Atlas America Series 27-2006 10-Q 2011 Q2 Quarterly report

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 June 30, 2011

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

For the transition period from                    to                    

Commission file number 0-52615

ATLAS AMERICA SERIES 27-2006 L.P.

(Name of small business issuer in its charter)

Delaware	20-5242075
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
Westpointe Corporate Center One
1550 Coraopolis Heights Road, 2nd Floor
Moon Township, PA	15108
(Address of principal executive offices)	(zip code)

Issuer’s telephone number, including area code:(412) 262-2830

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. YesþNoo

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). YesþNoo

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 filero Accelerated filero Non-accelerated filero Smaller reporting companyþ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

ATLAS AMERICA SERIES 27-2006 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
INDEX TO QUARTERLY REPORT

ON FORM 10-Q

	PAGE
PART I. FINANCIAL INFORMATION
Item 1: Financial Statements
Balance Sheets as of June 30, 2011 and December 31, 2010		3
Statements of Operations for the Three Months and Six Months ended June 30, 2011 and 2010		4
Statement of Changes in Partners’ Capital for the Six Months ended June 30, 2011		5
Statements of Cash Flows for the Six Months ended June 30, 2011 and 2010		6
Notes to Financial Statements		7-15
Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations		15-18
Item 4: Controls and Procedures		19
PART II. OTHER INFORMATION
Item 1: Legal Proceedings		19
Item 6: Exhibits		19
SIGNATURES		20
CERTIFICATIONS
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

2

ATLAS AMERICA SERIES 27-2006 L.P.

BALANCE SHEETS

	June 30,		December 31,
	2011		2010
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	157,700	$	260,100
Accounts receivable — affiliate		1,220,800		806,100
Short-term hedge receivable due from affiliate		—		754,600
Total current assets		1,378,500		1,820,800
					��
Oil and gas properties, net		10,490,400		11,056,400
Long-term hedge receivable due from affiliate		—		737,400
Long-term receivable-affiliate		431,500		—
	$	12,300,400	$	13,614,600
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	19,700	$	13,900
Short-term hedge liability due to affiliate		—		5,500
Total current liabilities		19,700		19,400
Asset retirement obligation		3,085,900		3,005,700
Long-term hedge liability due to affiliate		—		128,500
Partners’ capital:
Managing general partner		1,818,200		2,399,500
Limited partners (2,840 units)		6,885,400		7,682,100
Accumulated other comprehensive income		491,200		379,400
Total partners’ capital		9,194,800		10,461,000
	$	12,300,400	$	13,614,600

See accompanying notes to financial statements.

3

ATLAS AMERICA SERIES 27-2006 L.P.

STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2011		2010			2011		2010
REVENUES
Natural gas and oil	$	921,600	$	986,800		$	1,678,100	$	2,113,900
Total revenues		921,600		986,800			1,678,100		2,113,900
COSTS AND EXPENSES
Production		439,300		451,700			830,000		932,200
Depletion		315,900		396,000			566,000		877,200
Accretion of asset retirement obligation		45,100		33,600			90,200		67,100
General and administrative		50,900		67,500			120,200		123,800
Total expenses		851,200		948,800			1,606,400		2,000,300
Net income	$	70,400	$	38,000		$	71,700	$	113,600
Allocation of net income:
Managing general partner	$	14,900	$	75,300		$	36,600	$	176,200
Limited partners	$	55,500	$	(37,300	)	$	35,100	$	(62,600	)
Net income (loss) per limited partnership unit	$	19	$	(13	)	$	12	$	(22	)

See accompanying notes to financial statements.

4

ATLAS AMERICA SERIES 27-2006 L.P.

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE SIX MONTHS ENDED

June 30, 2011

(Unaudited)

							Accumulated
	Managing						Other
	General			Limited			Comprehensive
	Partner			Partners			Income		Total
Balance at January 1, 2011	$	2,399,500		$	7,682,100		$	379,400	$	10,461,000
Participation in revenues and expenses:
Net production revenues		200,900			647,200			—		848,100
Depletion		(95,800	)		(470,200	)		—		(566,000	)
Accretion of asset retirement obligation		(29,400	)		(60,800	)		—		(90,200	)
General and administrative		(39,100	)		(81,100	)		—		(120,200	)
Net income		36,600			35,100			—		71,700
Other comprehensive income		—			—			111,800		111,800
Subordination		(126,300	)		126,300			—		—
Distributions to partners		(491,600	)		(958,100	)		—		(1,449,700	)
Balance at June 30, 2011	$	1,818,200		$	6,885,400		$	491,200	$	9,194,800

See accompanying notes to financial statements.

5

ATLAS AMERICA SERIES 27-2006 L.P.

STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
	2011			2010
Cash flows from operating activities:
Net income	$	71,700		$	113,600
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion		566,000			877,200
Non-cash loss on hedge instruments		260,700			372,100
Accretion of asset retirement obligation		90,200			67,100
Decrease in accounts receivable-affiliate		91,400			485,500
Increase in accrued liabilities		5,800			5,100
Asset retirement obligation settled		(10,000	)		—
Net cash provided by operating activities		1,075,800			1,920,600
Cash flows from financing activities:
Distributions to partners		(1,178,200	)		(2,027,200	)
Net cash used in financing activities		(1,178,200	)		(2,027,200	)
Net decrease in cash and cash equivalents		(102,400	)		(106,600	)
Cash and cash equivalents at beginning of period		260,100			377,600
Cash and cash equivalents at end of period	$	157,700		$	271,000
Supplemental schedule of non-cash financing activities:
Distribution to Managing General Partner	$	271,500		$	—

See accompanying notes to financial statements.

6

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

NOTE 1 — DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Atlas America Series 27-2006 L.P. (the “Partnership”) is a Delaware limited partnership and formed on July 21, 2006 with Atlas Resources, LLC serving as its Managing General Partner and operator (“Atlas Resources” or “MGP”). Atlas Resources is an indirect subsidiary of Atlas Energy, L.P., formerly Atlas Pipeline Holdings, L.P. (“Atlas Energy”) (NYSE: ATLS). On February 17, 2011, Atlas Energy, a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of Atlas Pipeline Partners, L.P. (“APL”) (NYSE: 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, and certain well interests in Pennsylvania and Michigan; and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities.

Atlas Resources’ focus is on the development and/or production of natural gas and oil in the Appalachian, Michigan, Illinois, and/or Colorado basin regions of the United States of America. Atlas Resources is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy Resource Services, Inc. provides Atlas Resources with the personnel necessary to manage its assets and raise capital.

The accompanying financial statements, which are unaudited except that the balance sheet at December 31, 2010 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 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, 2010. The results of operations for the three and six months ended June 30, 2011 may not necessarily be indicative of the results of operations for the year ended December 31, 2011.

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, 2010 filed with the Securities and Exchange Commission (“SEC”).

Use of Estimates

Preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 revenue 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.

7

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Use of Estimates (Continued)

The natural gas industry principally conducts its business by processing actual transactions as much 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 six months ended June 30, 2011 and 2010 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).

Accounts Receivable and Allowance for Possible Losses

In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of the Partnership’s customers’ credit information. Credit is extended on an unsecured basis to many of its energy customers. At June 30, 2011 and December 31, 2010, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.

Oil and Gas Properties

Oil and gas properties are stated at cost. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized. The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel equals 6 Mcf.

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 costs of developed producing properties. Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the 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.

	June 30,			December 31,
	2011			2010
Proved properties:
Leasehold interests		1,687,400		$	1,687,400
Wells and related equipment		86,251,900			86,251,900
		87,939,300			87,939,300
Accumulated depletion		(77,448,900	)		(76,882,900	)
Oil and gas properties, net	$	10,490,400		$	11,056,400

8

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 for that asset to its estimated fair value if such carrying amount exceeds the fair value.

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

The determination of oil and natural gas 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 was no impairment charge recognized during the three and six months ended June 30, 2011. During the year ended December 31, 2010, the Partnership recognized an impairment charge of $5,196,300, net of an offsetting gain in accumulated other comprehensive income of $326,800.

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.

9

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue Recognition

The Partnership generally sells natural gas and crude oil at prevailing market prices. Revenue is 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 the Partnership’s percentage ownership of working interest. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil 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 fees which are, in turn, based upon applicable product prices (see “Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at June 30, 2011 and December 31, 2010 of $506,600 and $582,900, respectively, which are included in accounts receivable — affiliate within the Partnership’s balance sheets.

Recently Adopted Accounting Standards

In June 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. Update 2011-05 amends the FASB Accounting Standards Codification to provide an entity with the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with a total net income, each component of other comprehensive income, and a total amount for comprehensive income. Update 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in partners’ capital. These changes apply to both annual and interim financial statements. Update 2011-05 will be effective for public entities’ fiscal years, and interim periods within those years, beginning after December 15, 2011. The Partnership will apply the requirements of Update 2011-05 upon its effective date of January 1, 2012, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

NOTE 3 — ASSET RETIREMENT OBLIGATION

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 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 estimates of plugging and abandonment costs or remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its oil and gas properties, the Partnership has determined that there are no other material retirement obligations associated with tangible long-lived assets.

10

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)

NOTE 3 — ASSET RETIREMENT OBLIGATION (Continued)

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011			2010
Asset retirement obligation at beginning of period	$	3,040,800	$	2,269,000	$	3,005,700		$	2,235,500
Liabilities settled		—		—		(10,000	)		—
Accretion expense		45,100		33,600		90,200			67,100
Asset retirement obligation at end of period	$	3,085,900	$	2,302,600	$	3,085,900		$	2,302,600

NOTE 4 — DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, used a number of different derivative instruments, principally swaps and collars, in connection with its commodity price risk management activities. The MGP entered into financial instruments to hedge the Partnership’s forecasted natural gas and crude oil 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 natural gas and crude oil is sold. Under swap agreements, the Partnership received or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas and crude oil at a fixed price for the relevant contract period.

Historically, the MGP has entered into natural gas and crude oil future option contracts and collar contracts on behalf of the Partnership to achieve more predictable cash flows by hedging its exposure to changes in natural gas and oil 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 delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

The MGP formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. The MGP assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the MGP will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the MGP through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive income and reclassifies the portion relating to commodity derivatives to gas and oil production revenues for the Partnership’s derivatives within the Partnership’s statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within gain (loss) on mark-to-market derivatives in its statements of operations as they occur.

11

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)

NOTE 4 — DERIVATIVE INSTRUMENTS (Continued)

Prior to the acquisition on February 17, 2011 of “the Transferred Business”, Atlas Energy, Inc. monetized its derivative instruments related to the Transferred Business. The monetized proceeds relate to instruments that were originally put into place to hedge future natural gas and oil production of the Transferred Business, including production generated through its Drilling Partnerships. At June 30, 2011, the Partnership recorded a net receivable from the monetized derivative instruments of $506,100 in accounts receivable-affiliate and $431,500 in long-term receivable-affiliate with the corresponding net unrealized gains in accumulated other comprehensive income on the Partnership’s balance sheets, which will be allocated to natural gas and oil production revenue generated over the period of the original instruments’ contracts. As a result of the monetization and the early settlement of natural gas and oil derivative instruments and the unrealized gains recognized in income in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred gain on its balance sheets in other comprehensive income of $491,200 as of June 30, 2011. Unrealized gains, net of the MGP’s interest, previously recognized into income as a result of prior period impairments included in accumulated other comprehensive income were $105,900 and $340,500 for the year ended December 31, 2010 and prior periods, respectively. The MGP’s portion of the unrealized gains was written-off as part of the terms related to the acquisition of the Transferred Business. For the six months ended June 30, 2011, the Partnership reclassified $271,500 of unrealized gains previously recognized into income from prior period impairments related to the MGP from a hedge receivable due from affiliate to a non-cash distribution to the MGP. As such, $271,500 was recorded as a distribution to partners on the statement of changes in partners’ capital. During the six months ended June 30, 2011, $230,700 of monetized proceeds were recorded by the Partnership and allocated only to the limited partners. Of the remaining $491,200 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $257,200 of net gains to the Partnership’s statements of operations over the next twelve month period and the remaining $234,000 in later periods.

The following table summarizes the fair value of the Partnership’s derivative instruments as of December 31, 2010, as well as the gain or loss recognized in the statements of operations for the three and six months ended June 30, 2011 and 2010:

		Fair Value
	Balance Sheet	December 31,
Derivatives in Cash Flow Hedging Relationships	Location	2010
Commodity Contracts	Current assets	$	754,600
	Long-term assets		737,400
			1,492,000
	Current liabilities		(5,500	)
	Long-term liabilities		(128,500	)
			(134,000	)
	Total	$	1,358,000

Effects of Derivative Instruments on Statements of Operations:

		Three Months Ended					Six Months Ended
		June 30,		June 30,			June 30,		June 30,
		2011		2010			2011		2010
Derivative in Cash Flow Hedging Relationships	Gain Recognized in OCI on Derivatives
	Commodity Contracts	$	—	$	(125,600	)	$	72,200	$	1,219,700

		Three Months Ended				Six Months Ended
		June 30,		June 30,		June 30,		June 30,
		2011		2010		2011		2010
Location of Gain Reclassified from Accumulated OCI into Income	Gain Reclassified from OCI into Net Income
	Gas and Oil Revenue	$	116,300	$	90,500	$	324,500	$	355,900

12

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)

NOTE 5 — COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) includes net 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 accounting principles generally accepted in the United States of America, have not been recognized in the calculation of net income. These changes, other than net income, are referred to as “other comprehensive income (loss)” and for the Partnership includes changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges, and changes in the estimated amount of future monetized proceeds to be received (See Note 4). The monetized proceeds included in accounts receivable affiliate have been allocated to the Partnership based on estimated future production in relation to all other Partnerships’ future production eligible to receive monetized hedge proceeds. As actual production is realized, there may be a corresponding difference in the Partnership’s actual share of monetized hedge proceeds received, than what was previously estimated. This component is shown as “Difference in estimated monetized gains receivable.” The following table sets forth the calculation of the Partnership’s comprehensive income (loss):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Net income	$	70,400		$	38,000		$	71,700		$	113,600
Other comprehensive income (loss):
Unrealized holding gain (loss) on hedging contracts		—			(125,600	)		72,200			1,219,700
MGP portion of non-cash loss on hedge instruments		—			—			271,500			—
Difference in estimated monetized gains receivable		55,700			—			92,600			—
Less: reclassification adjustment for gains realized in net income		(116,300	)		(90,500	)		(324,500	)		(355,900	)
Total other comprehensive (loss) income		(60,600	)		(216,100	)		111,800			863,800
Comprehensive income (loss)	$	9,800		$	(178,100	)	$	183,500		$	977,400

NOTE 6 — 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. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Quoted prices in active markets for identical 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 entities own assumptions about the assumptions that 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.

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ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)

NOTE 6 — FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership used a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 4). The Partnership’s commodity derivative contracts were valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.

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

The Partnership estimates the fair value of asset retirement obligations using Level 3 inputs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements; the credit-adjusted risk-free rate of the Partnership; and estimated inflation rates (see Note 3).

NOTE 7 — TRANSACTIONS WITH ATLAS RESOURCES, LLC AND ITS AFFILIATES

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. Administrative costs incurred for the three and six months ended June 30, 2011 were $39,700 and $78,100, respectively. Administrative costs incurred for the three and six months ended June 30, 2010 were $41,400 and $83,600, respectively.

• Monthly well supervision fees which are included in production expenses in the Partnership’s statements of operations are payable at $376 per well per month for operating and maintaining the wells. Well supervision fees incurred, for the three and six months ended June 30, 2011 were $199,100 and $391,700, respectively. Well supervision fees incurred for the three and six months ended June 30, 2010 were $207,600 and $419,000, respectively.

• Transportation fees which are included in production expenses in the Partnership’s statements of operations are generally payable at 13% of the natural gas sales price. Transportation fees incurred for the three and six months ended June 30, 2011 were $127,500 and $239,100, respectively. Transportation fees incurred for the three and six months ended June 30, 2010 were $149,200 and $303,400, respectively.

The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable-affiliate on the Partnership’s balance sheets represents the net production revenues due from the MGP.

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ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)

NOTE 7 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS (Continued)

Subordination by Managing General Partner

Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues of the Partnership to provide a distribution to the limited partners equal to at least 10% of their agreed subscriptions. Subordination is determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution of net revenues to the limited partners (July 2007). For the three months ended June 30, 2011, the MGP was required to subordinate $126,300. Therefore, MGP capital was decreased and the limited partners’ capital was increased by $126,300 as shown on the statement of changes in partners’ capital for the three months ended June 30, 2011.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (UNAUDITED)

Forward-Looking Statements

When used in thisForm 10-Q, the words “believes,” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. These risks and uncertainties 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 thisForm 10-Q or to reflect the occurrence of unanticipated events.

Management’s Discussion and Analysis should be read in conjunction with our Financial Statements and the Notes to our Financial Statements.

Overview

The following discussion provides information to assist in understanding our financial condition and result 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 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 managing general partner, 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 managing general partner or its affiliates. Also, beginning one year after each of our wells has been placed into production our managing general partner, as operator, may retain $200 per month, per well to cover the estimated future plugging and abandonment costs of the well. As of June 30, 2011, our managing general partner had not withheld any funds for this purpose. Our managing general partner intends to produce our wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling.

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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 and gas 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 managing general partner is responsible for selling our natural gas production. During 2011 and 2010, we experienced no problems in selling our natural gas and oil. Product availability and price are the principal means of competition 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.

We have drilled and currently operate wells located in Pennsylvania, Tennessee, and New York. We have no employees and rely on our MGP for management, which in turn, relies on its parent company, Atlas Energy Holdings Operating Company, LLC for administrative services.

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						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Production revenues (in thousands):
Gas	$	886		$	974		$	1,612		$	2,081
Oil		36			13			66			33
Total	$	922		$	987		$	1,678		$	2,114
Production volumes:
Gas (mcf/day)(1)		1,934			1,798			1,738			1,997
Oil (bbls/day)(1)		5			3			4			4
Total (mcfe/day)(1)		1,964			1,816			1,762			2,021
Average sales prices:(2)
Gas (per mcf)(1) (3)	$	5.69		$	7.32		$	5.94		$	6.74
Oil (per bbl)(1) (4)	$	86.63		$	74.24		$	88.92		$	70.89
Average production costs:
As a percent of revenues		48	%		46	%		49	%		44	%
Per mcfe(1)	$	2.46		$	2.73		$	2.60		$	2.55
Depletion per mcfe	$	1.77		$	2.39		$	1.77		$	2.40

(1)	“Mcf” represents thousand cubic feet, “mcfe” represents thousand cubic feet equivalent, and “bbls” represents barrels. Bbls are converted to mcfe using the ratio of six mcfs to one bbl.
(2)	Average sales prices represent accrual basis pricing after reversing the effect of previously recognized gains resulting from prior period impairment charges.

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(3)

Average gas prices are calculated by including in total revenue derivative losses previously recognized into income and dividing by the total volume for the period. Previously recognized derivative losses were $115,600 and $223,900 for the three months ended June 30, 2011 and 2010, respectively. Previously recognized derivative losses were $258,300 and $355,900 for the six months ended June 30, 2011 and 2010, respectively. The derivative losses are included in other comprehensive income (loss) and resulted from prior period impairment charges.

(4)

Average oil prices are calculated by including in total revenue derivative losses previously recognized into income and dividing by the total volume for the period. Previously recognized derivative losses were $1,000 and $9,200 for the three months ended June 30, 2011 and 2010, respectively. Previously recognized derivative losses were $2,400 and $16,200 for the six months ended June 30, 2011 and 2010, respectively. The derivative losses are included in other comprehensive income (loss) and resulted from prior period impairment charges.

Natural Gas Revenues.Our natural gas revenues were $886,000 and $973,900 for the three months ended June 30, 2011 and 2010, respectively, a decrease of $87,900 (9%). The $87,900 decrease in natural gas revenues for the three months ended June 30, 2011 as compared to the prior year similar period was attributable to a $161,800 decrease in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions partially offset by a $73,900 increase in production volumes. Our production volumes increased to 1,934 mcf per day for the three months ended June 30, 2011 from 1,798 mcf per day for the three months ended June 30, 2010, an increase of 136 mcf per day (8%). Our production volumes increased for the three months ended June 30, 2011 due to certain wells being moved to a new gathering system.

Our natural gas revenues were $1,611,900 and $2,080,900 for the six months ended June 30, 2011 and 2010, respectively, a decrease of $469,000 (23%). The $469,000 decrease in natural gas revenues for the six months ended June 30, 2011 as compared to the prior year similar period was attributable to a $268,900 decrease in production volumes and a $200,100 decrease in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions. Our production volumes decreased to 1,738 mcf per day for the six months ended June 30, 2011 from 1,997 mcf per day for the six months ended June 30, 2010, a decrease of 259 mcf per day (13%). The overall decrease in natural gas production volumes for the six months ended June 30, 2011 resulted primarily from the normal decline inherent in the life of a well.

Oil Revenues.We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $35,600 and $12,900 for the three months ended June 30, 2011 and 2010, respectively, an increase of $22,700 (176%). The $22,700 increase in oil revenues for the three months ended June 30, 2011 as compared to the prior year similar period was attributable to a $17,300 increase in oil prices after the effect of financial hedges and a $5,400 increase in production volumes. Our production volumes increased to 5 bbls per day for the three months ended June 30, 2011 from 3 bbls per day for the three months ended June 30, 2010, an increase of 2 bbls per day (67%).

Our oil revenues were $66,200 and $33,000 for the six months ended June 30, 2011 and 2010, respectively, an increase of $33,200 (101%). The $33,200 increase in oil revenues for the six months ended June 30, 2011 as compared to the prior year similar period was attributable to a $29,500 increase in oil prices after the effect of financial hedges and a $3,700 increase in production volumes. Our production volumes increased to 4.25 bbls per day for the six months ended June 30, 2011 from 3.83 bbls per day for the six months ended June 30, 2010, an increase of .42 bbls per day (11%).

Costs and Expenses.Production expenses were $439,300 and $451,700 for the three months ended June 30, 2011 and 2010, respectively, a decrease of $12,400 (3%). Production expenses were $830,000 and $932,200 for the six months ended June 30, 2011 and 2010, respectively, a decrease of $102,200 (11%). These decreases for the three and six months ended June 30, 2011 were due to lower transportation fees.

Depletion of oil and gas properties as a percentage of oil and gas revenues were 34% and 40% for the three months ended June 30, 2011 and 2010, respectively; and 34% and 41% for the six months ended June 30, 2011 and 2010, respectively. These percentage changes are directly attributable to changes in revenues, oil and gas reserve quantities, product prices and production volumes and changes in the depletable cost basis of oil and gas properties.

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General and administrative expenses for the three months ended June 30, 2011 and 2010 were $50,900 and $67,500, respectively, a decrease of $16,600 (25%). For the six months ended June 30, 2011 and 2010 these expenses were $120,200 and $123,800, respectively, a decrease of $3,600 (3%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP. These decreases for the three and six months ended June 30, 2011 were primarily due to lower third-party costs as compared to the prior year similar period.

Liquidity and Capital Resources

Cash provided by operating activities decreased $844,800 in the six months ended June 30, 2011 to $1,075,800 as compared to $1,920,600 for the six months ended June 30, 2010. This decrease was due to a decrease in net income, depletion, net non-cash loss on hedge instruments and accretion of $441,400. In addition, the change in accounts receivable-affiliate of $394,100 and a settlement of an asset retirement obligation of $10,000 decreased operating cash flows. The decrease was partially offset by the change in accrued liabilities increasing operating cash flows by $700 for the six months ended June 30, 2011 as compared to the six months ended June 30, 2010.

Cash used in financing activities decreased $849,000 during the six months ended June 30, 2011 to $1,178,200 from $2,027,200 for the six months ended June 30, 2010. 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, 2011, our MGP had not withheld any 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 may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

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.

Subordination by Managing General Partner

Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of production revenues of the Partnership to the benefit of the limited partners for an amount equal to at least 10% of their net subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the investor partners (July 2007) and expiring 60 months from that date. For the six months ended June 30, 2011, the MGP was required to subordinate $126,300. Therefore MGP capital was decreased and the limited partners’ capital was increased by $126,300 as shown on the Statement of Changes in Partners’ Capital for the six months ended June 30, 2011.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. 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 our 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, 2010.

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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 MGP’s Chairman of 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 MGP’s 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 upon that evaluation, our MGP’s Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, concluded that, at June 30, 2011, 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 effect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Managing General Partner is not aware of any legal proceedings filed against the Partnership.

Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their collective business. 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 6. EXHIBITS

EXHIBIT INDEX

Exhibit No.	Description
4.0	Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series 27-2006 L.P.(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-1 Registration Statement dated April 30, 2007, File No. 000-52615.

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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 RESOURCES, LLC, Managing General Partner
Date: August 12, 2011	By:	/s/ FREDDIE M. KOTEK
		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 person on behalf of the registrant and in the capacities and on the dates indicated.

Date: August 12, 2011	By:	/s/ SEAN P. MCGRATH
		Sean P. McGrath, Chief Financial Officer

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