Atlas America Series 27-2006 10-K 2008 FY Annual report

	United States
	Securities and Exchange Commission
	Washington, D.C. 20549
	Form 10-K
(Mark One)
R	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2008
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.
	(Exact name of registrant as specified 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)
Registrant’s telephone number (412) 262-2830
Securities registered under Section 12(b) of the Exchange Act.
Title of each class		Name of each exchange on which registered
None		None
Securities registered under Section 12 (g) of the Exchange Act:  Investor General Partner Units and Limited Partner Units
(Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes ¨ No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes ¨ No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days, Yes þ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this form 10-K þ
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 þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No þ
DOCUMENTS INCORPORATED BY REFERENCE:  None

ATLAS AMERICA SERIES 27-2006 L.P.

(A DELAWARE LIMITED PARTNERSHIP)

INDEX TO ANNUAL REPORT

ON FORM 10-K

PART I		PAGE
Item 1:	Description of Business	3-5
Item 2:	Description of Properties	5-9
Item 3:	Legal Proceedings	9
Item 4:	Submission of Matters to a Vote of Security Holders	9
PART II
Item 5:	Market for Registrant’s Common Equity and Related Security Holder Matters	9-10
Item 7:	Management’s Discussion and Analysis of Financial Condition or Plan of Operations	10-18
Item 8:	Financial Statements	19-36
Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	37
Item 9A:	Controls and Procedures	37
Item 9B:	Other Information	38
PART III
Item 10:	Directors, Executive Officers and Corporate Governance	38-40
Item 11:	Executive Compensation	40
Item 12:	Security Ownership of Certain Beneficial Owners and Management	40-41
Item 13:	Certain Relationships and Related Transactions, and Director Independence	41
Item 14:	Principal Accountant Fees and Services	42
PART IV
Item 15:	Exhibits	42
SIGNATURES		43

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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.

PART I

ITEM 1.  DESCRIPTION OF BUSINESS

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. We are currently operating wells located in Pennsylvania, New York and Tennessee. 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.  See Item 10 “Directors, Executive Officers and Corporate Governance.”

We received total cash subscriptions from investors of $70,883,000, which were paid to our MGP acting as operator and general drilling contractor under our drilling and operating agreements. Our MGP contributed leases and paid all syndication and offering costs and 60.11% of the tangible (“equipment”) costs for a total capital contribution, at December 31, 2008, to us of $24,126,600. We have drilled 256 developmental wells to the Clinton/Medina, Upper Devonian Sandstones and Southern Appalachia Shale geological formations in Pennsylvania, New York and Tennessee.

Public Offering of Atlas Energy.  In December 2006, Atlas America, Inc., or Atlas America, contributed substantially all of its natural gas and oil assets and its investment partnership management business to Atlas Energy. Concurrent with this transaction, Atlas Energy issued 7,273,750 common units, representing a 19.4% ownership interest at that moment, in an initial public offering at a price of $21.00 per unit. The net proceeds of approximately $139.9 million, after underwriting discounts and commissions, were distributed to Atlas America.

Atlas Energy is a limited liability company focused on the development and production of natural gas and, to a lesser extent, oil in northern Michigan's Antrim Shale and the Appalachian Basin region of the United States of America. Atlas Energy is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it coinvests to finance the exploitation and development of its acreage. Atlas Energy is managed by Atlas Energy Management, Inc., through which Atlas America provides Atlas Energy with the personnel necessary to manage its assets and raise capital.

Business Strategy.  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 Atlas Pipeline Partners L.P.’s gas gathering system, which is managed by an affiliate of our MGP. 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. See Item 2 “Description of Properties” for information concerning our wells.

Our ongoing operating and maintenance costs have been and are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We pay our MGP a monthly well supervision fee of $376, subject to inflationary adjustments, per well, as outlined in our drilling and operating agreement. This well supervision fee covers all normal and regularly recurring operating expenses for the production and sale of natural gas and, to a lesser extent, oil such as:

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·   well tending, routine maintenance and adjustment;

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

·   preparing reports to us and to 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 at cost for third-party services, materials, and a reasonable charge for services performed directly by our MGP or its affiliates.  Also, beginning one year after each of our wells has been placed into production our MGP, as operator, may retain $200 per month per well to cover the estimated future plugging and abandonment costs of the well. As of December 31, 2008, our MGP had not withheld any funds for this purpose.

Markets and Competition.  The availability of a ready market for natural gas and oil produced by us, and the price obtained, depends on numerous factors beyond our control, including the extent of domestic production, imports of foreign natural gas and oil, political instability or terrorist acts in oil 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 MGP is responsible for selling our natural gas production. Our natural gas is sold as discussed in Item 2 “Description of Properties.” During 2008 and 2007, 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.  See Item 2 “Description of Properties” regarding the marketing of our natural gas and oil.

Governmental Regulation.  The energy industry in general is heavily regulated by federal and state authorities, including regulation of production, environmental quality and pollution control. The intent of federal and state regulations generally is to prevent waste, protect rights to produce natural gas and oil between owners in a common reservoir and control contamination of the environment.  Failure to comply with regulatory requirements can result in substantial fines and other penalties.  The following discussion of the regulation of the United States of America energy industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which our operations may be subject.

Regulation of oil and gas producing activities.  State regulatory agencies where a producing natural gas well is located provide a comprehensive statutory and regulatory scheme for oil and gas operations such as ours including supervising the production activities and the transportation of natural gas sold in intrastate markets.  Our oil and gas operations in Pennsylvania are regulated by the Department of Environmental Resources, Division of Oil and Gas, our oil and gas operations in Tennessee are regulated by the Tennessee Department of Environment and Conservation and the Division of Geology and our oil and gas operations in New York are regulated by the New York Department of Environmental and Conservation and the Division of Geology.

Among other things, the regulations involve:

·   new well permit and well registration requirements, procedures and fees;

·   minimum well spacing requirements;

·   restriction on well locations and underground gas storage;

·   certain well site restoration, groundwater protection and safety measures;

·   landowner notification requirements;

·   certain bonding or other security measures;

·   various reporting requirements;

·   well plugging standards and procedures; and

·   broad enforcement powers.

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Environmental and Safety Regulation.  Under the Comprehensive Environmental Response, Compensation and Liability Act, the Toxic Substances Control Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Clean Air Act, and other federal and state laws relating to the environment, owners and operators of wells producing natural gas or oil can be liable for fines, penalties and clean-up costs for pollution caused by the wells. Moreover, the owners or operators’ liability can extend to pollution costs from situations that occurred prior to their acquisition of the assets. State public utility regulators have either adopted federal standards or promulgated their own safety requirements consistent with the federal regulations.

We believe we have complied in all material respects with applicable federal and state regulations and do not expect that these regulations will have a material adverse impact on our operations. Our producing activities also must comply with various federal, state and local laws not mentioned, including those covering the discharge of materials into the environment, or otherwise relating to the protection of the environment.

Where can you find more information.  We will file Form 10-K Annual Report and Form 10-Q Quarterly Reports as well as other non-recurring special purpose reports with the Securities and Exchange Commission.  A complete list of our filings is available on the Securities and Exchange Commission’s website at www.sec.gov. Any of our filings are also available at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The Public Reference Room may be contacted at 1-800- SEC-0330 for further information.

Additionally, our MGP will provide copies of any of these reports to you without charge.  Such requests should be made to:

Atlas America Series 27-2006 L.P.

Westpointe Corporate Center One

1550 Coraopolis Heights Road, 2nd Floor

Moon Township, PA  15108

ITEM 2.  DESCRIPTION OF PROPERTIES

Drilling Activity.  The following table shows information about wells drilled since our formation. All of our wells drilled were development wells, which mean a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. We do not expect to drill any wells in future years.  Also, see Item 7 “Management's Discussion and Analysis of Financial Condition or Plan of Operations” regarding our revenues recognized, costs and expenses we incurred, and our daily production volumes, average sales prices and production costs per equivalent unit during the period indicated.

	Development Wells
Years Ended December 31,	Productive (1)				Dry (2)
	Gross (3)		Net (4)		Gross (3)		Net (4)
2007		248.00		198.12		2.00		1.25
2006		6.00		6.00		—		—
		254.00		204.12		2.00		1.25

_____________

(1)   A “productive well” generally means a well that is not a dry hole.

(2)   A “dry hole” generally means a well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. The term “completion” refers either to the installation of permanent equipment for the production of oil or gas or, in the case of a dry hole, to the reporting of the abandonment of the well to the appropriate regulatory agency.

(3)   A “gross” well is a well in which we have a working interest.

(4)   A “net” well equals the actual working interest we own in one gross well divided by one hundred. For example, a 50% working interest in a well is one gross well, but a 0.5 net well.

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Summary of Producing Wells.  The table below shows the number of producing gross and net wells at December 31, 2008, in which we have a working interest, all wells are located in the Appalachian Basin.

	Number of Producing Wells
	Gross		Net
Gas		254		204.12

Production.  The following table shows the quantities of natural gas and oil we produced (net to our interest), our average sales price, and our average production (lifting) cost per equivalent unit of production for the period indicated.

									Average
Year									Production Cost
Ended	Production				Average Sales Price				(Lifting Cost)
December 31,	Oil (bbls) (1)		Gas (mcf) (1)		per bbl (1)		per mcf (1)		per mcfe (1) (2)
2008		3,600		1,336,900	$	93.76		9.19	$	2.07
2007		3,200		1,446,600	$	66.93	$	8.47	$	1.68

____________

(1)   “Mcf” means one thousand cubic feet of natural gas.  “Mcfe” means a thousand cubic feet equivalent.  Oil production is converted to mcfe at the rate of six mcf per barrel (“bbl”).

(2)   Lifting costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, insurance and gathering charges.

Natural Gas and Oil Reserve Information.The following tables summarize information regarding our estimated proved natural gas and oil reserves as of the date indicated. All of our reserves are located in the United States of America. Our estimates relating to our proved natural gas and oil reserves and our future net revenues from natural gas and oil reserves are based on reports which are reviewed by our independent third-party consultant as discussed below.  In accordance with SEC guidelines, we provide the PV-10 estimate of future net cash flows from proved reserves discounted using an annual discount rate of 10%. The estimated future net cash flows from proved reserves are calculated using natural gas and oil sales prices in effect as of the dates of the estimates, which are held constant throughout the life of the properties. We based our estimates of proved reserves upon the following year-end weighted average prices:

	December 31,
	2008		2007
Natural gas (per mcf)	$	6.21	$	7.35
Oil ( per bbl)		36.27		88.47

Reserve estimates are imprecise and may change as additional information becomes available.  Furthermore, estimates of natural gas and oil reserves are projections based on engineering data.  There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production.  Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.  Reserve reports of other engineers might differ from the reports of Wright & Company, our independent consultants.  The results of drilling, testing and production of a well subsequent to the date of the reserve estimate for the well may justify revising the estimate of the well’s reserves in the future.  Also, future prices we receive from the sale of natural gas and oil may be different from those estimated by Wright & Company in preparing the reserve reports.  The amounts and timing of future operating costs also may differ from those we estimated. In addition, you should not construe the estimated PV-10 values as representative of the fair market value of our proved natural gas and oil properties. PV-10 values are based on projected cash inflows, which do not provide for changes in natural gas and oil prices or for escalation of expenses. The meaningfulness of these estimates depends on the accuracy of the assumptions on which they were based. The downward revision of oil and gas reserves reflected production results that occurred during 2008 and used historical field level and historical decline curves for the year ended December 31, 2008. This decline reflects a decrease in the average price of natural gas of 16% and the average price of oil of 59% for the year ended December 2008.

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We evaluate natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves.  We deducted when applicable, operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows.  We made no provision for income taxes and based the estimates on operating methods and conditions prevailing as of the dates indicated.  We cannot assure you that these estimates are accurate predictions of future net cash flows from our natural gas and oil reserves or their present value. For additional information concerning our natural gas and oil reserves and estimates of future net revenues, see Note 9 of the “Notes to Financial Statements” in Item 8 “Financial Statements.”

	At December 31,
	2008		2007
Natural gas reserves – Proved Reserves (Mcf) (1)(4):
Proved developed reserves (2)		6,919,500		10,981,700
Total proved reserves of natural gas		6,919,500		10,981,700
Oil reserves – Proved Reserves (Bbl) (1)(4):
Proved developed reserves (2)		12,800		18,000
Total proved reserves of oil		12,800		18,000
Total proved reserves (Mcfe)		6,996,300		11,089,700
PV-10 estimate of cash flows of proved reserves (3)(4):
Proved developed reserves	$	13,929,200	$	28,958,000
Total PV-10 estimate	$	13,929,200	$	28,958,000
PV-10 estimate per investor partner unit (5)	$	3,306	$	6,872
Undiscounted estimate per investor partner unit (5)	$	5,485	$	11,544

_____________

(1)   “Proved reserves” generally means the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.  Reservoirs are considered proved if economic production is supported by either actual production or conclusive formation test.  The area of a reservoir considered proved includes that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data.

(2)   “Proved developed reserves” generally means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

(3)   The present value of estimated future net cash flows is calculated by discounting estimated future net cash flows by 10% annually.

(4)   Please see Regulation S-X rule 4-10 for complete definitions of each reserve category.

(5)   This value per $25,000 unit is determined by following the methodology used for determining our proved reserves using the data discussed above. However, this value does not necessarily reflect the fair market value of a unit, and each unit is illiquid. Also, the value of a unit for purposes of presentment of the unit to our MGP for purchase is different because it is calculated under a formula set forth in the partnership agreement.

We have not filed any estimates of our gas and oil reserves with, nor were such estimates included in any reports to, any Federal or foreign governmental agency other than the SEC within the 12 months before the date of this filing.

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Title to Properties.  We believe that we hold good and indefeasible title to our properties in accordance with standards generally accepted in the natural gas industry, subject to exceptions stated in the opinions of counsel employed by us in the various areas in which we conduct our activities.  We do not believe that these exceptions detract substantially from our use of any property.  As is customary in the natural gas industry, our MGP conducts only a perfunctory title examination at the time it acquires a property.  Before our MGP commences drilling operations, it conducts an extensive title examination and performs curative work on defects that it deems significant. Our MGP has obtained title examinations for substantially all of our producing properties.  No single property represents a material portion of our holdings.

Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the natural gas industry. Our properties are also subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our use of our properties.

Acreage.  The table below shows, by state, the estimated acres of developed oil and gas acreage in which we had an interest at December 31, 2008. There was no undeveloped acreage at December 31, 2008.

	Developed Acreage
Location	Gross (1)		Net (2)
New York		200.00		200.00
Pennsylvania		3,939.82		3,308.27
Tennessee		2,399.10		1,680.35
Total		6,538.92		5,188.62

___________

(1)   A “gross” acre is an acre in which we own a working interest.

(2)   A “net” acre equals the actual working interest we own in one gross acre divided by one hundred. For example, a 50% working interest in an acre is one gross acre, but a 0.5 net acre.

Delivery Commitments.Atlas Energy markets our natural gas, which is principally located in the Fayette County, PA area, primarily to Equitable Gas, Dominion Field Services, Inc., Exelon Energy Company, and to other third-party natural gas purchasers or marketers.

The pricing arrangements with Equitable Gas, Dominion Field Services, Inc., Exelon Energy Company, and other third-party gas purchasers or marketers are tied to the New York Mercantile Exchange Commissions or NYMEX monthly futures contract price. The total price received for our gas is a combination of the monthly NYMEX futures price plus a basis adjustment. For example, the NYMEX futures price is the base price and there is an additional premium paid, because of the location of the gas (the Appalachian Basin) in relation to the gas market, which is referred to as the “basis.”

Pricing for natural gas and oil has been volatile and uncertain for many years. The agreements with Equitable Gas, Dominion Field Services, Inc., Exelon Energy Company, and the other third-party gas purchasers or marketers also permit Atlas Energy and its affiliates to implement gas forward sales transactions through those companies. Equitable Gas, Dominion Field Services, Inc., Exelon Energy Company, and the other third-party purchasers or marketers also use NYMEX based financial instruments to hedge their pricing exposure and make price-hedging opportunities available to Atlas Energy, which then makes those arrangements available to us and its other partnerships. The price paid by Equitable Gas, Dominion Field Services, Inc., Exelon Energy Company, and any other third-party purchasers for certain volumes of natural gas sold under these hedge agreements may be significantly different from the underlying monthly spot market price. Also, Atlas Energy's hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts employed by Atlas Energy are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to six years in the future. The overall portion of our natural gas portfolio that is hedged changes from time to time.

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To assure that all financial instruments will be used solely for hedging price risks and not for speculative purposes, Atlas Energy has established a committee to assure that all financial trading is done in compliance with Atlas Energy’s hedging policies and procedures.  Atlas Energy does not intend to contract for positions that it cannot offset with actual production.

We are not required to provide any fixed and determinable quantities of gas under any agreement other than with Equitable Gas, Dominion Field Services, Inc., Exelon Energy Company and the other third-party gas purchasers or marketers.

ITEM 3.  LEGAL PROCEEDINGS

The MGP is not aware of any legal proceedings filed against us.

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 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS

None

PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS

Market Information.  There is no established public trading market for our units and we do not anticipate a market for our units will develop.  Our units may be transferred only in accordance with the provisions of Article VI of our partnership agreement which require that:

·   our managing general partner consent;

·   the transfer not result in materially adverse tax consequences to us; and

·   the transfer not violate federal or state securities laws.

An assignee of a unit may become a substituted partner only on meeting the following conditions:

·   the assignor gives the assignee the right;

·   our MGP consents to the substitution;

·   the assignee pays to us all costs and expenses incurred in connection with the substitution; and

·   the assignee executes and delivers the instruments, which our MGP requires to effect the substitution and to confirm his or her agreement to be bound by the terms of our partnership agreement.

A substitute partner is entitled to all of the rights of full ownership of the assigned units, including the right to vote.

Holders.  As of December 31, 2008, we had 1,364 unit holders.

Distributions.  Our MGP reviews our accounts monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. We distribute those funds, which our MGP determines are not necessary for us to retain, to our partners. We will not advance or borrow funds for purposes of making distributions.

The determination of our revenues and costs is made in accordance with generally accepted accounting principles, consistently applied, and cash distributions to our MGP may only be made in conjunction with distributions to our limited partners.

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During the year ended December 31, 2008 and 2007, we distributed the following:

·$7,637,400 and $3,289,800 to our limited partners; and

·$3,694,000 and $1,591,200 to our managing general partner, respectively.

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR PLAN OF OPERATIONS

This Item 7 “Management’s Discussion and Analysis of Financial Condition or Plan of Operations” should be read in conjunction with Item 8 “Financial Statements” and the “Notes to Financial Statements”.

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 developmental wells. 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. No additional funds will be required for drilling.

Public Offering of Atlas Energy.  In December 2006, Atlas America, Inc., or Atlas America, contributed substantially all of its natural gas and oil assets and its investment partnership management business to Atlas Energy Resources, LLC.  Concurrent with this transaction, Atlas Energy issued 7,273,750 common units, representing a 19.4% ownership interest at that moment, in an initial public offering at a price of $21.00 per unit. The net proceeds of approximately $139.9 million, after underwriting discounts and commissions, were distributed to Atlas America.

Atlas Energy is a limited liability company focused on the development and production of natural gas and, to a lesser extent, oil in northern Michigan's Antrim Shale and the Appalachian Basin region of the United States of America. Atlas Energy is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it coinvests to finance the exploitation and development of its acreage.Atlas Energy is managed by Atlas Energy Management, Inc., through which Atlas America provides Atlas Energy with the personnel necessary to manage its assets and raise capital.

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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:

	Years Ended December 31
	2008			2007
Production revenues (in thousands):
Gas	$	12,279		$	12,249
Oil	$	335		$	214
Total	$	12,614		$	12,463
Production volumes:
Gas (mcf/day) (1)		3,653			3,963
Oil (bbls/day) (1)		10			9
Total (mcfe/day) (1)		3,713			4,017
Average sales price:
Gas (per mcf) (1) (2)	$	9.19		$	8.47
Oil (per bbl) (1) (3)	$	93.76		$	66.93
Average production costs:
As a percent of revenues		22	%		20	%
Per mcfe (1)	$	2.07		$	1.68
Depletion per mcfe	$	6.32		$	5.51

_____________

(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)   The average sales price per mcf before the effects of hedging was $9.46 and $7.35 for the years ended December 31, 2008 and 2007, respectively.

(3)   The average sales price per bbl before the effects of hedging was $95.45 for the year ended December 31, 2008. There was no hedging for oil in 2007.

Natural Gas Revenues.  Our natural gas revenues were $12,279,300 and $12,248,600 for the years ended December 31, 2008 and 2007, respectively, an increase of $30,700. This increase was due to an increase in the average sales price we received for our natural gas to $9.19 per mcf for the year ended December 31, 2008 from $8.47 per mcf for the year ended December 31, 2007, an increase of $0.72 per mcf (9%), partially offset by a decrease in production volumes to 3,653 mcf per day for the year ended December 31, 2008 from 3,963 mcf per day for the year ended December 31, 2007, a decrease of 310 mcf (8%) per day. The $30,700 increase in our natural gas revenues for the year ended December 31, 2008, as compared to the prior year period, was attributable to a $960,200 increase due to higher natural gas sales prices, which are driven by market conditions, partially offset by a $929,500 decrease due to lower production volumes. The overall increase in natural gas production volumes resulted primarily from more wells being on-line for the full period as compared to the prior year period.

The price we receive for our natural gas is primarily a result of the index-driven agreements with Equitable Gas, Dominion Field Services, Inc., Exelon Energy Company, and our other natural gas purchasers.  See Item 2 “Description of Properties.” Thus, the price we receive for our natural gas may vary significantly each month as the underlying index changes in response to market conditions.

11

Oil Revenues.  We drill wells primarily to produce natural gas, rather than oil, but some wells have oil production. Our oil revenues were $335,400 and $214,200 for the years ended December 31, 2008 and 2007, respectively, an increase of $121,200 (57%). This increase was due to an increase in the average sales price we received for our oil to $93.76 for the year ended December 31, 2008, as compared to $66.93 for the year ended December 31, 2007, an increase of $26.83 per bbl (40%), and an increase in the production volumes to 10 bbls per day for the year ended December 31, 2008 from 9 bbls per day for the year ended December 31, 2007, an increase of 1 bbls per day (11%). The $121,200 increase in oil revenue for the year ended December 31, 2008 as compared to the prior year similar period was attributable to a $96,000 increase due to higher oil prices and $25,200 increase due to higher production volumes.

Expenses.  Production expenses were $2,808,300 and $2,468,300 for the years ended December 31, 2008 and 2007, respectively, an increase of $340,000 (14%). This increase was primarily attributable to the majority of our wells being on-line for the entire year ended December 31, 2008.

Depletion of oil and gas properties as a percentage of oil and gas revenues was 68% for the year ended December 31, 2008 as compared to 65% for the year ended December 31, 2007. This percentage change is directly attributable to revenues, oil and gas reserve quantities, product prices, production volumes and changes in the depletable cost basis of our oil and gas properties.

Impairment of oil and gas properties for the year ended December 31, 2008 and 2007 was $38,135,500 and $10,255,500, respectively. Annually, we compare the carrying value of our proved developed oil and gas producing properties to their estimated fair market value. To the extent our carrying value exceeds the estimated fair market value an impairment charge is recognized. As a result of this assessment, an impairment charge was recognized for the years ended December 31, 2008 and 2007. This impairment charge is based on reserve qualities, future market values and our carrying value. We can not provide any assurance that similar charges may or may not be taken in future periods.

General and administrative expenses were $278,400 and $195,100 for the years ended December 31, 2008 and 2007, respectively, an increase of $83,300 (43%). These expenses include outside costs for services, as well as the monthly administrative fee charged by our MGP.  This increase was primarily due to the majority of our wells being on-line for the entire year ended December 31, 2008.

Liquidity and Capital Resources.  Cash provided by operating activities increased $4,827,600 in the years ended December 31, 2008 to $10,850,900 as compared to $6,023,300 for the year ended December 31, 2007. This increase was primarily due to an increase in net earnings before depletion, impairment and accretion of $3,293,400 offset by a non-cash gain on derivative value of $3,564,700. In addition, a decrease in accounts-receivable affiliate increased operating cash flows by $5,118,700 for the year ended December 31, 2008 as compared to the prior year similar period.

Cash used in financing activities increased $6,450,300 for the year ended December 31, 2008 to $11,331,400 as compared to $4,881,100 for the year ended December 31, 2007. This increase is due to higher distributions to partners.

The MGP may withhold funds for estimated 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 anytime exceed 5% of our total subscriptions, and we will not borrow from third-parties.

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

12

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, impairment of long-lived assets, 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.

For a detailed discussion on the application of policies critical to our business operations and other accounting policies, see Note 2 of the “Notes to Financial Statements” in Item 8 “Financial Statements.”

Use of Estimates.  Preparation of our 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. Actual results could differ from these estimates.

Reserve Estimates.  Our estimates of our proved natural gas and oil reserves and future net revenues from them are based on reserve analyses that rely on various assumptions, including those required by the SEC, as to natural gas and oil prices, drilling and operating expenses, capital expenditures, abandonment costs, taxes and availability of funds.  Any significant variance in these assumptions could materially affect the estimated quantity of our reserves.  As a result, our estimates of our proved natural gas and oil reserves will be inherently imprecise.  Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves may vary substantially from our estimates, or estimates contained in the reserve reports. In addition, our proved reserves may be subject to downward or upward revision based on production history, results of future exploration and development, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control.

Accounts Receivable and Allowance for Possible Losses.  The MGP engages in credit extension, monitoring, and collection. In evaluating our allowance for possible losses, the MGP performs ongoing credit evaluations of our customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by our review of our customer’s credit information. The MGP extends credit on an unsecured basis to many of our energy customers. At December 31, 2008 and 2007 our credit evaluation indicated that the MGP has no need for an allowance for possible losses for our oil and gas receivables.

Impairment of Oil and Gas Properties.We review our producing oil and gas properties for impairment on an annual basis and whenever events and circumstances indicate a decline in the recoverability of their carrying values. We estimate the expected future cash flows from our oil and gas properties and compare 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, we 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. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that will require us to record an impairment of our oil and gas properties. During 2008 and 2007, we recognized an impairment charge of $38,135,500 and $10,255,500, respectively, net of an offsetting gain in other comprehensive income of $3,564,700 for the year ended December 31, 2008.

13

Derivative Instruments.Atlas Energy on our behalf from time to time enters into natural gas future option and collar contracts to hedge exposure to changes in natural gas prices. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Oil contracts are based on a West Texas Intermediate or WTI index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

We apply the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, or SFAS 133. SFAS 133 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. See Note 7 on our financial statements.

At December 31, 2008, Atlas Energy had allocated open natural gas futures contracts to us related to natural gas sales covering 2,540,100 dekatherms (“Dth”) of gas, maturing through December 31, 2013 at an average settlement price of $8.22 per Dth. In addition, Atlas Energy had allocated oil futures contracts to us related to oil sales covering 4,300 barrels (”Bbls”) of oil, maturing through April 30, 2013 at an average settlement price of $98.31 per Bbl. At December 31, 2008, we reflected a net hedge asset on our Balance Sheets of $3,564,700. As a result of the asset impairment we reclassified $3,564,700 of the gains and reduced impairment expense as of December 31, 2008. We realized losses of $379,600 and gains of $1,616,900 for the year ended December 31, 2008 and 2007, respectively in our oil and gas revenues within the Statements of Operations related to the settlement of qualifying hedge instruments. Ineffective hedge gains or losses are recorded within the Statements of Operations while the hedge contract is open and may increase or decrease until settlement of the contract. We recognized no gains or losses during the years ended December 31, 2008 and 2007, for hedge ineffectiveness or as a result of the discontinuance of cash flow hedges.

As of December 31, 2008, Atlas Energy had allocated to us 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		873,300	$	8.55	$	2,136,100
2010		603,900		8.11		585,000
2011		427,900		7.84		221,500
2012		316,100		8.05		248,600
2013		34,400		8.73		48,100
					$	3,239,300

14

Natural Gas Costless Collars

Production				Average
Period Ending	Option	Volumes		Floor & Cap		Fair Value
December 31,	Type	(MMbtu) (1)		(per MMbtu)		Asset (2)
2009	Puts purchased		5,500	$	11.00	$	27,100
2009	Calls sold		5,500		15.35		—
2010	Puts purchased		77,000		7.84		76,500
2010	Calls sold		77,000		9.01		—
2011	Puts purchased		171,800		7.48		85,000
2011	Calls sold		171,800		8.44		—
2012	Puts purchased		23,300		7.00		5,100
2012	Calls sold		23,300		8.32		—
2013	Puts purchased		6,900		7.00		1,600
2013	Calls sold		6,900		8.25		—
						$	195,300

Crude Oil Fixed Price Swaps

Production			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(Bbl)		(per Bbl)		Asset (3)
2009		800	$	100.14	$	38,100
2010		700		97.40		22,100
2011		600		96.44		15,600
2012		400		96.00		10,700
2013		100		96.06		3,000
					$	89,500

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		500	$	85.00	$	16,400
2009	Calls sold		500		118.63		—
2010	Puts purchased		400		85.00		10,300
2010	Calls sold		400		112.92		—
2011	Puts purchased		400		85.00		7,300
2011	Calls sold		400		110.81		—
2012	Puts purchased		300		85.00		5,200
2012	Calls sold		300		110.06		—
2013	Puts purchased		100		85.00		1,400
2013	Calls sold		100		110.09		—
						$	40,600
				Total Net Asset		$	3,564,700

15

_____________

(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.

The fair value of the derivatives is included on our Balance Sheets as follows:

	December 31,
	2008			2007
Short-term hedge receivable due from affiliate	$	2,431,800		$	1,235,400
Long-term hedge receivable due from affiliate		1,539,700			184,700
Short-term hedge liability due to affiliate		(214,100	)		(29,200	)
Long-term hedge liability due to affiliate		(192,700	)		(1,856,100	)
	$	3,564,700		$	(465,200	)

Fair Value of Financial Instruments

We have adopted the provisions of SFAS 157 at January 1, 2008. 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. SFAS 157’s 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 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.

We use the fair value methodology outlined in SFAS 157 to value the assets and liabilities for our outstanding derivative contracts. All of our derivatives contracts are defined as Level 2. Our 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 our fair value hierarchy for our financial instruments at December 31, 2008.

	Fair Value Measurements at December 31, 2008 Using
	Quoted prices		Significant other		Significant
	in active		observable		unobservable
	markets		inputs		inputs
	(Level 1)		(Level 2)		(Level 3)
Commodity-based derivatives	$	—	$	3,564,700	$	—
Total	$	—	$	3,564,700	$	—

16

Revenue Recognition.  Revenues from sales of natural gas and oil are recognized by us when the gas and oil have been delivered to the purchaser. Our natural gas and oil is sold under various contracts entered into by our MGP. Virtually all of our MGP’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price we receive from the sale of our natural gas fluctuates to remain competitive with generally available natural gas supplies in the market.

Asset Retirement Obligations.  On an annual basis, we estimate the costs of future dismantlement, restoration, reclamation and abandonment of our natural gas and oil-producing properties. We also estimate the salvage value of our equipment that we can recover upon abandonment. We comply with SFAS No. 143, Accounting for Asset Retirement Obligations as discussed in Note 8 to our financial statements. As of December 31, 2008, and 2007, our estimate of salvage values was greater than or equal to, our estimate of the costs of future dismantlement, restoration, reclamation and abandonment. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs from those we have estimated, or changes in our estimates or cost, would reduce our net earnings.

Off-Balance Sheet Arrangements.  We have no financial statement risk, or any Off-Balance Sheet Arrangements or contractual obligations.

Recently Issued Financial Accounting Standards.

In May 2008, the Financial Accounting Standards Board, or FASB, issued Statement of Financial Accounting Standards, No. 162, The Hierarchy of Generally Accepted Accounting Policies, or SFAS 162, which reorganizes the GAAP hierarchy. The purpose of the new standard is to improve financial reporting by providing a consistent framework for determining what accounting principles should be used when preparing U.S. GAAP financial statements. The standard is effective 60 days after the SEC's approval of the PCAOB's amendments to AU Section 411. The adoption of SFAS 162 will not have an impact on our financial position or results of operations.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities, or SFAS 161, an amendment of FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, or SFAS 133. SFAS 161 requires entities to provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions. The standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged, but not required. SFAS 161 also requires entities to disclose more information about the location and amounts of derivative instruments in financial statements; how derivatives and related hedges are accounted for under SFAS 133 and how the hedges affect the entity’s financial position, financial performance, and cash flows. We will apply the requirements of SFAS No. 161 on its adoption on January 1, 2009. We do not expect it to have an impact on our financial position or results of operations.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, or SFAS No. 159. SFAS No. 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair value hedge without having to comply with complex hedge accounting rules. The statement was effective for us as of January 1, 2008. We adopted SFAS No. 159 at January 1, 2008, and have elected not to apply the fair value option to any of our financial instruments not already carried at fair value in accordance with other accounting standards, and therefore the adoption of SFAS No. 159 did not impact our financial statements for the year ended December 31, 2008.

17

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurement , or SFAS No. 157. SFAS No. 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. In February 2008, the FASB issued FSP FAS 157-2, Effective Date of FASB Statement No. 157, or FSP FAS 157-2. FSP FAS 157-2, which was effective upon issuance, delays the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value at least once a year, to fiscal years beginning after November 15, 2008. On January 1, 2009, we will adopt SFAS No. 157 for nonfinancial assets and liabilities that are not measured at fair value on a recurring basis. Our nonfinancial assets and liabilities will be limited to the initial recognition of asset retirement obligations. FSP FAS 157-2 also covers interim periods within the fiscal years for items within its scope. The delay is intended to allow the FASB and its constituents the time to consider the various implementation issues associated with SFAS No. 157. We adopted SFAS No. 157 as of January 1, 2008 with respect to our derivative instruments which are measured at fair value within our financial statements. See Note 7 for disclosures pertaining to the provisions of SFAS No. 157 with regard to our fair value measurements.

18

ITEM 8.  FINANCIAL STATEMENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Atlas America Series #27-2006 L.P.

We have audited the accompanying balance sheets of Atlas America Series #27-2006 L.P. (a Delaware Limited Partnership) as of December 31, 2008 and 2007, and the related statements of operations, comprehensive loss, changes in partners’ capital, and cash flows for the years then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Atlas America Series #27-2006 L.P. as of December 31, 2008 and 2007, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

March 30, 2009

19

ATLAS AMERICA SERIES 27-2006 L.P.

BALANCE SHEETS

DECEMBER 31,

	2008		2007
ASSETS
Current assets:
Cash and cash equivalents	$	661,800	$	1,142,300
Accounts receivable-affiliate		2,478,800		3,806,400
Short-term hedge receivable due from affiliate		2,431,800		1,235,400
Total current assets		5,572,400		6,184,100
Oil and gas properties, net		19,685,600		70,039,100
Long-term hedge receivable due from affiliate		1,539,700		184,700
	$	26,797,700	$	76,407,900
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accrued liabilities	$	22,200	$	27,000
Short-term hedge liability due to affiliate		214,100		29,200
Total current liabilities		236,300		56,200
Asset retirement obligation		2,013,000		1,690,100
Long-term hedge liability due to affiliate		192,700		1,856,100
Partners' capital:
Managing general partner		5,760,400		14,585,800
Limited partners (2,840 units)		18,595,300		58,684,900
Accumulated other comprehensive loss		—		(465,200	)
Total partners' capital		24,355,700		72,805,500
	$	26,797,700	$	76,407,900

The accompanying notes are an integral part of these financial statements

20

ATLAS AMERICA SERIES 27-2006 L.P.

STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31, 2007 and 2008

	2008			2007
REVENUES
Natural gas and oil	$	12,614,700		$	12,462,800
Total revenues		12,614,700			12,462,800
COSTS AND EXPENSES
Production		2,808,300			2,468,300
Depletion		8,590,600			8,074,200
Impairment of oil and gas properties		38,135,500			10,255,500
Accretion of asset retirement obligation		96,000			110,400
General and administrative		278,400			195,100
Total expenses		49,908,800			21,103,500
Net loss	$	(37,294,100	)	$	(8,640,700	)
Allocation of net (loss) earnings:
Managing general partner	$	(4,841,900	)	$	266,100
Limited partners	$	(32,452,200	)	$	(8,906,800	)
Net loss per limited partnership unit	$	(11,427	)	$	(3,136	)

The accompanying notes are an integral part of these financial statements

21

ATLAS AMERICA SERIES 27-2006 L.P.

STATEMENTS OF COMPREHENSIVE LOSS

YEARS ENDED DECEMBER 31, 2008 AND 2007

	2008			2007
Net loss	$	(37,294,100	)	$	(8,640,700	)
Other comprehensive income (loss):
Unrealized holding gain on hedging contracts		85,600			1,151,700
Less: reclassification adjustment for loss (gains) realized in net earnings		379,600			(1,616,900	)
Total other comprehensive income (loss)		465,200			(465,200	)
Comprehensive loss	$	(36,828,900	)	$	(9,105,900	)

The accompanying notes are an integral part of these financial statements

22

ATLAS AMERICA SERIES 27-2006 L.P.

STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

YEARS ENDED DECEMBER 31, 2008 AND 2007

							Accumulated
	Managing						Other
	General			Limited			Comprehensive
	Partner			Partners			Loss			Total
Balance at December 31, 2006	$	1,246,200		$	70,881,500		$	—		$	72,127,700
Participation in revenue and costs and expenses
Net production revenues		3,258,200			6,736,300			—			9,994,500
Depletion		(1,274,200	)		(6,800,000	)		—			(8,074,200	)
Impairment of oil and gas properties		(1,618,300	)		(8,637,200	)		—			(10,255,500	)
Accretion expense		(36,000	)		(74,400	)		—			(110,400	)
General and administrative		(63,600	)		(131,500	)		—			(195,100	)
Net earnings (loss)		266,100			(8,906,800	)		—			(8,640,700	)
MGP asset contribution		14,664,700			—			—			14,664,700
Other comprehensive loss		—			—			(465,200	)		(465,200	)
Distributions to partners		(1,591,200	)		(3,289,800	)		—			(4,881,000	)
Balance at December 31, 2007	$	14,585,800		$	58,684,900		$	(465,200	)	$	72,805,500
Participation in revenue and costs and expenses
Net production revenues		3,196,900			6,609,500			—			9,806,400
Depletion		(1,455,500	)		(7,135,100	)		—			(8,590,600	)
Impairment of oil and gas properties		(6,461,200	)		(31,674,300	)		—			(38,135,500	)
Accretion expense		(31,300	)		(64,700	)		—			(96,000	)
General and administrative		(90,800	)		(187,600	)		—			(278,400	)
Net earnings (loss)		(4,841,900	)		(32,452,200	)		—			(37,294,100	)
MGP asset returned		(289,500	)		—			—			(289,500	)
Other comprehensive income		—			—			465,200			465,200
Distributions to partners		(3,694,000	)		(7,637,400	)		—			(11,331,400	)
Balance at December 31, 2008	$	5,760,400		$	18,595,300		$	—		$	24,355,700

The accompanying notes are an integral part of these financial statements

23

ATLAS AMERICA SERIES 27-2006 L.P.

STATEMENTS OF CASH FLOWS

YEARS ENDED DECEMBER 31, 2008 AND 2007

	2008			2007
Cash flows from operating activities:
Net losses	$	(37,294,100	)	$	(8,640,700	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		8,590,600			8,074,200
Impairment of oil and gas properties		41,700,300			10,255,500
Non-cash gain on derivative value		(3,564,700	)		—
Accretion of asset retirement obligation		96,000			110,400
(Decrease) increase in accrued liabilities		(4,800	)		15,000
Decrease (increase) in accounts receivable-affiliate		1,327,600			(3,791,100	)
Net cash provided by operating activities		10,850,900			6,023,300
Cash flows from financing activities:
Return of initial capital contribution to managing general partner		—			(100	)
Distributions to partners		(11,331,400	)		(4,881,000	)
Net cash used in financing activities		(11,331,400	)		(4,881,100	)
Net (decrease) increase in cash and cash equivalents		(480,500	)		1,142,200
Cash and cash equivalents at beginning of period		1,142,300			100
Cash and cash equivalents at end of period	$	661,800		$	1,142,300
Supplemental Schedule of non-cash investing and financing activities:
Assets (returned to) contributed by the managing general partner:
Tangible equipment	$	(714,200	)	$	10,500,000
Lease costs		—			1,377,300
Intangible drilling costs		424,700			2,787,500
Total assets (returned to) contributed by the managing general partner	$	(289,500	)	$	14,664,800
Asset retirement obligation	$	226,900		$	1,246,300

The accompanying notes are an integral part of these financial statements

24

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2008

NOTE 1 – DESCRIPTION OF BUSINESS

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 1,363 Limited Partners. The Partnership was formed on July 21, 2006 to drill and operate gas wells located in Pennsylvania, New York and Tennessee. At December 31, 2007, the Partnership completed its drilling activities.

In December 2006, Atlas America, Inc. contributed substantially all of its natural gas and oil exploration and production assets to Atlas Energy Resources, LLC

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A summary of significant accounting policies applied in the preparation of the accompanying financial statements follows:

Basis of Accounting

The financial statements are prepared in accordance with accounting principles generally accepted in the United States of America.

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.  Actual results could differ from these estimates.

Reclassifications

Certain reclassifications have been made to the 2007 presentation to conform to the 2008 presentation.

Accounts Receivable and Allowance for Possible Losses

In evaluating the need for an allowance for possible losses, the 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 December 31, 2008 and 2007, the Partnership’s MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.

Revenue Recognition

Revenues from sales of natural gas and oil are recognized by the Partnership when the gas and oil have been delivered to the purchaser.  The Partnership’s natural gas and oil is sold under various contracts entered into by its MGP. Virtually all of the MGP’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price the Partnership receives from the sale of its natural gas fluctuates to remain competitive with natural gas supplies generally available in the market.

25

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2008

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue Recognition (Continued)

Because there are timing differences between the delivery of the Partnership’s natural gas and oil and its receipt of a delivery statement, the Partnership has unbilled revenues. These revenues are accrued based on volumetric data from its records and its estimates of the related transportation and compression fees, which are, in turn, based on applicable product prices.  The Partnership had unbilled trade receivables of $1,789,600 at December 31, 2008 and $2,686,600 at December 31, 2007, which are included in Accounts receivable – affiliate on the Partnership’s Balance Sheets.

Fair Value of Financial Instruments

For cash, receivables and payables, the carrying amounts approximate fair values because of the short maturities of these instruments.

For derivatives the carrying value approximates fair value because they have been marked to market.

Supplemental Cash Flow Information

The Partnership considers temporary investments with a maturity at the date of acquisition of 90 days or less to be cash equivalents.  No cash was paid by the Partnership for interest or income taxes for the years ended December 31, 2008 and 2007.

Concentration of Credit Risk

Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership places its temporary cash investments in deposits with high-quality financial institutions.  At December 31, 2008, the Partnership had $696,200 in deposits of which $446,200 was over the insurance limit of the Federal Deposit Insurance Corporation.  At December 31, 2007, the Partnership had $1,192,500 in deposits of which $1,092,500 was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.

Comprehensive Loss

Comprehensive loss includes net 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 loss, are referred to as "other comprehensive income (loss)" and, for the Partnership, include changes in the fair value of hedging contracts related to commodity derivatives.

Oil and Gas Properties

Oil and gas properties are stated at cost.  Depletion is based on cost less estimated salvage value primarily using the unit-of-production method over the assets’ estimated useful lives. 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:

26

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2008

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Oil and gas properties consist of the following at the dates indicated:	December 31,
	2008			2007
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,716,900		$	1,716,900
Wells and related equipment		86,310,000			86,399,700
		88,026,900			88,116,600
Accumulated depletion		(68,341,300	)		(18,077,500	)
	$	19,685,600		$	70,039,100

The Partnership uses the successful efforts method of accounting for oil and gas producing activities.  Costs to acquire mineral interests in oil and gas properties and to drill and equip wells are capitalized.  Oil is converted to gas equivalent basis (“mcfe”) at the rate of one barrel equals 6 mcf.

The Partnership’s long-lived assets are reviewed for impairment at least annually or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows.  The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization and salvage value 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.  The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates.  The fair market value is determined as the present value of future net revenues from the production of proved reserves discounted using an annual discount rate of 12% in 2008 and 9% in 2007 and the 12 month NYMEX forward looking strip price for natural gas. If the carrying value exceeds such undiscounted cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets. During 2008 and 2007 the Partnership recognized an impairment charge of $38,135,500 and $10,255,500, respectively, net of an offsetting gain in other comprehensive income of $3,564,700 for the year ended December 31, 2008.

Upon the sale or retirement of a complete or partial unit of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to accumulated depletion. As a result of retirements the Partnership reclasified $8,200 and $256,200 from oil and gas properties, to accumulated depletion for the years ended December 31, 2008 and 2007, respectively. Upon the sale of an entire interest where the property had been assessed for impairment, a gain or loss is recognized in the Statements of Operations.

Asset Retirement Obligation

The fair values of asset retirement obligations are recognized in the period they are incurred if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of oil and gas producing properties and include costs to dismantle and relocate or dispose of production equipment, gathering systems, wells and related structures. Estimates are based on 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 Partnership does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined, see Note 8.

27

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2008

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Environmental Matters

The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment.  The Partnership has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.

The Partnership accounts for environmental contingencies in accordance with SFAS No. 5 Accounting for Contingencies.  Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated.  Atlas Energy maintains insurance that may cover in whole or in part certain environmental expenditures. For the years ended December 31, 2008 and 2007, the Partnership had no environmental matters requiring specific disclosure or the recording of a liability.

Major Customers

The Partnership’s natural gas is sold under contract to various purchasers. For the year ended December 31, 2008, sales to Equitable Gas, Dominion Field Services, Inc., Exelon Energy Company and Atmos Energy Marketing accounted for 16%, 14%, 11% and 11% respectively, of total revenues.  For the year ended December 31, 2007, sales to Knox Energy, LLC, Dominion Field Services, Inc., Equitable Gas, Exelon Energy Company and Interstate Gas Supply, Inc. accounted for 19%, 17%, 16%, 15%, and 10% respectively, of total revenues.  No other customers accounted for 10% or more of total revenues for the years ended December 31, 2008 and 2007.

Income Taxes

The Partnership is not treated as a taxable entity for federal income tax purposes.  Any item of income, gain, loss, deduction or credit flows through to the partners as though each partner had incurred such item directly.  As a result, each partner must take into account his pro rata share of all items of partnership income and deductions in computing his federal income tax liability.

Recently Issued Financial Accounting Standards

In May 2008, the Financial Accounting Standards Board, ("FASB") issued Statement of Financial Accounting Standards No. 162, The Hierarchy of Generally Accepted Accounting Policies ("SFAS 162"), which reorganizes the GAAP hierarchy. The purpose of the new standard is to improve financial reporting by providing a consistent framework for determining what accounting principles should be used when preparing the U.S. GAAP financial statements. The standard is effective 60 days after the SEC's approval of the PCAOB's amendments to AU Section 411. The adoption of SFAS 162 will not have an impact on the Partnership's financial position or results of operations.

28

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2008

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities, or SFAS 161, an amendment of FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, (“SFAS 133”). SFAS 161 requires entities to provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions. The standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged, but not required. SFAS 161 also requires entities to disclose more information about the location and amounts of derivative instruments in financial statements; how derivatives and related hedges are accounted for under SFAS 133 and how the hedges affect the entity’s financial position, financial performance, and cash flows. The Partnership will apply the requirements of SFAS No. 161 on its adoption on January 1, 2009 and does not expect it to have an impact on its financial position or results of operations.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair value hedge without having to comply with complex hedge accounting rules. The statement was effective for the Partnership as of January 1, 2008. The Partnership adopted SFAS No. 159 at January 1, 2008, and has elected not to apply the fair value option to any of its financial instruments not already carried at fair value in accordance with other accounting standards, and therefore the adoption of SFAS No. 159 did not impact the Partnership’s financial statements for the year ended December 31, 2008.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurement, (”SFAS No. 157”). SFAS No. 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. In February 2008, the FASB issued FSP FAS 157-2, Effective Date of FASB Statement No. 157, (“FSP FAS 157-2”). FSP FAS 157-2, which was effective upon issuance, delays the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value at least once a year, to fiscal years beginning after November 15, 2008. On January 1, 2009, the Partnership will adopt SFAS No. 157 for nonfinancial assets and liabilities that are not measured at fair value on a recurring basis. For the Partnership, the nonfinancial assets and liabilities will be limited to the initial recognition of asset retirement obligations. FSP FAS 157-2 also covers interim periods within the fiscal years for items within its scope. The delay is intended to allow the FASB and its constituents the time to consider the various implementation issues associated with SFAS No. 157. The Partnership adopted SFAS No. 157 as of January 1, 2008 with respect to its derivative instruments which are measured at fair value within its financial statements. See Note 7 for disclosures pertaining to the provisions of SFAS No. 157 with regard to the Partnership’s fair value measurements.

29

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2008

NOTE 3 - PARTICIPATION IN REVENUES AND COSTS

The MGP and the limited partners will generally participate in revenues and costs in the following manner:

	Managing
	General			Limited
	Partner			Partners
Organization and offering costs		100	%		0	%
Lease costs		100	%		0	%
Revenues (1)		32.60	%		67.40	%
Operating costs, administrative costs, direct costs and all other operating costs (2)		32.60	%		67.40	%
Intangible drilling costs		4.79	%		95.21	%
Tangible equipment costs		60.11	%		39.89	%

(1)   Subject to the MGP’s subordination obligation, substantially all partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 7% of the partnership revenues, which may not exceed 40%.

(2)   These costs will be charged to the partners in the same ratio as the related production revenues are credited.

NOTE 4 – CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The Partnership has entered into the following significant transactions with its MGP and its affiliates as provided under the Partnership agreement:

·   The Partnership's MGP contributed undeveloped leases necessary to cover each of the Partnership’s prospects and for the year ended December 31, 2007 received a credit to its capital account in the Partnership of $1,377,300.

·   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 in 2008 and 2007 were $172,500 and $116,100, respectively.

·   Monthly well supervision fees which are included in production expenses in the Partnership's Statements of Operations are payable at $376 and $362 per well per month in 2008 and 2007 for operating and maintaining the wells. Well supervision fees incurred in 2008 and 2007 were $868,600 and $560,100, 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 in 2008 and 2007 were $1,367,500 and $1,527,400, respectively.

·   Direct costs which are included in production and general administrative expenses in the Partnership's Statements of Operations are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf. Direct costs incurred in 2008 and 2007 were $678,100 and $459,800, respectively.

·   Assets returned to the MGP, which are disclosed in the Partnership's Statements of Cash Flows as a non-cash activity for the year ended December 31, 2008, were $289,500. Assets contributed to the MGP, which are disclosed on the Partnership’s Statement of Cash Flows as a non-cash activity for the year ended December 31, 2007, were $14,664,800.

30

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2008

NOTE 4 – CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS (Continued)

The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. The line-item “Accounts receivable–affiliate” on the Partnership’s Balance Sheets represents the net production revenues due from the MGP.

NOTE 5 - COMMITMENTS

Subject to certain conditions, investor partners may present their interests beginning in 2011 for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.

Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs.  As of December 31, 2008 the MGP has not withheld any such funds.

NOTE 6 - 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 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 revenues to the investor partners (July 2007).  Since the inception of the Partnership, the MGP has not been required to subordinate any of its net revenues to the limited partners.

NOTE 7 – DERIVATIVE INSTRUMENTS

Atlas Energy on behalf of the Partnership from time to time enters into natural gas future option contracts and collar contracts to hedge exposure to changes in natural gas 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. 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 Partnership applies the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, ("SFAS 133"). SFAS 133 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.

31

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2008

NOTE 7 – DERIVATIVE INSTRUMENTS (Continued)

At December 31, 2008, Atlas Energy had allocated open natural gas futures contracts to the Partnership related to natural gas sales covering 2,540,100 dekatherms (“Dth”) of gas, maturing through December 31, 2013 at an average settlement price of $8.22 per Dth. In addition, Atlas Energy had allocated oil futures contracts to the Partnership related to oil sales covering 4,300 barrels (“Bbls”) of oil, maturing through April 30, 2013 at an average settlement price of $98.31 per Bbl. At December 31, 2008, the Partnership reflected a net hedge asset on its Balance Sheets of $3,564,700. As a result of the asset impairment we reclassified $3,564,700 of the gains and reduced impairment expense as of December 31, 2008. The Partnership realized losses of $379,600 and gains of $1,616,900 for the year ended December 31, 2008, in its gas and oil revenues within the Statements of Operations related to the settlement of qualifying hedge instruments. Ineffective hedge gains or losses are recorded within the Statements of Operations 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 years ended December 31, 2008 and 2007, for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges.

As of December 31, 2008, 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		873,300	$	8.55	$	2,136,100
2010		603,900		8.11		585,000
2011		427,900		7.84		221,500
2012		316,100		8.05		248,600
2013		34,400		8.73		48,100
					$	3,239,300

Natural Gas Costless Collars

Production				Average
Period Ending	Option	Volumes		Floor & Cap		Fair Value
December 31,	Type	(MMbtu) (1)		(per MMbtu)		Asset (2)
2009	Puts purchased		5,500	$	11.00	$	27,100
2009	Calls sold		5,500		15.35		—
2010	Puts purchased		77,000		7.84		76,500
2010	Calls sold		77,000		9.01		—
2011	Puts purchased		171,800		7.48		85,000
2011	Calls sold		171,800		8.44		—
2012	Puts purchased		23,300		7.00		5,100
2012	Calls sold		23,300		8.32		—
2013	Puts purchased		6,900		7.00		1,600
2013	Calls sold		6,900		8.25		—
						$	195,300

32

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2008

NOTE 7 – DERIVATIVE INSTRUMENTS (Continued)

Crude Oil Fixed Price Swaps

Production			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(Bbl)		(per Bbl)		Asset (3)
2009		800	$	100.14	$	38,100
2010		700		97.40		22,100
2011		600		96.44		15,600
2012		400		96.00		10,700
2013		100		96.06		3,000
					$	89,500

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		500	$	85.00	$	16,400
2009	Calls sold		500		118.63		—
2010	Puts purchased		400		85.00		10,300
2010	Calls sold		400		112.92		—
2011	Puts purchased		400		85.00		7,300
2011	Calls sold		400		110.81		—
2012	Puts purchased		300		85.00		5,200
2012	Calls sold		300		110.06		—
2013	Puts purchased		100		85.00		1,400
2013	Calls sold		100		110.09		—
						$	40,600
				Total Net Asset		$	3,564,700

_____________

(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.

33

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2008

NOTE 7 – DERIVATIVE INSTRUMENTS (Continued)

The fair value of the derivatives is included on the Partnership’s Balance Sheets as follows:

	December 31,
	2008			2007
Short-term hedge receivable due from affiliate	$	2,431,800		$	1,235,400
Long-term hedge receivable due from affiliate		1,539,700			184,700
Short-term hedge liability due to affiliate		(214,100	)		(29,200	)
Long-term hedge liability due to affiliate		(192,700	)		(1,856,100	)
	$	3,564,700		$	(465,200	)

Fair Value of Financial Instruments

The Partnership adopted the provisions of SFAS 157 at January 1, 2008. 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. SFAS 157’s 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 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.

The Partnership uses the fair value methodology outlined in SFAS 157 to value the assets and liabilities for its outstanding derivative contracts. 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 December 31, 2008.

	Fair Value Measurements at December 31, 2008 Using
	Quoted prices		Significant other		Significant
	in active		observable		unobservable
	markets		inputs		inputs
	(Level 1)		(Level 2)		(Level 3)
Commodity-based derivatives	$	—	$	3,564,700	$	—
Total	$	—	$	3,564,700	$	—

34

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2008

NOTE 8 – ASSET RETIREMENT OBLIGATION

The Partnership accounts for its estimated plugging and abandonment costs of its oil and gas properties in accordance with SFAS 143, Accounting for Asset Retirement Obligations 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 years indicated are:

	Years Ended December 31,
	2008		2007
Asset retirement obligation at beginning of year	$	1,690,100	$	333,400
Liabilities incurred from drilling wells		—	��	1,301,500
Revision in estimates		226,900		(55,200	)
Accretion expense		96,000		110,400
Asset retirement obligation at end of year	$	2,013,000	$	1,690,100

NOTE 9 - NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)

The supplementary information summarized below presents the results of natural gas and oil activities in accordance with Statements of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities, (“SFAS No. 69”).  Annually, reserve value information is provided to the investor partners pursuant to the partnership agreement.  The partnership agreement provides a presentment feature whereby the MGP will buy partnership units, subject to annual limitations, based upon a valuation formula price in the partnership agreement. Therefore, reserve value information under SFAS No. 69 is not presented.

No consideration has been given in the following information to the income tax effect of the activities, as the Partnership is not treated as a taxable entity for income tax purposes.

(1)   Capitalized Costs Related to Oil and Gas Producing Activities

The following table presents the capitalized costs related to natural gas and oil producing activities at the periods indicated:

	At December 31,
	2008			2007
Mineral interest in proved properties:	$	1,716,900		$	1,716,900
Wells and related equipment		86,310,000			86,399,700
Accumulated depletion		(68,341,300	)		(18,077,500	)
Net capitalized cost	$	19,685,600		$	70,039,100

35

ATLAS AMERICA SERIES 27-2006 L.P.

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2008

NOTE 9 - NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (Continued)

(2)   Oil and Gas Reserve Information

The information presented below represents estimates of proved developed natural gas and oil reserves. All reserves are proved developed reserves and are located in the Appalachian Basin area. The estimates of the Partnership’s proved developed gas reserves are based upon evaluations made by management and verified by Wright & Company, Inc., an independent petroleum-engineering firm, as of December 31, 2008 and 2007. All reserves are located within the United States of America.  Reserves are estimated in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalation except by contractual arrangements.  Proved developed reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made.  Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

Proved developed reserves are generally those which are expected to be recovered through existing wells with existing equipment and operating methods.  Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

There are numerous uncertainties inherent in estimating quantities of proved developed reserves and in projecting future net revenues and the timing of development expenditures.  The reserve data presented represents estimates only and should not be construed as being exact.  In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of the Partnership’s oil and gas reserves or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors for which effects have not been provided. The increase in the Partnership's reserves for the year ended December 31, 2008, is primarily due to extensions, discoveries and other additions for the majority of wells being drilled as compared to prior year.

	Natural Gas			Oil
	(Mcf)			(Bbls)
Balance at December 31, 2006		2,841,800			2,300
Production		(1,446,600	)		(3,200	)
Extensions, discoveries and other additions		10,975,900			—
Revisions to previous estimates		(1,389,400	)		18,900
Balance at December 31, 2007		10,981,700			18,000
Production		(1,336,900	)		(3,600	)
Revisions to previous estimates		(2,725,300	)		(1,600	)
Balance at December 31, 2008		6,919,500			12,800

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ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE:

None.

ITEM 9A.  CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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

Under the supervision of our Chairman of the Board of Directors, Chief Executive Officer and President, 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 Chairman of the Board of Directors, Chief Executive Officer and President, concluded that, as of December 31, 2008, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of management, including our Chairman of the Board of Directors, Chief Executive Officer and President, we conducted an evaluation of the effectiveness of internal control over financial reporting based upon criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (COSO framework).

An effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, effectiveness of an internal control system in future periods cannot be guaranteed because the design of any system of internal controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any control design will succeed in achieving its stated goals under all potential future conditions. Over time certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.

Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting as of December 31, 2008 was effective.

This annual report does not include an attestation report by Grant Thornton regarding internal control over financial reporting. Management's report was not subject to attestation by Grant Thornton pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management's report in this annual report.

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ITEM 9B.  OTHER INFORMATION

None.

PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Atlas Energy is headquartered at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108, which is also our MGP’s primary office.

Executive Officers and Directors.  The executive officers and directors of our MGP will serve until their successors are elected.  The executive officers and directors of our MGP are as follows:

NAME	AGE	POSITION OR OFFICE
Freddie M. Kotek	53	Chairman of the Board of Directors, Chief Executive Officer and President
Frank P. Carolas	49	Executive Vice President – Land and Geology and a Director
Jeffrey C. Simmons	50	Executive Vice President – Operations and a Director
Jack L. Hollander	52	Senior Vice President – Direct Participation Programs
Sean P. McGrath	37	Chief Accounting Officer
Michael L. Staines	59	Senior Vice President, Secretary and a Director
Matthew A. Jones	47	Chief Financial Officer

With respect to the biographical information set forth below:

·   the approximate amount of an individual’s professional time devoted to the business and affairs of our MGP and Atlas America have been aggregated because there is no reasonable method for them to distinguish their activities between the two companies; and

·   for those individuals who also hold senior positions with other affiliates of our MGP, if it is stated that they devote approximately 100% of their professional time to our MGP and Atlas America, it is because either the other affiliates are not currently active in drilling new wells, such as Viking Resources or Resource Energy, and the individuals are not required to devote a material amount of their professional time to the affiliates, or there is no reasonable method to distinguish their activities between our MGP and Atlas America as compared with the other affiliates of our MGP, such as Viking Resources or Resource Energy.

Freddie M. Kotek. President and Chief Executive Officer since January 2002 and Chairman of the Board of Directors since September 2001. Mr. Kotek has been Executive Vice President of Atlas America since February 2004, and served as a director from September 2001 until February 2004 and served as Chief Financial Officer from February 2004 until March 2005.  Mr. Kotek was a Senior Vice President of Resource America, and President of Resource Leasing, Inc. (a wholly-owned subsidiary of Resource America) from 1995 until May 2004 when he resigned from Resource America and all of its subsidiaries which are not subsidiaries of Atlas America.  Mr. Kotek was President of Resource Properties from September 2000 to October 2001 and its Executive Vice President from 1993 to August 1999.  Mr. Kotek received a Bachelor of Arts degree from Rutgers College in 1977 with high honors in Economics. He also received a Master in Business Administration degree from the Harvard Graduate School of Business Administration in 1981. Mr. Kotek will devote approximately 95% of his professional time to the business and affairs of the MGP and Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc., and the remainder of his professional time to the business and affairs of the MGP’s other affiliates.

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Frank P. Carolas. Executive Vice President-Land and Geology and a Director since January 2001. Mr. Carolas has been an Executive Vice President of Atlas America since January 2001 and served as a Director of Atlas America from January 2002 until February 2004. Mr. Carolas has been a Senior Vice President of Atlas Energy Management, Inc. since 2006.  Mr. Carolas was a Vice President of Resource America from April 2001 until May 2004 when he resigned from Resource America.  Mr. Carolas served as Vice President of Land and Geology for the MGP from July 1999 until December 2000 and for Atlas America from 1998 until December 2000. Before that Mr. Carolas served as Vice President of Atlas Energy Group, Inc. from 1997 until 1998, which was the former parent company of the MGP. Mr. Carolas is a certified petroleum geologist and has been with the MGP and its affiliates since 1981.  He received a Bachelor of Science degree in Geology from Pennsylvania State University in 1981 and is an active member of the American Association of Petroleum Geologists. Mr. Carolas devotes approximately 100% of his professional time to the business and affairs of the MGP, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.

Jeffrey C. Simmons. Executive Vice President-Operations and a Director since January, 2001. Mr. Simmons has been an Executive Vice President of Atlas America since January 2001 and was a Director of Atlas America from January 2002 until February 2004.  Mr. Simmons has been a Senior Vice President of Atlas Energy Management, Inc., since 2006.  Mr. Simmons was a Vice President of Resource America from April 2001 until May 2004 when he resigned from Resource America.  Mr. Simmons served as Vice President of Operations for the MGP from July 1999 until December 2000 and for Atlas America from 1998 until December 2000. Mr. Simmons joined Resource America in 1986 as a senior petroleum engineer and has served in various executive positions with its energy subsidiaries since then.  Mr. Simmons received his Bachelor of Science degree with honors from Marietta College in 1981 and his Masters degree in Business Administration from Ashland University in 1992. Mr. Simmons devotes approximately 90% of his professional time to the business and affairs of the MGP, Atlas America, and the remainder of his professional time to the business and affairs of the MGP’s other affiliates, primarily Viking Resources and Resource Energy, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.

Jack L. Hollander. Senior Vice President – Direct Participation Programs since January 2002 and before that he served as Vice President – Direct Participation Programs from January 2001 until December 2001. Mr. Hollander also serves as Senior Vice President – Direct Participation Programs of Atlas America since January 2002. Mr. Hollander practiced law with Rattet, Hollander & Pasternak, concentrating in tax matters and real estate transactions, from 1990 to January 2001, and served as in-house counsel for Integrated Resources, Inc. (a diversified financial services company) from 1982 to 1990. Mr. Hollander earned a Bachelor of Science degree from the University of Rhode Island in 1978, his law degree from Brooklyn Law School in 1981, and a Master of Law degree in Taxation from New York University School of Law Graduate Division in 1982. Mr. Hollander is a member of the New York State bar, and the Chairman of the Investment Program Association which is an industry association, as of March 2005.  Mr. Hollander devotes approximately 100% of his professional time to the business and affairs of the MGP, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.

Sean P. McGrath. Chief Accounting Officer since December 31, 2008. Mr. McGrath also has been the Chief Accounting Officer of Atlas America, Inc. and ATN since December 31, 2008. Mr. McGrath has been the Chief Accounting Officer of Atlas Pipeline Partners GP since May 2005 and Chief Accounting Officer of Atlas Pipeline Holdings GP since January 2006. Mr. McGrath was the Controller of Sunoco Logistics Partners L.P., a publicly-traded partnership that transports, terminals and stores refined products and crude oil from 2002 to 2005. Mr. McGrath is a Certified Public Accountant and received his Bachelor of Science degree in accounting from LaSalle University in 1993. Mr. McGrath will devote approximately 70% of his professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of the managing general partner’s other affiliates, including Atlas Pipeline Partners GP.

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Michael L. Staines. Senior Vice President, Secretary, and a Director since 1998. Mr. Staines has been an Executive Vice President and Secretary of Atlas America since 1998. Mr. Staines was a Senior Vice President of Resource America from 1989 until May, 2005 when he resigned from Resource America.  Mr. Staines was a director of Resource America from 1989 to February 2000 and Secretary from 1989 to October 1998. Mr. Staines has been President of Atlas Pipeline Partners GP since January 2001 and its Chief Operating Officer and a member of its Managing Board since its formation in November 1999.  Mr. Staines is a member of the Ohio Oil and Gas Association and the Independent Oil and Gas Association of New York. Mr. Staines received a Bachelor of Science degree from Cornell University in 1971 and a Master of Business degree from Drexel University in 1977. Mr. Staines devotes approximately 5% of his professional time to the business and affairs of the MGP and Atlas America, and the remainder of his professional time to the business and affairs of the MGP’s other affiliates, including Atlas Pipeline Partners GP.

Matthew A. Jones.  Chief Financial Officer since March 2006 for Atlas Resources, LLC.  Mr. Jones has been the Chief Financial Officer since January 2006 and a director of Atlas Pipeline Holdings since February 2006 and has been Chief Financial Officer of Atlas Pipeline Partners GP and Atlas America since March 2005.  He has been the Chief Financial Officer and a director of Atlas Energy Resources and Atlas Energy Management since their formation.  From 1996 to 2005, Mr. Jones worked in the Investment Banking Group at Friedman Billings Ramsey, concluding as Managing Director.  Mr. Jones worked in Friedman Billings Ramsey’s Energy Investment Banking Group from 1999 to 2005, and in Friedman Billings Ramsey’s Specialty Finance and Real Estate Group from 1996 to 1999.  Mr. Jones is a Chartered Financial Analyst. Mr. Jones devotes approximately 55% of his professional time to the business and affairs of the MGP, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc. and the remainder of his professional time to the business and affairs of the MGP’s other affiliates.

Audit Committee Financial Expert.  The Board of Directors of our MGP acts as the audit committee.  The Board of Directors has determined that Freddie M. Kotek meets the requirement of an “audit committee financial expert,” he is not independent.

Remuneration of Officers and Directors.  No officer or director of the MGP will receive any direct remuneration or other compensation from the Partnership.  These persons will receive compensation solely from affiliated companies of the MGP.

Code of Business Conduct and Ethics.  Because the Partnership does not directly employ any persons, the MGP has determined that the partnership will rely on a Code of business Conduct and Ethics adopted by Atlas America, Inc. and/or Atlas Energy Resources, LLC that applies to the principal executive officer, principal financial officer and principal accounting officer of the MGP, as well as to persons performing services for the MGP generally.  You may obtain a copy of this Code of Business Conduct and Ethics by a request to the MGP at Atlas Resources, LLC, Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108.

ITEM 11.  EXECUTIVE COMPENSATION

We have no employees and rely on the employees of our MGP and its affiliates for all services. No officer or director of our MGP will receive any direct remuneration or other compensation from us. Those persons will receive compensation solely from affiliated companies of our MGP. See Item 13 “Certain Relationships and Related Transactions, and Director Independence” for a discussion of compensation paid by us to our MGP.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

As of December 31, 2008, we had 2,840 investor units outstanding. No officer or director of our MGP owns any units.  Although, subject to certain conditions, investor partners may present their units to us beginning in 2011 for purchase, the MGP is not obligated by the Partnership agreement from purchasing more than 5% of our total outstanding units in any calendar year.

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Organizational and Security Ownership of Beneficial Owners.  Atlas America owns approximately 49.4% of the limited liability company interest of Atlas Energy Resources, LLC which owns 100% of the limited liability company interests of Atlas Energy Operating Company, LLC, which owns 100% of the limited liability company interests of AIC, LLC, which owns 100% of the  limited liability company interest of the MGP.  The officers and directors of Atlas America and Atlas Energy Resources, LLC are set forth below.  The directors of AIC, LLC are Jonathan Z. Cohen, Michael L. Staines, and Jeffrey Simmons.  The biographies of Messrs., Staines and Simmons are set forth above.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Oil and Gas Revenues.  Our MGP is allocated 32.60% of our oil and gas revenues in return for its payment and/or contribution of services towards our syndication and offering costs equal to 12% of our subscriptions, its payment of 60.11% of the tangible costs of drilling and completing our wells and its contribution to us of all of our oil and gas leases.  These capital contributions from our MGP totaled $24,126,600. During the years ended December 31, 2008 and 2007, our MGP received $3,196,900 and $3,258,200, respectively, from our net production revenues.

Leases.  Following the final closing date, for the offering of our units to potential investors, which was December 29, 2006 our MGP contributed oil and gas leases to us covering 256 undeveloped prospects for the wells we drilled and received a credit to its capital account in the amount of $1,377,300 for the year ended December 31, 2007.

Administrative Costs.  Our MGP and its affiliates receive an unaccountable, fixed fee reimbursement for their administrative costs of $75 per well per month, which is proportionately reduced if we acquire less than 100% of the working interest in a well. During the years ended December 31, 2008 and 2007, our MGP received $172,500 and $116,100, respectively for its administrative costs.

Direct Costs.  Our MGP and its affiliates are reimbursed for all direct costs expended on our behalf.  During the years ended December 31, 2008 and 2007 our MGP’s received $678,100 and $459,800, respectively as reimbursement for direct costs.

Well Charges.  Our MGP, as operator, is reimbursed at actual cost for all direct expenses incurred on our behalf and receives well supervision fees for operating and maintaining the wells during producing operations in the amount of $376 and $362 per well per month in 2008 and 2007, respectively subject to an annual adjustment for inflation. The well supervision fees are proportionately reduced to the extent we acquire less than 100% of the working interest in a well.  For the years ended December 31, 2008 and 2007 our MGP received $868,600 and $560,100, respectively for well supervision fees.

Transportation Fees.  We pay gathering fees to our MGP at a competitive rate for each mcf of our natural gas transported.  Transportation rate is generally 13% of the natural gas sales price.  For the years ended December 31, 2008 and 2007 $1,367,500 and $1,527,400, respectively was paid to our MGP for gathering fees. In turn, our MGP paid 100% of this amount to Atlas America, for the use of its gathering system in transporting a majority of our natural gas production.

Other Compensation.  For the year ended December 31, 2008 our MGP did not advance any funds to us, or did they provide us with any equipment, supplies, or other services.

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ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees. The aggregate fees recognized by the Partnership from our independent auditors, Grant Thornton LLP, for professional services rendered for the audit of our annual financial statements for the years ended December 31, 2008 and 2007, and for the reviews of the financial statements included in our quarterly reports on Form 10-Q during such years were $34,600 and $45,700, respectively.

Procedures for Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditor. Pursuant to its charter, the Audit Committee of our MGP is responsible for reviewing and approving, in advance, any audit and any permissible non-audit engagement or relationship between us and our independent auditors.  We do not have a separate audit committee.

PART IV

ITEM 15.  EXHIBITS

EXHIBIT INDEX

	Description	Location
4(a)	Certificate of Limited Partnership for Atlas America	Previously filed in our Form S-1 on
	Series 27-2006 L.P.	August 9, 2005
4(b)	Amended and Restated Certificate and Agreement of Limited	Previously filed in our Form S-1 on
	Partnership for Atlas America Series 27-2006 L.P. (1)	August 9, 2005
4(c)	Drilling and Operating Agreement for Atlas America	Previously filed in our Form S-1 on
	Series 27-2006 L.P. (1)	August 9, 2005
31.1	Rule 13a-14(a)/15(d) – 14 (a) Certification
31.2	Rule 13a-14(a)/15(d) – 14 (a) Certification.
32.1	Section 1350 Certification.
32.2	Section 1350 Certification.

______________

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

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SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
Atlas America Series 27-2006 L.P.
Date:  March 30, 2009	Atlas Resources, LLC, Managing General Partner
	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:  March 30, 2009	By: /s/ Freddie M. Kotek
	Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive
	Officer and President
Date:  March 30, 2009	By: /s/ Frank P. Carolas
	Frank P. Carolas, Executive Vice President – Land and Geology
Date:  March 30, 2009	By: /s/ Jeffrey C. Simmons
	Jeffrey C. Simmons, Executive Vice President – Operations
Date:  March 30, 2009	By: /s/ Sean P. McGrath
	Sean P. McGrath, Chief Accounting Officer
Date:  March 30, 2009	By: /s/ Matthew A. Jones
	Matthew A. Jones, Chief Financial Officer

Supplemental information to be furnished with reports filed pursuant to Section 15(d) of the

Exchange Act by Non-reporting Issuers

An annual report will be furnished to security holders subsequent to the filing of this report.

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