Atlas America Series 27-2006 10-Q 2009 Q2 Quarterly report

	United States
	Securities and Exchange Commission
	Washington, D.C. 20549
	Form 10-Q
(Mark One)
R	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2009
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 incorporation or organization)		(I.R.S. Employer 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.  YesR No o
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 o No R
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", 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 R
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No R
Transitional Small Business Disclosure Format (check one): Yes o No R

ATLAS AMERICA SERIES 27-2006 L.P.

(A Delaware Limited Partnership)

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

PART I.	FINANCIAL INFORMATION	PAGE
Item 1:	Financial Statements
	Balance Sheets as of June 30, 2009 and December 31, 2008	3
	Statements of Net Earnings for the Three Months and Six Months ended June 30, 2009 and 2008	4
	Statement of Changes in Partners’ Capital for the Six Months ended June 30, 2009	5
	Statements of Cash Flows for the Six Months ended June 30, 2009 and 2008	6
	Notes to Financial Statements	7-17
Item 2:	Management’s Discussion and Analysis of Financial Condition or Plan of Operations	17-22
Item 4:	Controls and Procedures	22-23
PART II.	OTHER INFORMATION
Item 6:	Exhibits	23
SIGNATURES		24
CERTIFICATIONS		25-28

2

ATLAS AMERICA SERIES 27-2006 L.P.

BALANCE SHEETS

	June 30,			December 31,
	2009			2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	420,000		$	661,800
Accounts receivable – affiliate		1,446,700			2,478,800
Short-term hedge receivable due from affiliate		1,071,500			2,431,800
Total current assets		2,938,200			5,572,400
Oil and gas properties, net		18,681,000			19,685,600
Long-term hedge receivable due from affiliate		644,300			1,539,700
	$	22,263,500		$	26,797,700
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	25,800		$	22,200
Short-term hedge liability due to affiliate		3,500			214,100
Total current liabilities		29,300			236,300
Asset retirement obligation		2,073,400			2,013,000
Long-term hedge liability due to affiliate		161,900			192,700
Partners’ capital:
Managing general partner		4,561,400			5,760,400
Limited partners (2,840 units)		16,205,000			18,595,300
Accumulated other comprehensive loss		(767,500	)		—
Total partners' capital		19,998,900			24,355,700
	$	22,263,500		$	26,797,700

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

3

ATLAS AMERICA SERIES 27-2006 L.P.

STATEMENTS OF NET EARNINGS

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
REVENUES
Natural gas and oil	$	1,025,500		$	3,527,800		$	2,498,300		$	7,483,400
Total revenues		1,025,500			3,527,800			2,498,300			7,483,400
COSTS AND EXPENSES
Production		528,900			771,200			1,114,700			1,761,800
Depletion		466,900			2,222,400			985,500			4,782,600
Accretion of asset retirement obligation		30,200			24,000			60,400			(42,400	)
General and administrative		55,500			83,500			116,500			147,200
Total expenses		1,081,500			3,101,100			2,277,100			6,649,200
Net (loss) earnings	$	(56,000	)	$	426,700		$	221,200		$	834,200
Allocation of net earnings (loss):
Managing general partner	$	55,300		$	513,300		$	227,300		$	1,083,200
Limited partners	$	(111,300	)	$	(86,600	)	$	(6,100	)	$	(249,000	)
Net loss per limited partnership unit	$	(39	)	$	(31	)	$	(2	)	$	(88	)

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

4

ATLAS AMERICA SERIES 27-2006 L.P.

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE SIX MONTHS ENDED

June 30, 2009

(Unaudited)

							Accumulated
	Managing						Other
	General			Limited			Comprehensive
	Partner			Partners			Loss			Total
Balance at January 1, 2009	$	5,760,400		$	18,595,300		$	—		$	24,355,700
Participation in revenues and expenses:
Net production revenues		451,100			932,500			—			1,383,600
Depletion		(166,100	)		(819,400	)		—			(985,500	)
Accretion of asset retirement obligation		(19,700	)		(40,700	)		—			(60,400	)
General and administrative		(38,000	)		(78,500	)		—			(116,500	)
Net earnings (loss)		227,300			(6,100	)		—			221,200
Asset contributions		(19,100	)		—			—			(19,100	)
Other comprehensive loss		—			—			(767,500	)		(767,500	)
Subordination		(534,600	)		534,600			—			—
Distributions to partners		(872,600	)		(2,918,800	)		—			(3,791,400	)
Balance at June 30, 2009	$	4,561,400		$	16,205,000		$	(767,500	)	$	19,998,900

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

5

ATLAS AMERICA SERIES 27-2006 L.P.

STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
	2009			2008
Cash flows from operating activities:
Net earnings	$	221,200		$	834,200
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depletion, depreciation and amortization		985,500			4,782,600
Non-cash loss on derivative value		1,246,800			—
Accretion of asset retirement obligation		60,400			(42,400	)
Decrease in accounts receivable-affiliate		1,032,100			667,900
Increase (decrease) in accrued liabilities		3,600			(17,000	)
Net cash provided by operating activities		3,549,600			6,225,300
Cash flows from financing activities:
Distributions to partners		(3,791,400	)		(6,375,700	)
Net cash used in financing activities		(3,791,400	)		(6,375,700	)
Net decrease in cash and cash equivalents		(241,800	)		(150,400	)
Cash and cash equivalents at beginning of period		661,800			1,142,300
Cash and cash equivalents at end of period	$	420,000		$	991,900
Supplemental schedule of non-cash investing and financing activities:
Assets returned to managing general partner:
Tangible equipment	$	(19,100	)	$	(346,200	)
Intangible drilling costs		—			(29,100	)
	$	(19,100	)	$	(375,300	)

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

6

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

NOTE 1 - DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Atlas America Series 27-2006 L.P. (the “Partnership”) is a Delaware Limited Partnership which includes Atlas Resources, LLC of Pittsburgh, Pennsylvania, as Managing General Partner ("MGP") and Operator, and 1,367 subscribers to units as Limited Partners. The Partnership was formed on July 21, 2006 to drill and operate gas wells located in Pennsylvania, New York and Tennessee. The Partnership has no employees and relies on its MGP for management which, in turn, relies on its parent company, Atlas Energy Resources, LLC (NYSE:ATN), ("Atlas Energy"), for administrative services.

The financial statements as of June 30, 2009 and for the three months and six months ended June 30, 2009 and 2008 are unaudited except that the balance sheet at December 31, 2008 is derived from audited financial statements. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission. However, in the opinion of management, these interim financial statements include all the necessary adjustments to fairly present the results of the interim periods presented. Management has evaluated subsequent events through August 13, 2009, the date the financial statements were issued. The unaudited interim financial statements should be read in conjunction with the audited financial statements included in the Partnership's Form 10-K for the year ended December 31, 2008. The results of operations for the three months and six months ended June 30, 2009 may not necessarily be indicative of the results of operations for the year ended December 31, 2009.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 Form 10-K for the year ended December 31, 2008 filed with the Securities and Exchange Commission.

Accounts Receivable and Allowance for Possible Losses

In evaluating the need for an allowance for possible losses, the Partnership's MGP, performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of its customers' credit information. Credit is extended on an unsecured basis to many of its energy customers. At June 30, 2009 and December 31, 2008, the Partnership's MGP's credit evaluation indicated that the Partnership has no need for an allowance for possible losses.

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

7

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue Recognition

Because there are timing differences between the delivery of the Partnership’s natural gas and oil and the receipt of a delivery statement, the Partnership has unbilled revenues. These revenues are accrued based upon volumetric data from the Partnership’s records and estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices. The Partnership had unbilled trade receivables of $1,084,000 at June 30, 2009 and $1,789,600 at December 31, 2008, which are included in Accounts receivable-affiliate on the Partnership's Balance Sheets.

Oil and Gas Properties

The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil and gas properties are recorded at cost. Depletion is based on cost less estimated salvage value primarily using the unit-of-production method over the assets' estimated useful lives. In addition, accumulated depletion includes impairment adjustments to reflect the write-down to fair market value of the oil and gas properties. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

Oil and gas properties consist of the following at the dates indicated:	June 30,			December 31,
	2009			2008
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,716,900		$	1,716,900
Wells and related equipment		86,290,900			86,310,000
		88,007,800			88,026,900
Accumulated depletion		(69,326,800	)		(68,341,300	)
	$	18,681,000		$	19,685,600

Recently Adopted and Issued Financial Accounting Standards

In June 2009, the FASB issued Statement No. 165, Subsequent Events (“SFAS No. 165”). SFAS No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS No. 165 requires management of a reporting entity to evaluate events or transactions that may occur after the balance sheet date for potential recognition or disclosure in the financial statements and provides guidance for disclosures that an entity should make about those events. SFAS No. 165 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. The Partnership adopted the requirements of SFAS No. 165 on April 1, 2009 and its adoption did not have a material impact on its financial position or results of operations.

8

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Adopted and Issued Financial Accounting Standards (Continued)

In June 2009, the FASB issued Statement No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – A Replacement of FASB Statement No. 162 (“SFAS No. 168”). SFAS No. 168 establishes the FASB Accounting Standards Codification (“Codification”) as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The Codification supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following SFAS No. 168, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the Codification. SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Partnership will apply the requirements of SFAS No. 168 to its financial statements and will update its disclosure references to the new FASB codification for the interim period ended September 30, 2009 and does not expect it to have a material impact on its financial position or results of operations.

In April 2009, the Financial Accounting Standards Board, (“FASB”) issued Staff Position 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (“FSP FAS 157-4”). FSP FAS 157-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. FSP FAS 157-4 also requires an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. FSP FAS 157-4 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Partnership adopted the requirements of FSP FAS 157-4 on April 1, 2009 and its adoption did not have a material impact on its financial position or results of operations.

In April 2009, the FASB issued Staff Position 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (“FSP FAS 107-1 and APB 28-1”). FSP FAS 107-1 and APB 28-1 require an entity to provide disclosures about fair value of financial instruments in interim financial information. In addition, an entity shall disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. FSP FAS 107-1 APB 28-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Partnership adopted the requirements of FSP FAS 107-1 APB 28-1 on April 1, 2009 and its adoption did not have a material impact on its financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, - an amendment of FASB Statement No. 133 (“SFAS No. 161”). SFAS No. 161 amends the requirement of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”), to require enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for under SFAS No. 133 and its related interpretations and how derivative instruments and related hedge items affect an entity’s financial position, financial performance and cash flows. The Partnership adopted the requirements of SFAS No. 161 on January 1, 2009 and it did not have a material impact on its financial position or results of operations (See Note 5).

9

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Modernization of Oil and Gas Reporting

In December 2008, the Securities and Exchange Commission (“SEC”) announced that it had approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K. These new disclosure requirements are referred to as “Modernization of Oil and Gas Reporting” and include provisions that:

·   Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

·   Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.

·   Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves.

·   Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty.”

·   Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

·   Require additional disclosures regarding the qualifications of the chief technical person who oversees the Partnership’s overall reserve estimation process. Additionally, disclosures are required related to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a Partnership’s  reserves preparer or auditor based on Society of Petroleum Engineers criteria.

The Partnership will begin complying with the disclosure requirements in its annual report on Form 10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. The Partnership is currently in the process of evaluating the new requirements.

10

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 3 - TRANSACTIONS WITH ATLAS RESOURCES, LLC AND ITS AFFILIATES

The Partnership has entered into the following significant transactions with its 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 Net Earnings are payable at $75 per well per month. Administrative costs incurred for the three months and six months ended June 30, 2009 were $43,200 and $86,500, respectively. Administrative costs incurred for the three months and six months ended June 30, 2008 were $43,400 and $87,700, respectively.

·   Monthly well supervision fees which are included in production expenses in the Partnership’s Statements of Net Earnings are payable at $376 per well per month in 2009 and 2008, for operating and maintaining the wells. Well supervision fees incurred, for the three months and six months ended June 30, 2009 were $216,900 and $433,900, respectively. Well supervision fees incurred, for the three months and six months ended June 30, 2008 were $217,400 and $439,600, respectively.

·   Transportation fees which are included in production expenses in the Partnership’s Statements of Net Earnings are generally payable at 13% of the natural gas sales price. Transportation fees incurred for the three months and six months ended June 30, 2009 were $182,300 and $422,400, respectively. Transportation fees incurred for the three months and six months ended June 30, 2008 were $431,700 and $1,064,800, respectively.

·   Assets returned to the MGP which are disclosed on the Partnership's Statements of Cash Flows as a non-cash activity for the six months ended June 30, 2009 and 2008 were $19,100 and $375,300, 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.

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 investor partners (July 2007) and expiring 60 months from that date. For the six months ended June 30, 2009, the MGP was required to subordinate $534,600 of its net revenues of $1,267,400. Therefore MGP distributions were decreased and the limited partners were increased by $534,600 as shown on the Statement of Changes in Partners’ Capital for the six months ended June 30, 2009.

11

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 4 – COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) includes net income (loss) and all other changes in equity of a business during a period from transactions and other events and circumstances from non-owner sources. These changes, other than net income, are referred to as "other comprehensive income (loss)" and, for the Partnership, include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges. A reconciliation of the Partnership’s comprehensive income (loss) for the periods indicated is as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Net (loss) earnings	$	(56,000	)	$	426,700		$	221,200		$	834,200
Other comprehensive income (loss):
Unrealized holding gain (loss) on hedging contracts		139,700			(5,998,500	)		(857,500	)		(9,843,500	)
Less: reclassification adjustment for gains (losses) realized in net earnings		(61,300	)		46,100			90,000			(391,900	)
Total other comprehensive income (loss)		78,400			(5,952,400	)		(767,500	)		(10,235,400	)
Comprehensive income (loss)	$	22,400		$	(5,525,700	)	$	(546,300	)	$	(9,401,200	)

NOTE 5 – DERIVATIVE INSTRUMENTS

The Partnership applies the provisions of SFAS 133, which requires each derivative instrument to be recorded in the balance sheet as either an asset or liability measured at fair value. Changes in a derivative instrument’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met.

The Partnership is exposed to certain risks relating to its ongoing business operations. The risk is managed by using derivative instruments related to commodity price risk. Forward contracts on natural gas and oil are entered into to manage the price risk associated with forecasted sales of natural gas and crude oil. In accordance with SFAS No. 133, the Partnership designates these derivatives as cash flow hedges and the derivative instruments have been recorded as either assets or liabilities at fair value in the balance sheet. The effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified to earnings in the same period during which the hedged transaction affects earnings. The following table summarizes the fair value of derivative instruments as of June 30, 2009 and December 31, 2008, as well as the gain or loss recognized for the three months and six months ended June 30, 2009 and 2008, respectively. There were no gains or losses recognized in income for ineffective derivative instruments for the three months and six months ended June 30, 2009 and 2008, respectively.

12

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 5 – DERIVATIVE INSTRUMENTS (Continued)

Fair Value of Derivative Instruments:
	Asset Derivatives					Liability Derivatives
Derivatives in		Fair Value					Fair Value
SFAS 133 Cash Flow	Balance Sheet	June 30,		December 31,		Balance Sheet	June 30,			December 31,
Hedging Relationships	Location	2009		2008		Location	2009			2008
Commodity contracts:	Current assets	$	1,071,500	$	2,431,800	Current liabilities	$	(3,500	)	$	(214,100	)
	Long-term assets		644,300		1,539,700	Long-term liabilities		(161,900	)		(192,700	)
Total derivatives under SFAS No. 133		$	1,715,800	$	3,971,500		$	(165,400	)	$	(406,800	)

Effects of Derivative Instruments on Statements of Net Earnings:

Derivatives in	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) Three Months Ended					Location of Gain/(Loss) Reclassified from Accumulated	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) Three Months Ended
SFAS 133 Cash Flow	June 30,		June 30,			OCI into Income	June 30,		June 30,
Hedging Relationship	2009		2008			(Effective Portion)	2009		2008
Commodity contracts	$	139,700	$	(5,998,500	)	Natural gas and oil revenue	$	61,300	$	(46,100	)

Derivatives in	Gain/(Loss) Recognized in OCI on Derivative (Effective Portion) Six Months Ended						Location of Gain/(Loss) Reclassified from Accumulated	Gain/(Loss) Reclassified from OCI into Income (Effective Portion) Six Months Ended
SFAS 133 Cash Flow	June 30,			June 30,			OCI into Income	June 30,			June 30,
Hedging Relationship	2009			2008			(Effective Portion)	2009			2008
Commodity contracts	$	(857,500	)	$	(9,843,500	)	Natural gas and oil revenue	$	(90,000	)	$	391,900

Atlas Energy, on behalf of the Partnership, from time to time enters into natural gas and crude oil future option contracts and collar contracts to hedge exposure to changes in natural gas prices and oil prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures, 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.

At June 30, 2009, the Partnership reflected a net hedge asset on its Balance Sheets of $1,550,400, however unrealized gains of $2,317,900 resulting from impairment charges of the Partnership’s oil and gas properties for the period ended December 31, 2008 results in a net unrealized accumulated loss of $767,500. Of the remaining $767,500 net unrealized loss in accumulated other comprehensive loss at June 30, 2009, if the fair values of the instruments remain at current market values, the Partnership will reclassify $276,600 of net losses to its Statements of Net Earnings over the next twelve month period as these contracts settle, and $490,900 of net losses in later periods. Actual amounts that will be reclassified will vary as a result of future price changes. Ineffective hedge gains or losses are recorded within the Statements of Net Earnings while the hedge contract is open and may increase or decrease until settlement of the contract. The Partnership recognized no gains or losses during the three months and six months ended June 30, 2009 and 2008 for hedge ineffectiveness or as a result of the discontinuance of cash flow hedges.

13

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 5 – DERIVATIVE INSTRUMENTS (Continued)

As of June 30, 2009, Atlas Energy had allocated to the Partnership the following natural gas and oil volumes hedged:

Natural Gas Fixed Price Swaps

Production			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(MMbtu) (1)		(per MMbtu)		Asset (2)
2009		201,300	$	8.04	$	739,900
2010		278,100		7.71		458,300
2011		169,600		7.04		135,900
2012		149,500		7.22		82,200
2013		71,300		7.13		500
					$	1,416,800

Natural Gas Costless Collars

Production				Average		Fair Value
Period Ending	Option	Volumes		Floor & Cap		Asset
December 31,	Type	(MMbtu) (1)		(per MMbtu)		(Liability) (2)
2009	Puts purchased		1,100	$	11.00	$	7,300
2009	Calls sold		1,100		15.35		—
2010	Puts purchased		29,000		7.84		57,600
2010	Calls sold		29,000		9.01		—
2011	Puts purchased		76,600		6.52		45,900
2011	Calls sold		76,600		7.67		—
2012	Puts purchased		29,200		6.51		—
2012	Calls sold		29,200		7.72		(4,700	)
2013	Puts purchased		36,300		6.52		—
2013	Calls sold		36,300		7.81		(11,300	)
						$	94,800

Crude Oil Fixed Price Swaps

Production			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(Bbl)		(per Bbl)		Asset (3)
2009		300	$	99.50	$	7,900
2010		400		97.40		9,000
2011		300		77.46		6,000
2012		200		76.86		3,700
2013		100		77.36		1,000
					$	27,600

14

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 5 – DERIVATIVE INSTRUMENTS (Continued)

Crude Oil Costless Collars

Production				Average
Period Ending	Option	Volumes		Floor & Cap		Fair Value
December 31,	Type	(Bbl)		(per Bbl)		Asset (3)
2009	Puts purchased		200	$	85.00	$	2,500
2009	Calls sold		200		116.88		—
2010	Puts purchased		200		85.00		3,700
2010	Calls sold		200		112.92		—
2011	Puts purchased		200		67.22		2,700
2011	Calls sold		200		89.44		—
2012	Puts purchased		200		65.51		1,800
2012	Calls sold		200		91.45		—
2013	Puts purchased		100		65.36		500
2013	Calls sold		100		93.44		—
						$	11,200
				Total Net Asset		$	1,550,400

____________

(1)   MMBTU represents million British Thermal Units.

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

(3)   Fair value based on forward WTI crude oil prices.

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS

SFAS 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The Partnership prioritizes the inputs of the valuation techniques used to measure fair value into three levels.

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 entity's 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.

15

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

Assets and Liabilities Measured at Fair Value on a Recurring Basis

All of the Partnership’s derivatives contracts are defined as Level 2. The Partnership's natural gas and crude oil derivative contracts are valued based on prices quoted on the NYMEX or WTI and adjusted by the respective counterparty using various assumptions including quoted forward prices, time value, volatility factors, and contractual prices for the underlying instruments. In accordance with SFAS 157, the following table represents the Partnership's fair value hierarchy for its financial instruments at June 30, 2009.

	Fair Value Measurements at June 30, 2009 Using
	Quoted prices		Significant other		Significant
	in active		observable		unobservable
	markets		inputs		inputs
	(Level 1)		(Level 2)		(Level 3)
Commodity-based derivatives	$	—	$	1,550,400	$	—
Total	$	—	$	1,550,400	$	—

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The Partnership has certain assets and liabilities that are reported at fair value on a nonrecurring basis in its Balance Sheets. The following methods and assumptions were used to estimate fair values.

Oil and Gas Property Impairments. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Partnership reviews its proved oil and gas properties for impairment annually or when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The Partnership estimates the expected future cash flows from its oil and gas properties and compares such future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Partnership will adjust the carrying amount of the oil and gas properties to their fair value in the current period. The factors used to determine fair value include, but are not limited to, estimates of reserves, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. There was no impairment charge for the three months and six months ended June 30, 2009 and 2008, respectively, however the Partnership recorded an impairment of $41,700,300 for the year ended December 31, 2008.

Asset Retirement Obligations. The Partnership estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment for a legal obligation for an asset retirement obligation such as: amounts and timing of settlements; interest rates; and estimated inflation rates. There were no new asset retirement obligations incurred for the three months and sixmonths ended June 30, 2009 and 2008, respectively.

16

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS (Continued)

June 30, 2009

(Unaudited)

NOTE 7 - ASSET RETIREMENT OBLIGATION

The Partnership accounts for the estimated plugging and abandonment costs for its oil and gas properties in accordance with Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”) and FASB, Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations.

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Asset retirement obligation at beginning of period	$	2,043,200	$	1,623,700	$	2,013,000	$	1,690,100
Accretion expense		30,200		24,000		60,400		(42,400	)
Asset retirement obligation at end of period	$	2,073,400	$	1,647,700	$	2,073,400	$	1,647,700

NOTE 8 – COMMITMENTS AND CONTINGENCIES

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 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 OR PLAN OF OPERATIONS (UNAUDITED)

Forward-Looking Statements

The matters discussed within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates and projections. While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements.

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

17

General

We were formed as a Delaware limited partnership on July 21, 2006, with Atlas Resources, LLC as our Managing General Partner, or MGP, to drill natural gas development wells. Atlas Resources, Inc. was merged into a newly-formed limited liability company, Atlas Resources LLC, which now serves as our MGP. We have no employees and rely on our MGP for management which, in turn relies on its parent company, Atlas Energy Resources, LLC (NYSE:ATN), or Atlas Energy, for administrative services. Atlas Energy is a subsidiary of Atlas America, Inc. (NASDAQ:ATLS).

Our wells are currently producing natural gas and, to a far lesser extent, oil which are our only products. Most of our gas is gathered and delivered to market through Laurel Mountain Midstream, LLC’s gas gathering system, a newly formed joint-venture between Atlas Energy’s affiliate, Atlas Pipeline Partners, L.P. (NYSE:APL) and The Williams Companies (NYSE:WMB). We do not plan to sell any of our wells and will continue to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold.

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,
	2009			2008			2009			2008
Production revenues (in thousands):
Gas	$	1,008		$	3,439		$	2,463		$	7,297
Oil		18			89			35			186
Total	$	1,026		$	3,528		$	2,498		$	7,483
Production volumes:
Gas (mcf/day) (1)		2,172			4,140			2,310			4,503
Oil (bbls/day) (1)		6			10			6			11
Total (mcfe/day) (1)		2,208			4,200			2,346			4,569
Average sales prices: (2)
Gas (per mcf) (1) (3)	$	8.17		$	9.13		$	8.80		$	8.90
Oil (per bbl) (1) (4)	$	57.86		$	96.23		$	66.51		$	90.12
Average production costs:
As a percent of revenues		52	%		22	%		45	%		24	%
Per mcfe (1)	$	2.63		$	2.02		$	2.63		$	2.12
Depletion per mcfe	$	2.32		$	5.81		$	2.32		$	5.75

_____________

(1)   “Mcf” means thousand cubic feet, “mcfe” means thousand cubic feet equivalent and “bbls” means 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.

(3)   Average gas prices are calculated by including in total revenue gains previously recognized into income and dividing by the total volume for the period. Gas revenue was adjusted for previously recognized gains of $607,200 and $1,215,300 for the three and six months June 30, 2009.

(4)   Average oil prices are calculated by including in total revenue gains previously recognized into income and dividing by the total volume for the period. Oil revenue was adjusted for previously recognized gains of $15,100 and $31,600 for the three and six months June 30, 2009.

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Natural Gas Revenues.  Our natural gas revenues were $1,008,000 and $3,438,700 for the three months ended June 30, 2009 and 2008, respectively, a decrease of $2,430,700 (71%). The $2,430,700 decrease in natural gas revenues for the three months ended June 30, 2009 as compared to the prior year similar period was attributable to a $1,634,400 decrease in production volumes and a $796,300 decrease in natural gas sales prices after the effect of financial hedges. Our production volumes decreased to 2,172 mcf per day for the three months ended June 30, 2009 from 4,140 mcf per day for the three months ended June 30, 2008, a decrease of 1,968 mcf per day (48%). The overall decrease in natural gas production volumes for the three months ended June 30, 2009 resulted from the normal decline inherent in the life of a well.

Our natural gas revenues were $2,462,900 and $7,297,000 for the six months ended June 30, 2009 and 2008, respectively, a decrease of $4,834,100 (66%). The $4,834,100 decrease in natural gas revenues for the six months ended June 30, 2009 as compared to the prior year similar period was attributable to a $3,574,100 decrease in production volumes and a $1,260,000 decrease in natural gas sales prices after the effect of financial hedges. Our production volumes decreased to 2,310 mcf per day for the six months ended June 30, 2009 from 4,503 mcf per day for the six months ended June 30, 2008, a decrease of 2,193 mcf per day (49%). The overall decrease in natural gas production volumes for the six months ended June 30, 2009 resulted 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 $17,500 and $89,100 for the three months ended June 30, 2009 and 2008, respectively, a decrease of $71,600 (80%). The $71,600 decrease in oil revenues for the three months ended June 30, 2009 as compared to the prior year similar period was attributable to a $36,600 decrease in oil prices and a $35,000 decrease in production volumes. Our production volumes decreased to 6 bbls per day for the three months ended June 30, 2009 from 10 bbls per day for the three months ended June 30, 2008, a decrease of 4 bbls per day (40%).

Our oil revenues were $35,400 and $186,400 for the six months ended June 30, 2009 and 2008, respectively, a decrease of $151,000 (81%). The $151,000 decrease in oil revenues for the six months ended June 30, 2009 as compared to the prior year similar period was attributable to a $95,700 decrease in production volumes and a $55,300 decrease in oil prices. Our production volumes decreased to 6 bbls per day for the six months ended June 30, 2009 from 11 bbls per day for the six months ended June 30, 2008, a decrease of 5 bbls per day (45%).

Expenses.  Production expenses were $528,900 and $771,200 for the three months ended June 30, 2009 and 2008, respectively, a decrease of $242,300 (31%). Production expenses were $1,114,700 and $1,761,800 for the six months ended June 30, 2009 and 2008, respectively, a decrease of $647,100 (37%). These decreases were primarily attributable to decreases in transportation fees and other variable expenses for the six months ended June 30, 2009 as compared to the prior year similar period.

Depletion of oil and gas properties as a percentage of oil and gas revenues were 46% and 63% for the three months ended June 30, 2009 and 2008, respectively; and 39% and 64% for the six months ended June 30, 2009 and 2008, respectively. These percentage changes are directly attributable to changes in revenues, oil and gas reserve quantities, product prices, production volumes and changes in the depletable cost basis of oil and gas properties.

General and administrative expenses for the three months ended June 30, 2009 and 2008, were $55,500 and $83,500, respectively, a decrease of $28,000 (34%). For the six months ended June 30, 2009 and 2008 these expenses were $116,500 and $147,200, respectively, a decrease of $30,700 (21%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP.  These decreases were primarily due to lower third-party costs as compared to the prior year similar period.

19

Liquidity and Capital Resources

Cash provided by operating activities decreased $2,675,700 in the six months ended June 30, 2009 to $3,549,600 as compared to $6,225,300 for the six months ended June 30, 2008. This decrease was primarily due to a decrease in net earnings before depletion, net non-cash loss on derivative value and accretion of $3,060,500. In addition, the change in accounts receivable affiliate increased operating cash flows by $364,200 in the six months ended June 30, 2009 as compared to the six months ended June 30, 2008.

Cash used in financing activities decreased $2,584,300 during the six months ended June 30, 2009 to $3,791,400 from $6,375,700 for the six months ended June 30, 2008. This decrease was due to a decrease in cash distributions.

Our MGP may withhold funds for future plugging and abandonment costs. 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.

We believe that our future cash flows from operations and amounts available from borrowings from our MGP or its affiliates, if any, will be adequate to fund our operations.

Critical Accounting Policies

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, 2008.

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 investor partners (July 2007) and expiring 60 months from that date. For the six months ended June 30, 2009, the MGP was required to subordinate $534,600 of its net revenues of $1,267,400. Therefore MGP distributions were decreased and the limited partners were increased by $534,600 as shown on the Statement of Changes in Partners’ Capital for the six months ended June 30, 2009.

Recently Adopted and Issued Financial Accounting Standards

In June 2009, the FASB issued Statement No. 165, Subsequent Events or SFAS No. 165. SFAS No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS No. 165 requires management of a reporting entity to evaluate events or transactions that may occur after the balance sheet date for potential recognition or disclosure in the financial statements and provides guidance for disclosures that an entity should make about those events. SFAS No. 165 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. We adopted the requirements of SFAS No. 165 on April 1, 2009 and its adoption did not have a material impact on our financial position or results of operations.

20

In June 2009, the FASB issued Statement No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – A Replacement of FASB Statement No. 162 or SFAS No. 168. SFAS No. 168 establishes the FASB Accounting Standards Codification or Codification as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities.  The Codification supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following SFAS No. 168, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the Codification. SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We will apply the requirements of SFAS No. 168 to our financial statements and will update its disclosure references to the new FASB codification for the interim period ended September 30, 2009 and does not expect it to have a material impact on our financial position or results of operations.

In April 2009, the Financial Accounting Standards Board, or FASB issued Staff Position 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly or FSP FAS 157-4. FSP FAS 157-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. FSP FAS 157-4 also requires an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. FSP FAS 157-4 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted the requirements of FSP FAS 157-4 on April 1, 2009 and its adoption did not have a material impact on our financial position or results of operations.

In April 2009, the FASB issued Staff Position 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments or FSP FAS 107-1 and APB 28-1. FSP FAS 107-1 and APB 28-1 require an entity to provide disclosures about fair value of financial instruments in interim financial information. In addition, an entity shall disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. FSP FAS 107-1 APB 28-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted the requirements of FSP FAS 107-1 APB 28-1 on April 1, 2009 and its adoption did not have a material impact on our financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, - an amendment of FASB Statement No. 133 or SFAS No. 161. SFAS No. 161 amends the requirement of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, or SFAS No. 133, to require enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for under SFAS No. 133 and its related interpretations and how derivative instruments and related hedge items affect an entity’s financial position, financial performance and cash flows. We adopted the requirements of SFAS No. 161 on January 1, 2009 and its adoption did not have a material impact on our financial position or results of operations (See Note 5).

21

Modernization of Oil and Gas Reporting

In December 2008, the Securities and Exchange Commission or SEC announced that it had approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K. These new disclosure requirements are referred to as “Modernization of Oil and Gas Reporting” and include provisions that:

·   Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

·   Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.

·   Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves.

·   Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty.”

·   Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

·   Require additional disclosures regarding the qualifications of the chief technical person who oversees the Partnership’s overall reserve estimation process. Additionally, disclosures are required related to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a Partnership’s reserves preparer or auditor based on Society of Petroleum Engineers criteria.

We will begin complying with the disclosure requirements in its annual report on Form 10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. We are currently in the process of evaluating the new requirements.

ITEM 4.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Partnership maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in Securities and 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 the MGP’s management, including the chief executive officer and the chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, the MGP’s 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 the MGP’s management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of the chief executive officer and chief financial officer, the MGP has carried out an evaluation of the effectiveness of the Partnership’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the chief executive officer and chief financial officer concluded that the Partnership’s disclosure controls and procedures are effective at the reasonable assurance level at June 30, 2009.

22

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 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)
10.1	Drilling and Operating Agreement 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	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
	Act of 2002
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
	Act of 2002

______________

(1) Filed on April 30, 2007 in the Form S-1 Registration Statement dated April 30, 2007, File No. 0-52615

23

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 13, 2009	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 persons on behalf of the registrant and in the capacities and on the dates indicated.
Date:  August 13, 2009	By:/s/ Freddie M. Kotek
	Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive
	Officer and President
Date:  August 13, 2009	By:/s/ Matthew A. Jones
	Matthew A. Jones, Chief Financial Officer
Date:  August 13, 2009	By:/s/ Sean P. McGrath
	Sean P. McGrath, Chief Accounting Officer

24