,500 in later periods.

At September 30, 2014 and December 31, 2013, remaining hedge monetization cash proceeds of $7,500 and $37,900, respectively, related to the amounts hedged on behalf of the Partnership’s limited partners were included within accounts receivable monetized gains-affiliate. The Partnership will allocate the monetized net proceeds to the limited partners based on the natural gas and oil production generated over the period of the original derivative contracts.

During June 2012, the MGP used the undistributed monetized funds to purchase natural gas put options on behalf of the limited partners of the Partnership only. 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, 2014 and December 31, 2013, the put premiums were recorded as short-term payables to affiliate of $13,100 and $13,800, respectively, and long-term payables to affiliate of $17,900 and $27,400, respectively.

The following table summarizes the gross and net fair values of the Partnership’s affiliate balances on the Partnership’s balance sheets for the periods indicated:

	Gross Amountsof RecognizedAssets		Gross AmountsOffset in theBalance Sheets			Net Amount of AssetsPresented in theBalance Sheets
Offsetting Assets
As of September 30, 2014
Accounts receivable monetized gains-affiliate	$	7,500	$	(7,500	)	$	-
As of December 31, 2013
Accounts receivable monetized gains-affiliate	$	37,900	$	(13,800	)	$	24,100

	Gross Amountsof RecognizedLiabilities			Gross AmountsOffset in theBalance Sheets		Net Amount ofLiabilitiesPresented in theBalance Sheets
Offsetting Liabilities
As of September 30, 2014
Put premiums payable-affiliate	$	(13,100	)	$	7,500	$	(5,600	)
Long-term put premiums payable-affiliate		(17,900	)	-	-		(17,900	)
Total	$	(31,000	)	$	7,500	$	(23,500	)
As of December 31, 2013
Put premiums payable-affiliate	$	(13,800	)	$	13,800	$	-
Long-term put premiums payable-affiliate		(27,400	)		-		(27,400	)
Total	$	(41,200	)	$	13,800	$	(27,400	)

Accumulated Other Comprehensive Loss

As a result of the monetization and the early settlement of natural gas and oil derivative instruments, the put options, and the unrealized gains recognized in earnings in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred loss on its balance sheets in accumulated other comprehensive loss of $10,100 as of September 30, 2014. Included in accumulated other comprehensive loss are unrealized gains of $4,000, net of the MGP interest, that were recognized into earnings as a result of oil and gas property impairments during prior periods. During the nine months ended September 30, 2014, $5,200 of net gains were recorded by the Partnership and allocated only to the limited partners. Of the remaining $10,100 of net unrealized loss in accumulated other comprehensive loss, the Partnership will reclassify $4,000 of net loss to the Partnership’s statements of operations over the next twelve month period and the remaining loss of $6,100 in later periods.

NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership has established a hierarchy to measure 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 1 – Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with 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.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The carrying values of cash, accounts receivable and accounts payable approximate their respective fair values due to the short-term maturities of such financial instruments. The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (~~see~~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. ~~These~~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 for assets ~~and liabilities~~ measured at fair value at ~~September~~March 3031, ~~2014~~2015 and December 31, ~~2013~~2014 iswas as follows:

	Level 1		Level 2		Level 3		Total
As of September 30, 2014
As of March 31, 2015
Derivative assets, gross
Commodity puts	$	-	$	1740,~~400~~200	$	-	$	1740,~~400~~200
Derivative liabilities, gross
Commodity puts		-		-		-		-
Total derivatives, fair value, net	$	-	$	17,400	$	-	$	17,400

	Level 1		Level 2		Level 3		Total
As of December 31, 2013
As of December 31, 2014
Derivative assets, gross
Commodity puts	$	-	$	1837,~~200~~600	$	-	$	1837,~~200~~600
Derivative liabilities, gross
Commodity puts		-		-		-		-
Total derivatives, fair value, net	$	-	$	18,200	$	-	$	18,200

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 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~~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~~March 3031, ~~2014~~2015 and ~~2013~~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 expense in the Partnership’s ~~statement~~statements of operations, are payable at $376 per well per month for operating and maintaining the wells. ~~Transportation~~Well supervision fees, ~~which~~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 13% of the natural gas sales price. Direct costs, which are included in production and general administrative ~~expense~~expenses in the Partnership’s ~~statement~~statements of operations, are payable to the MGP and its affiliates as a 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,

2014

2013

2014

2013

2015

2014

Administrative fees

3436,~~100~~800

3433,~~800~~400

~~101,300~~

~~105,400~~

Supervision fees

~~170~~184,~~800~~500

~~174~~167,~~700~~200

~~507,600~~

~~528,400~~

Transportation fees

4840,~~000~~100

7677,000

~~197,000~~

~~240,100~~

Direct costs

9587,~~900~~500

~~103~~89,~~300~~800

~~274,900~~

~~273,500~~

Total

348,~~800~~900

~~388~~367,~~800~~400

~~1,080,800~~

~~1,147,400~~

NOTE 7 - 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 ~~September~~March 3031, ~~2014~~2015, the MGP has withheld $3445,~~400~~600 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 ~~collective~~respective ~~business~~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 America Series 27-2006 L.P. (“we”, “us”, or the “Partnership”) is a Delaware limited partnership, formed on July 21, 2006 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).

We have drilled and currently operate wells located in New York, Pennsylvania and Tennessee. We have no employees and rely on our MGP for management, which in turn, relies on its parent company, Atlas Energy (after February 27, 2015, 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 ~~September~~March 3031, ~~2014~~2015, our MGP has withheld $3445,~~400~~600 of net production ~~revenue~~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 ~~oil~~gas and ~~gas~~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~~2015 and ~~2013~~2014, we experienced no problems in selling our natural gas and oil. Product availability and price are the principal means of ~~competition~~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 EndedSeptember 30,						Nine Months EndedSeptember 30,
	Three Months Ended
	2014			2013			2014			2013
	March 31,
Production revenues (in thousands):
	2015			2014
Gas	$	341		$	529		$	1,477		$	1,639
Production revenues (in thousands):
Oil		22			20			67			55
Gas	$	290		$	585
Total	$	363		$	549		$	1,544		$	1,694
Oil		19			14
Production volumes:
Total	$	309		$	599
Gas (mcf/day) (1)		1,400			1,493			1,317			1,504
Production volumes:
Oil (bbl/day) (1)		3			2			3			2
Gas (mcf/day) (1)		1,257			1,250
Total (mcfe/day) (1)		1,418			1,505			1,335			1,516
Oil (bbl/day) (1)		4			1
Average sales prices(2):
Total (mcfe/day) (1)		1,281			1,256
Gas (per mcf) (1) (3) (5)	$	2.90		$	4.04		$	4.15		$	4.21
Average sales prices (2)
Oil (per bbl) (1) (4)	$	88.94		$	91.66		$	92.22		$	89.63
Gas (per mcf) (1) (3)	$	2.56		$	5.23
Production costs:
Oil (per bbl) (1)	$	49.29		$	89.73
As a percent of revenues (5)		77	%		61	%		61	%		58	%
Production costs:
Per mcfe (1)	$	2.31		$	2.42		$	2.59		$	2.39
As a percent of revenues		96	%		53	%
Depletion per mcfe	$	0.66		$	2.28		$	0.66		$	2.28
Per mcfe (1)	$	2.57		$	2.82
Depletion per mcfe	$	0.40		$	0.66

(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 were $53,~~700~~100 ~~and $25,900~~ for the three months ended ~~September~~March 3031, 2014 ~~and 2013, respectively~~. ~~Previously recognized derivative gains were $15,100 and $89,900 for the nine months ended September 30, 2014 and 2013, respectively.~~

Natural Gas Revenues. Our natural gas revenues were $290,100 and $585,100 for the three months ended March 31, 2015 and 2014, respectively, a decrease of $295,000 (450%). ~~Average~~The ~~oil~~$295,000 ~~prices~~decrease ~~are~~in ~~calculated~~natural bygas ~~including~~revenues infor ~~total~~the ~~revenue~~three ~~derivative~~months ~~gains~~ended ~~previously~~March ~~recognized~~31, ~~into~~2015 ~~income~~as incompared ~~connection~~to ~~with~~the prior year similar period ~~impairment~~was ~~charges~~attributable ~~and~~to ~~dividing~~a by$298,400 decrease in our natural gas sales prices after the ~~total~~effect ~~volume~~of financial hedges, which was driven by market conditions, partially offset by a $3,400 increase in production volumes. Our production volumes increased to 1,257 mcf per day for the ~~period.~~three ~~Previously~~months ~~recognized~~ended ~~derivative~~March ~~gains~~31, ~~were~~2015 ~~$100~~from 1,250 mcf per day for the ~~nine~~three months ended ~~September~~March 3031, ~~2013~~2014, an increase of 7 mcf per day (1%).

~~(5)~~Oil ~~The~~Revenues. ~~average~~We ~~sales~~drill ~~price~~wells ~~and~~primarily ~~production~~to ~~costs~~produce asnatural agas, ~~percent~~rather ofthan oil, but some wells have limited oil production. Our oil revenues ~~for~~were ~~natural~~$19,100 ~~gas~~and $14,300 for the three months ended ~~September~~March 3031, 2015 and 2014, ~~has~~respectively, ~~been~~an ~~adjusted~~increase toof ~~reflect~~$4,800 (34%). The $264,800 ofincrease ~~additional~~in ~~revenue~~oil revenues for the three months ended March 31, ~~(See~~2015 ~~Item~~as compared to the prior year similar period was attributable to a $20,500 increase in production volumes, partially offset by a $15,700 decrease in oil prices after the effect of financial hedges. Our production volumes increased to 4: ~~Controls~~bbls ~~and~~per ~~Procedures)~~day for ~~additional~~the ~~information~~three months ended March 31, 2015 from 1 bbl per day for the three months ended March 31, 2014, an increase of 3 bbl per day.

20Costs and Expenses. Production expenses were $297,200 and $319,400 for the three months ended March 31, 2015 and 2014, respectively, a decrease of $22,200 (7%). This decrease was mostly attributable to lower transportation expenses from a decrease in production volumes.

Natural Gas Revenues. During the current year quarter, management identified a material weakness in the process used to estimate our unbilled revenue (See Item 4: Controls and Procedures). As a result, natural gas revenue for the three months ending September 30, 2014 includes an adjustment to reduce natural gas revenue by $26,800. The adjustment is the result of overestimating our unbilled revenues as of June 30, 2014. Our unadjusted natural gas revenues were $367,900 and $528,400 for the three months ended September 30, 2014 and 2013, respectively, a decrease of $160,500 (30%). The $160,500 decrease in natural gas revenues for the three months ended September 30, 2014 as compared to the prior year similar period was attributable to a $127,900 decrease in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions and a $32,600 decrease in our production volumes. Our production volumes decreased to 1,400 mcf per day for the three months ended September 30, 2014 from 1,493 mcf per day for the three months ended September 30, 2013, a decrease of 93 mcf per day (6%). The overall decrease in natural gas production volumes for the three months ended September 30, 2014 as compared to the prior year similar period resulted primarily from the normal decline inherent in the life of a well. 18

~~Our~~Depletion ~~natural~~of gas ~~revenues were $1,476,900~~ and ~~$1,638,600~~oil ~~for~~properties ~~the~~as ~~nine months ended September 30, 2014 and 2013, respectively,~~ a ~~decrease~~percentage of ~~$161,700~~gas ~~(10%).~~and ~~The~~oil ~~$161,700 decrease in natural gas~~ revenues ~~for the nine months ended September 30, 2014 as compared to the prior year similar period~~ was attributable to a $203,400 decrease in production volumes, partially offset by a $41,700 increase in our natural gas sales prices after the effect of financial hedges, which was driven by market conditions, including the reversal of $15~~,100~~% and ~~$89,900~~13% ~~previously recognized derivative gains~~ for the ~~nine~~three months ended ~~September~~March 3031, ~~2014~~2015 and ~~2013~~2014, respectively. ~~Our~~This ~~production~~change ~~volumes~~was ~~decreased~~primarily attributable to ~~1,317~~changes ~~mcf~~in ~~per~~gas ~~day~~and ~~for~~oil ~~the~~reserve ~~nine~~quantities ~~months~~and ~~ended~~to ~~September~~a ~~30,~~lesser ~~2014~~extent ~~from 1~~revenues,~~504~~ ~~mcf~~product ~~per~~prices ~~day~~and ~~for the nine months ended September 30, 2013, a decrease of 187 mcf per day (12%). The overall decrease in natural gas~~ production volumes ~~for~~and ~~the~~changes ~~nine~~in ~~months ended September 30, 2014 as compared to~~ the ~~prior~~depletable ~~year~~cost ~~similar~~basis ~~period~~of ~~resulted~~gas ~~primarily~~and ~~from~~oil ~~the normal decline inherent in the life of a well~~properties.

~~Oil~~General ~~Revenues.~~and Weadministrative ~~drill~~expenses ~~wells~~for ~~primarily~~the tothree ~~produce~~months ~~natural~~ended ~~gas,~~March ~~rather than oil~~31, ~~but~~2015 ~~some~~and ~~wells~~2014 ~~have limited oil production. Our oil revenues~~ were $2151,~~800~~700 and $2048,~~200 for the three months ended September 30~~000, ~~2014 and 2013,~~ respectively, an increase of $13,~~600~~700 (8%). ~~The~~These ~~$1,600~~expenses ~~increase~~include inthird-party ~~oil~~costs ~~revenues~~ for ~~the~~services ~~three~~as ~~months~~well ~~ended September 30, 2014~~ as ~~compared to~~ the ~~prior~~monthly ~~year~~administrative ~~similar~~fees ~~period~~charged ~~was attributable to a $2,300 increase in production volumes, partially offset~~ by aour ~~$700~~MGP ~~decrease~~and invary ~~oil~~from ~~prices~~period ~~after~~to ~~the~~period ~~effect~~due ~~of financial hedges. Our production volumes increased~~ to ~~2.66 bbls per day for~~ the ~~three~~costs ~~months~~charged ~~ended~~to ~~September~~us ~~30,~~and ~~2014~~services ~~from~~provided ~~2.39~~to ~~bbls per day for the three months ended September 30, 2013, an increase of 0~~us.27 ~~bbls per day (11%).~~

Our oil revenues were $67,100 and $55,200 for the nine months ended September 30, 2014 and 2013, respectively, an increase of $11,900 (22%). The $11,900 increase in oil revenues for the nine months ended September 30, 2014 as compared to the prior year similar period was attributable to a $9,900 increase in production volume and a $2,000 increase in oil prices after the effect of financial hedges. Our production volumes increased to 2.66 bbls per day for the nine months ended September 30, 2014 from 2.26 bbls per day for the nine months ended September 30, 2013, an increase of 0.40 bbls per day (18%).

Costs and Expenses. Production expenses were $301,600 and $335,300 for the three months ended September 30, 2014 and 2013, respectively, a decrease of $33,700 (10%). Production expenses were $943,700 and $990,400 for the nine months ended September 30, 2014 and 2013, respectively, a decrease of $46,700 (5%). The decreases for the three and nine months ended September 30, 2014 was mostly due to a decrease in transportation fees as a result of lower revenues and a decrease in well supervision fees.

Depletion of oil and gas properties as a percentage of oil and gas revenues was 24% and 58% for the three months ended September 30, 2014 and 2013, respectively, and 16% and 56% for the nine months ended September 30, 2014 and 2013, respectively. These changes are primarily attributable to changes in oil and gas reserve quantities and to a lesser extent revenues, 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, 2014 and 2013 were $47,200 and $53,500, respectively, a decrease of $6,300 (12%). For the nine months ended September 30, 2014 and 2013, these expenses were $137,100 and $157,000, respectively, a decrease of $19,900 (13%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP. The decrease for the three and nine months ended September 30, 2014 are primarily due to third-party costs as compared to the prior year similar period.

Liquidity and Capital Resources

Cash provided by operating activities decreased $~~182~~110,~~800~~000 in the ~~nine~~three months ended ~~September~~March 3031, ~~2014~~2015 to ~~$512,800~~zero as compared to $~~695~~110,~~600~~000 for the ~~nine~~three months ended ~~September~~March 3031, ~~2013~~2014. This decrease was ~~primarily~~mostly due to a decrease in ~~the~~ net ~~earnings~~income before depletion, accretion, and a non-cash (gains) loss on derivative value of $~~158~~276,~~000~~700, a decrease in the change in accrued liabilities of $116,~~200~~900, and a decrease in the change in asset retirement receivable-affiliate of $3411,~~400,~~200. ~~the~~The ~~change~~decrease inwas ~~asset retirement obligations settled of $300,~~ partially offset by an increase in the change in accounts receivable ~~trade~~-trade affiliate of $21184,~~100~~800 for the ~~nine~~three months ended ~~September~~March 3031, ~~2014~~2015 compared to the ~~nine~~three months ended ~~September~~March 3031, ~~2013~~2014.

21Cash used in financing activities was $172,800 for the three months ended March 31, 2014, due to cash distributions to partners. There was no cash used in financing activities for the three months ended March 31, 2015.

~~Cash~~Our ~~used~~MGP inmay ~~financing~~withhold ~~activities~~funds ~~decreased~~for ~~$148,900~~future ~~during~~plugging ~~the~~and ~~nine~~abandonment ~~months~~costs. ~~ended~~Through ~~September~~March 31, 302015, ~~2014~~our toMGP has withheld $~~575~~45,600 ~~from~~of ~~$724,500~~funds for ~~the~~this ~~nine~~purpose. ~~months~~Any ~~ended~~additional ~~September~~funds, 30if required, ~~2013.~~will ~~This~~be ~~decrease~~obtained ~~was~~from ~~due~~production torevenues aor ~~decrease~~borrowings infrom ~~cash~~our ~~distributions~~MGP or its affiliates, which are not contractually committed to ~~partners~~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.

~~Any~~We ~~additional~~are ~~funds,~~generally iflimited ~~required,~~to ~~will~~the beamount ~~obtained~~of ~~from~~funds ~~production~~generated ~~revenues~~by orthe ~~borrowings~~cash flows from our ~~MGP or its affiliates~~operations, which ~~are~~we ~~not~~believe ~~contractually~~is ~~committed~~adequate to ~~make~~fund ~~loans~~future tooperations ~~us.~~and ~~The~~distributions ~~amount~~to ~~that~~our wepartners. ~~may~~Historically, ~~borrow~~there athas ~~any~~been ~~one~~no ~~time~~need ~~may~~to ~~not~~borrow atfunds ~~any~~from ~~time exceed 5% of~~ our ~~total~~MGP ~~subscriptions~~to ~~and~~fund ~~we will not borrow from third-parties~~operations.

The Partnership is generally limited to the amount of funds generated by the cash flows from our operations, which we believe is adequate to fund future operations and distributions to our partners. Historically, there has been no need to borrow funds from our MGP to fund operations.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations is based upon our financial statements, which have been prepared in accordance with ~~accounting~~U.S. ~~principles generally accepted in the United States of America~~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 and followed in the preparation of our financial statements is included within “Notes to Financial Statements” in Part I, Item 1, “Financial Statements” in this quarterly report and in our Annual Report on Form 10-K for the year ended December 31, ~~2013~~2014.

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 ~~Chairman~~general ofpartner’s ~~the Board of Directors,~~ Chief Executive Officer, ~~President~~ 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 Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, 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 on that evaluation, our Chief Executive Officer, President and Chief Financial Officer concluded that, as of September 30, 2014, our disclosure controls and procedures were effective at the reasonable assurance level.19

~~During~~Under the ~~current~~supervision ~~period,~~of ~~but~~our ~~before~~general ~~the~~partner’s ~~June~~Chief ~~30,~~Executive ~~2014~~Officer ~~Form~~and ~~10-Q~~Chief ~~was~~Financial ~~filed,~~Officer ~~management~~and ~~identified~~with athe ~~deficiency~~participation inof our disclosure ~~controls~~committee ~~and~~appointed ~~procedures.~~by ~~Language~~such ~~indicating~~officers, ~~management’s~~we ~~conclusion~~have oncarried ~~the~~out ~~Company’s~~an ~~internal~~evaluation ~~control~~of ~~over~~the ~~financial~~effectiveness ~~reporting as~~ of ~~December~~our ~~31,~~disclosure ~~2013~~controls ~~was not included in Management’s Report on Internal Control over Financial Reporting within Form 10-K, Item 9A. “Controls~~ and ~~Procedures.”~~procedures Asas aof ~~result~~the end of the ~~amendment~~period ~~required~~covered toby ~~our~~this ~~December~~report. Based ~~31,~~upon ~~2013~~that ~~Form 10-K~~evaluation, our ~~Chairman~~general ofpartner’s ~~the Board of Directors,~~ Chief Executive Officer, ~~President~~ and Chief Financial Officer concluded that, as of ~~June~~March 3031, ~~2014~~2015, our disclosure controls and procedures were ~~not~~ effective at the reasonable assurance level.

As of the date of filing of this Form 10-Q, management has implemented a more formal and thorough review of its disclosures in Form 10-K, Item 9A and Form 10-Q, Item 4: Controls and Procedures. As of the date of filing of this Form 10-Q, management believes the deficiency in the Partnership’s disclosure controls and procedures has been remediated.

Changes in Internal Control over Financial Reporting

~~During~~There ~~the~~have ~~current~~been ~~quarter,~~no ~~management~~changes ~~identified a material weakness~~ in the ~~process~~Partnership’s ~~used~~internal tocontrol ~~estimate~~over ~~the~~financial ~~June~~reporting ~~30,~~during ~~2014~~our ~~unbilled~~most ~~revenue.~~recent ~~The~~fiscal ~~weakness~~quarter ~~resulted from an insufficient review of contract pricing information used to estimate unbilled revenue. As a result, a change in a pricing index of a marketing contract~~ that ~~was~~have ~~not~~materially ~~properly reflected in the estimate of unbilled revenues. At June 30~~affected, ~~2014,~~or ~~the~~are ~~Partnership~~reasonably ~~overestimated~~likely ~~its~~to ~~unbilled~~materially ~~revenues by $26~~affect,~~800~~ ~~and~~our ~~the~~internal ~~adjustment~~control ~~had~~over nofinancial ~~impact on cash distributions~~reporting.

As of the date of filing this Form 10-Q, management has implemented a more formal and thorough review of its pricing inputs used to calculate the estimated unbilled revenue. As of the date of filing of this Form 10-Q, management believes the deficiency in the Partnership’s internal control over financial reporting has been remediated.

Other than as previously discussed, there have been no changes in our 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

2320

ITEM 6.

EXHIBITS

EXHIBIT INDEX

Exhibit No.		Description
3.1		Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series 27-2006 L.P. (1)
4.2		Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series 27-2006 L.P. (1)
3.2	Agreement of Limited Partnership (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 April 30, 2007 in the Form S-1A Registration Statement dated April 30, 2007, File No. 000-52615

2421

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 America Series 27-2006 L.P.

	ATLAS AMERICA SERIES 27-2006 L.P.

	By: Atlas Resources, LLC, its Managing General Partner

Date: May 15, 2015	By:	/s/ FREDDIE M. KOTEK
		Freddie M. Kotek, Chief Executive Officer and President of the Managing General Partner

	ATLAS RESOURCES, LLC, Managing General Partner
Date: May 15, 2015		By:		/s/ SEAN P. MCGRATH
Date: November 14, 2014	By:		/s/ FREDDIE M. KOTEK
				Sean P. McGrath, Chief Financial Officer of the Managing General Partner
			Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President

~~In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.~~ 22

Date: November 14, 2014	By:		/s/ SEAN P. MCGRATH
			Sean P. McGrath, Chief Financial Officer

Filing Compare · Atlas America Series 27-2006 L.P.