SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2009

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

FOR THE TRANSITION PERIOD FROM ___________ TO _____________.

Commission file number:  000-25170

AURORA OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

Utah	87-0306609
(State or other Jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

4110 Copper Ridge Dr, Suite 100

Traverse City, Michigan 49684

(Address of principal executive offices)

(231) 941-0073

(Registrant’s telephone number, including area code)

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  x      No  ¨

Indicate by check mark whether the registrant is a large 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.

Large accelerated filer  ¨	Accelerated filer  ¨
Non-accelerated filer   ¨  (do not check if a smaller reporting company)	Smaller reporting company  x

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

Yes  ¨      No  x

The number of shares of the registrant’s common stock outstanding as of May 5, 2009, was 103,282,788.

FORM 10-Q

INDEX

PART I	FINANCIAL INFORMATION	1
Item 1.	Condensed Consolidated Financial Statements	2
Condensed Consolidated Balance Sheets as of March 31, 2009 (Unaudited), and December 31, 2008 (Audited)		2
Unaudited Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2009, and 2008		4
Unaudited Condensed Consolidated Statements of Equity for the Three Months Ended March 31, 2009, and 2008		5
Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2009, and 2008		6
Notes to Unaudited Condensed Consolidated Financial Statements		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 4.	Controls and Procedures	37
PART II	OTHER INFORMATION	38
Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3.	Defaults Upon Senior Securities	38
Item 4.	Submission of Matters to a Vote of Security Holders	38
Item 5.	Other Information	38
Item 6.	Exhibits	38
Signatures		41

i

PART I

Cautionary Note Regarding Forward-Looking Statements

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  All statements other than statements of historical facts are forward-looking statements.  You can find many of these statements by looking for words such as “believes,” “expects,” “anticipates,” “estimates,” “intends,” or similar expressions used in this report.

These forward-looking statements are subject to numerous assumptions, risks, and uncertainties.  Factors which may cause our actual results, performance, or achievements to be materially different from any future results, performance, or achievements expressed or implied by us in those statements include, among others, the following:

· changes in general economic, market, industry, or business conditions;

· the volatibility of natural gas and oil prices caused in part by the volatility of domestic and international demand for oil and natural gas;

· impacts the current national and international financial crisis may have on our business and financial condition;

· our ability to execute certain business strategies and debt restructuring initiatives;

· our ability to increase our production and oil and natural gas income through exploration and development;

· the anticipated impact on production of our well enhancement program, Antrim remediation program, or other corrective actions that we may take in an attempt to improve production;

· uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and the timing of development expenditures;

· leasehold terms expiring before production can be established;

· declines in the values of our natural gas and oil properties resulting in ceiling test write-downs;

· fluctuations in the values of certain of our assets and liabilities;

· actions taken with respect to non-performance by third parties, including suppliers, contractors, operators, processors, customers, and counterparties;

· drilling and operating risks;

· drilling and operating activities that do not result in commercially productive reserves;

· the availability of equipment, such as drilling rigs and transportation pipelines;

· the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity.

Because such statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements.  You are cautioned not to place undue reliance on such statements, which speak only as of the date of this report.

Certain Definitions

As used in this report, “mcf” means thousand cubic feet, “mmcf” means million cubic feet, “bcf” means billion cubic feet, “bbl” means barrel, “mbbls” means thousand barrels, and “mmbbls” means million barrels.  Also in this report, “boe” means barrel of oil equivalent, “mcfe” means thousand cubic feet of natural gas equivalent, “mmcfe” means million cubic feet of natural gas equivalent, “mmbtu” means million British thermal units, and “bcfe” means billion cubic feet of natural gas equivalent.  Natural gas equivalents and crude oil equivalents are determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate, or natural gas liquids.  All estimates of reserves and information related to production contained in this report, unless otherwise noted, are reported on a “net” basis. References to “us,” “we,” and “our” in this report refer to Aurora Oil & Gas Corporation, together with its subsidiaries.

1

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS
	March 31, 2009 (Unaudited)			December 31, 2008 (Audited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	7,649,457		$	10,005,138
Short-term investments		658,643			1,114,627
Accounts receivable:
Oil and natural gas sales		1,339,507			2,100,363
Joint interest owners		587,911			676,299
Field service and sales		622,041			520,126
Materials inventory		1,021,640			1,028,137
Prepaid expenses and other current assets		1,177,419			999,835
Total current assets		13,056,618			16,444,525
PROPERTY AND EQUIPMENT:
Land		264,022			264,022
Oil and natural gas properties, using full cost accounting:
Proved properties		35,185,218			88,116,757
Unproved properties		48,053,505			46,827,488
Less: accumulated depletion and amortization		(20,411,922	)		(19,810,023	)
Total oil and natural gas properties, net		62,826,801			115,134,222
Other property and equipment:
Pipelines, processing facilities, and compression		11,056,319			11,056,319
Other property and equipment		5,857,011			5,876,830
Less: accumulated depreciation		(2,806,454	)		(2,481,626	)
Total other property and equipment, net		14,106,876			14,451,523
Total property and equipment, net		77,197,699			129,849,767
OTHER ASSETS:
Note receivable		11,756,205			12,000,000
Intangibles (net of accumulated amortization of $41,666 and $37,499, respectively)		58,334			62,501
Debt issuance costs (net of accumulated amortization of $967,072 and $846,397, respectively)		1,090,665			1,211,340
Other		624,556			632,948
Total other assets		13,529,760			13,906,789
TOTAL ASSETS	$	103,784,077		$	160,201,081

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

2

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (continued)
	March 31, 2009 (Unaudited)			December 31, 2008 (Audited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	3,923,462		$	4,082,298
Accrued exploration, development, and leasehold costs		92,169			50,317
Current portion of obligations under capital leases		-			900
Current portion of note payable		53,724			53,014
Current portion of mortgage payables		466,604			124,550
Senior secured credit facility		72,021,446			72,021,446
Second lien term loan		52,999,397			50,980,022
Total current liabilities		129,556,802			127,312,547
LONG-TERM LIABILITIES:
Asset retirement obligation		1,719,255			1,686,393
Notes payable		121,392			135,119
Mortgage payables		2,541,617			2,915,039
Other long-term liabilities		447,896			528,908
Total long-term liabilities		4,830,160			5,265,459
Total liabilities		134,386,962			132,578,006
COMMITMENTS, CONTINGENCIES, AND SUBSEQUENT EVENTS (Note 9 and Note 11)
(DEFICIT) EQUITY
Shareholders’ (deficit) equity:
Common stock, $0.01 par value; authorized 250,000,000 shares; issued and outstanding 103,282,788		1,032,828			1,032,828
Additional paid-in capital		142,794,818			142,518,095
Accumulated deficit		(174,636,887	)		(116,395,785	)
Total shareholders’ (deficit) equity		(30,809,241	)		27,155,138
Noncontrolling interest		206,356			467,937
Total (deficit) equity		(30,602,885	)		27,623,075
TOTAL LIABILITIES AND (DEFICIT) EQUITY	$	103,784,077		$	160,201,081

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

3

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
	Three Months Ended March 31,
	2009			2008
REVENUES:
Oil and natural gas sales	$	3,166,175		$	6,442,558
Pipeline transportation and marketing		167,201			105,261
Field service and sales		480,038			123,559
Interest and other		350,623			102,687
Total revenues		4,164,037			6,774,065
EXPENSES:
Production taxes		110,410			339,314
Production and lease operating expense		2,205,885			2,670,144
Pipeline and processing operating expense		139,613			87,893
Field services expense		417,323			119,155
General and administrative expense		2,790,705			1,997,061
Oil and natural gas depletion and amortization		595,501			979,908
Other assets depreciation and amortization		342,807			355,773
Interest expense		2,121,829			1,462,412
Ceiling write-down of oil and gas properties		53,639,522			-
Taxes (refunds), other		34,144			(71,292	)
Total expenses		62,397,739			7,940,368
NET LOSS		(58,233,702	)		(1,166,303	)
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		(7,400	)		(15,105	)
NET LOSS ATTRIBUTABLE TO AURORA COMMON SHAREHOLDERS	$	(58,241,102	)	$	(1,181,408	)
NET LOSS PER COMMON SHARE ATTRIBUTABLE TO AURORA COMMON SHAREHOLDERS—BASIC and DILUTED	$	(0.56	)	$	(0.01	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING —BASIC and DILUTED		103,282,788			102,227,258

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

4

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)
	Three Months Ended March 31,
	2009					2008
	Shares		Amount			Shares		Amount
SHAREHOLDERS’ (DEFICIT) EQUITY COMMON STOCK:
Balance, beginning		103,282,788	$	1,032,828			101,769,456	$	1,017,695
Exercise of stock options and warrants		-		-			663,332		6,633
Balance, ending		103,282,788		1,032,828			102,432,788		1,024,328
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning				142,518,095					140,541,460
Stock-based compensation				276,723					693,652
Exercise of stock options and warrants				-					367,117
Balance, ending				142,794,818					141,602,229
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Balance, beginning				-					(385,043	)
Changes in fair value of derivative instruments				-					(11,253,481	)
Recognition of gain on derivative instruments				-					(259,835	)
Balance, ending				-					(11,898,359	)
ACCUMULATED DEFICIT:
Balance, beginning				(116,395,785	)				(9,031,123	)
Net loss				(58,241,102	)				(1,181,408	)
Balance, ending				(174,636,887	)				(10,212,531	)
TOTAL SHAREHOLDERS’ (DEFICIT) EQUITY				(30,809,241	)				120,515,667
NONCONTROLLING INTEREST
Balance, beginning				467,937					112,661
Repurchase of membership interest				(268,981	)				-
Net income				7,400					15,105
TOTAL NONCONTROLLING INTEREST				206,356					127,766
TOTAL (DEFICIT) EQUITY			$	(30,602,885	)			$	120,643,433

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

5

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
	Three Months Ended March 31,
CASH FLOWS FROM OPERATING ACTIVITIES:	2009			2008
Net loss attributable to Aurora common shareholders	$	(58,241,102	)	$	(1,181,408	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation, depletion, and amortization		938,308			1,335,681
Ceiling write-down of oil and gas properties		53,639,522			-
Amortization of debt issuance costs		132,980			137,512
Accretion of asset retirement obligation		28,841			27,545
Recognition of deferred gain on sale of natural gas compression equipment		(33,207	)		(33,207	)
Stock-based compensation		276,723			672,962
Equity loss of other investments and other		-			30
Interest paid-in-kind on second lien term loan		2,019,375			-
Unrealized loss on ineffective commodity derivative		-			968,556
Loss on sale and disposal of property and equipment		4,713			-
Net income attributable to noncontrolling interests		7,400			15,105
Changes in operating assets and liabilities:
Accounts receivables		612,379			1,149,849
Materials inventory		7,247			137,768
Prepaid expenses and other assets		(169,015	)		(133,980	)
Accounts payable and accrued liabilities		(201,743	)		237,460
Drilling advance – liabilities		-			(121,762	)
Net cash (used in) provided by operating activities		(977,579	)		3,212,111
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and natural gas properties		(1,625,465	)		(6,375,696	)
Leasehold expenditures, net		(314,347	)		(1,174,830	)
Sale of oil and natural gas properties		39,303			60,000
Purchase of member interest in Hudson Pipeline & Processing Co., LLC		(132,087	)		-
Acquisitions/additions for pipeline, property, and equipment		-			(16,947	)
Payments received on note receivable		243,795			-
Net additions and sales of other investments		-			5,843
Redesignation of cash equivalents to short-term investments		455,984			-
Net cash used in investing activities		(1,332,817	)		(7,501,630	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term bank borrowings		-			100,000
Short-term bank payments		-			(100,000	)
Advances on senior secured credit facility		-			9,000,000
Payments on mortgage obligations and notes payable		(45,285	)		(43,867	)
Payments of financing fees on credit facilities		-			(29,142	)
Proceeds from exercise of options and warrants		-			373,750
Other		-			(110,782	)
Net cash (used in) provided by financing activities		(45,285	)		9,189,959
Net (decrease) increase in cash and cash equivalents		(2,355,681	)		4,900,440
Cash and cash equivalents, beginning of the period		10,005,138			2,425,678
Cash and cash equivalents, end of the period	$	7,649,457		$	7,326,118

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

6

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited-continued)
	Three Months Ended March 31,
NONCASH FINANCING AND INVESTING ACTIVITIES:	2009		2008
Oil and natural gas properties asset retirement obligation	$	4,021	$	14,317
Accrued exploration and development costs on oil and natural gas properties		57,713		73,304
Accrued leasehold costs		81,097		320,481
Oil and natural gas properties capitalized stock-based compensation		-		20,690
Conversion of accounts receivable to notes receivable		2,009		6,170
Vehicle purchase through financing		-		44,536
Assumption of capital call as part of the member interest purchase in Hudson Pipeline & Processing Co., LLC		136,894		-
SUPPLEMENTAL INFORMATION OF INTEREST AND INCOME TAXES PAID (RECEIVED)
Interest	$	1,123,079	$	2,502,870
Income taxes		15,000		(111,789	)

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

7

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS

Aurora Oil & Gas Corporation (“AOG”) and its wholly-owned subsidiaries (collectively, the “Company”) is an independent energy company focused on the exploration, development, and production of unconventional natural gas reserves.  The Company generates most of its revenue from the production and sale of natural gas.  The Company is focused on developing operating interests in unconventional drilling programs in the Michigan Antrim shale and the New Albany shale of Indiana and Kentucky.  The Company’s drilling program is dependent on access to the credit markets.  Due to the current economic events within the banking industry and the Company currently being in default under the senior secured credit facility and second lien term loan more fully described in Note 6 “Debt”, the Company is having difficulty securing the necessary credit to move forward with a development program.  The Company is a Utah corporation whose common stock is listed and traded on the NYSE Alternext US LLC (formerly known as the American Stock Exchange).  As more fully described in Note 11 “Subsequent Events,” the Company is expected to voluntarily delist from the NYSE Alternext US LLC on or about May 11, 2009 and move to Over-The-Counter (“OTC”).

The Company’s revenue, profitability, and future rate of growth are substantially dependent on prevailing prices of natural gas and oil.  Historically, the energy markets have been very volatile, and it is likely that oil and natural gas prices will continue to be subject to wide fluctuations in the future.  Natural gas prices materially declined during the fourth quarter 2008 and continued to decline during the first quarter 2009 which as more fully described in Note 2 “Basis of Presentation and Summary of Significant Accounting Policies” contributed to a ceiling write-down of oil and gas properties in the amount of $53.6 million for the three months ended March 31, 2009.  A continued or extended decline in natural gas and oil prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows, access to capital, and the quantities of natural gas and oil reserves that can be economically produced.  Prior to the termination of the Company’s natural gas derivatives during October 2008, the Company periodically entered into various derivative instruments with a major financial institution to mitigate a portion of the exposure to adverse market changes.  Currently, the Company does not have the ability to hedge its production due to the Company’s bank defaults and the lack of borrowing base capacity to meet margin calls.  Accordingly, the Company is presently exposed to the fluctuation of natural gas prices.

NOTE 2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The financial information included herein is unaudited, except the balance sheet as of December 31, 2008, which has been derived from our audited consolidated financial statements as of December 31, 2008.  Such information includes all adjustments (consisting solely of normal recurring adjustments), which are, in the opinion of management, necessary for a fair presentation of financial position, results of operations, and cash flows for the interim periods.  The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year.

Certain information, accounting policies, and footnote disclosures normally included in consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission. These condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2008.

8

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

As more fully described in Note 4 “Recent Accounting Pronouncements,” on January 1, 2009, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 160 “Noncontrolling Interests in Consolidated Financial Statements, an amendment of Accounting Research Bulletin (“ARB”) No. 51” (“SFAS 160”) and SFAS No. 141R (revised 2007), “Business Combination” (“SFAS 141R”).  SFAS 160 changed the presentation requirements for noncontrolling (minority) interest and SFAS 141R change accounting and reporting requirements for business acquisitions.  SFAS 160 and SFAS 141R applies to noncontrolling interests prospectively from the date of adoption.  However, the presentation and disclosure requirements of SFAS 160 were applied retrospectively for all periods presented.

Principles of Consolidation

The accompanying condensed consolidated financial statements of the Company include the accounts of the wholly-owned subsidiaries and other subsidiaries in which the Company holds a controlling financial or management interest of which the Company determined that it is primary beneficiary.  The Company uses the equity method of accounting for investments in entities in which the Company has an ownership interest between 20% and 50% and exercises significant influence.  The Company also consolidates its pro rata share of oil and natural gas joint ventures.  All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of condensed consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.  Significant estimates underlying these condensed consolidated financial statements include the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties and to evaluate the full cost pool in the ceiling test analysis, the estimated fair value of asset retirement obligations, and fair value of stock options.

Reclassifications

Certain reclassifications have been made to the condensed consolidated financial statements for the three months ended March 31, 2008, in order to conform to the December 31, 2008, and March 31, 2009, presentation.  These reclassifications had no effect on net loss as previously reported.

Short-Term Investments

The Company’s short-term investments are comprised of an investment in The Reserve Primary Fund (the “Primary Fund”), a money market fund that has suspended redemptions and is being liquidated.  In accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” the Company records these investments as trading securities at fair value.

9

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

In mid-September 2008, the net asset value of the Primary Fund decreased below $1 per share as a result of the Primary Fund’s valuing at zero its holdings of debt securities issued by Lehman Brothers Holdings, Inc., which filed for bankruptcy on September 15, 2008.  While management expects to receive substantially all of the Company’s current holdings in the Primary Fund, management cannot predict when this will occur or the amount that ultimately will be received.  Accordingly, management has reclassified the investment from cash and cash equivalents to short-term investments as of March 31, 2009 and December 31, 2008.

As more fully described in Note 11 “Subsequent Events,” on April 15, 2009, the Company granted as collateral its short-term investments to secure the outstanding letters of credit more fully described in Note 9 “Commitments and Contingencies.”

Inventory

The Company’s inventory consists primarily of casing and well equipment and is carried at the lower of cost or market.

Capitalized Interest

The Company capitalizes interest on debt related to expenditures made in connection with exploration and development projects that are not subject to the full cost amortization pool. Interest is capitalized only for the period that exploration and development activities are in progress. Interest is capitalized using a weighted average interest rate based on the outstanding borrowing and cost of equity of the Company. Capitalized interest was $1.2 million for each of the three months ended March 31, 2009, and 2008.

Oil and Natural Gas Properties

The Company utilizes the full cost method of accounting for oil and natural gas properties.  Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration, and development activities of oil and natural gas, including costs of unsuccessful exploration and overhead charges directly related to acquisition, exploration, and development activities, are capitalized.  The Company is currently participating in oil and natural gas exploration and development projects in the Antrim shale of Michigan, the New Albany shale of southern Indiana and western Kentucky.  Thus, all capitalized costs of oil and natural gas properties considered proven, are amortized on the unit-of-production method using estimates of proven reserves.  No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and natural gas properties unless the sale represents a significant portion of oil and natural gas properties and the gain or loss significantly alters the relationship between capitalized costs and proven reserves.

Capitalized costs of oil and natural gas properties may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proven reserves plus the lower of cost or fair value of unproven properties. Should capitalized costs exceed this ceiling, an impairment is recognized.  The present value of estimated future net cash flows is computed by applying current prices of oil and natural gas to estimated future production of proved oil and natural gas reserves as of period end less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.  For the three months ended March 31, 2009, the Company recognized a ceiling write-down of oil and gas properties in the amount of $53.6 million as a result of the carrying amount of oil and gas properties subject to amortization exceeding the full cost ceiling limitation.

10

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Asset Retirement Obligation

The Company’s Asset Retirement Obligation (“ARO”) represents the estimated present value of the amount the Company will incur to dismantle and remove production equipment and facilities and restore and reclaim a field’s surface to a condition similar to that existing before oil and natural gas extraction began.

In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for the Company.  After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis within the related full cost pool.

There were no revisions made for the three months ended March 31, 2009.  Revisions for the three months ended March 31, 2008, are not considered material and primarily relate to changes in working interest on certain properties.

The following table sets forth a reconciliation of the Company’s ARO liability for the three months ended March 31 ($ in thousands):

	2009			2008
Beginning balance	$	1,686		$	1,495
Liabilities incurred		10			14
Liabilities settled		(6	)		(3	)
Accretion expense		29			28
Revisions of estimated liabilities		-			3
Ending balance	$	1,719		$	1,537

Financial Instruments

The Company has financial instruments for which the fair value of the financial instruments could be different than that recorded on a historical basis in the accompanying balance sheets.  The Company’s financial instruments consist of cash, short-term investments, accounts receivable, note receivable, accounts payable, accrued expenses, and debt.  The carrying amounts of the Company’s financial instruments approximate their fair values as of March 31, 2009, due to their short-term nature.

Concentration of Credit Risk

Financial instruments that subject the Company to concentrations of credit risk consist primarily of temporary cash investments, short-term investments, trade receivables, and note receivable.  The Company believes it has placed its demand deposits with high credit quality financial institutions.  As more fully described previously, the Company’s short-term investments are comprised of an investment in the Primary Fund which is a money market fund that decreased below $1 per share and is currently being liquidated.  While management recognizes there is increased credit risk associated with this investment, management expects to receive substantially all of the Company’s current holdings in the Primary Fund.  Concentrations of credit risk with respect to trade receivable are primarily focused on companies involved in the exploration and development of oil and natural gas properties.  The concentration is somewhat mitigated by the diversification of customers for which the Company provides services or partners under a joint venture arrangement.  As is general industry practice, the Company typically does not require customers or joint venture partners to provide collateral.  No significant losses from individual customers or joint venture partners were experienced during the three months ended March 31, 2009 or 2008.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

During 2008, the Company entered into a note receivable as more fully described in Note 10 “Related Party Transactions”.  The Company believes the concentration of credit risk associated with this note receivable is sufficiently mitigated based on the collateral secured as part of this agreement.

Stock-Based Compensation

On January 1, 2006, the Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R), to account for stock-based employee compensation.  Among other items, SFAS No. 123R eliminates the use of Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and the intrinsic value method of accounting and requires companies to recognize the cost of employee services received in exchange for stock-based awards based on the grant date fair value of those awards in their financial statements.  The Company elected to use the modified prospective method for adoption, which requires compensation expense to be recorded for all unvested stock options beginning in the first quarter of adoption.  For stock-based awards granted or modified subsequent to January 1, 2006, compensation expense, based on the fair value on the date of grant, will be recognized in the financial statements over the vesting period.  The Company utilizes the Black-Scholes option pricing model to measure the fair value of stock options.  To the extent compensation cost relates to employees directly involved in oil and natural gas exploration and development activities, such amounts are capitalized to oil and natural gas properties.  Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expenses.

The following stock-based compensation was recorded for the three months ended March 31 ($ in thousands):

	2009		2008
General and administrative expenses	$	276	$	673
Production and lease operating		1		-
Oil and natural gas properties		-		21
Total	$	277	$	694

The following table provides the unrecognized compensation expense related to unvested stock options as of March 31, 2009.  The expense is expected to be recognized over the following 3-year period ($ in thousands).

Period to be Recognized	2009		2010		2011		Total Unrecognized Compensation Expense
1st Quarter	$	-	$	99	$	39
2nd Quarter		193		78		26
3rd Quarter		106		40		-
4th Quarter		102		40		-
Total	$	401	$	257	$	65	$	723

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Comprehensive Income (Loss)

Comprehensive income (loss) is comprised of net income and other comprehensive income.  Other comprehensive income includes income resulting from derivative instruments designated as hedging transactions.   Since the Company’s derivative instruments were terminated during October 2008, there was no comprehensive income or loss for the three months ended March 31, 2009.  The details of comprehensive income (loss) for the three months ended March 31, was as follows ($ in thousands):

	2008
Net loss	$	(1,166	)
Other comprehensive loss:
Change in fair value of natural gas derivative instruments		(9,698	)
Change in fair value of interest rate derivative instruments		(1,555	)
Recognition of gains on derivative instruments		(260	)
Comprehensive loss attributable to Aurora	$	(12,679	)

Income (Loss) Per Share

Basic net income (loss) attributable to Aurora common share is computed based on the weighted average number of common shares outstanding during each period.  Diluted net income (loss) per common share is computed based on the weighted average number of common shares outstanding plus other dilutive securities, such as stock options, warrants, and redeemable convertible preferred stock.  As of March 31, 2009, and 2008, respectively, options and warrants to purchase 4,602,445 and 4,356,280 shares of common stock were not included in the computation of diluted net income (loss) per share as their effect would have been anti-dilutive.

NOTE 3. GOING CONCERN

The Company’s condensed consolidated financial statements for the three months ended March 31, 2009, have been prepared on a going concern basis which contemplates the realization of assets and the settlement of liabilities in the normal course of business.  With the loss of production and significant deficiencies in working capital along with the increase in interest rates and termination of the Company’s natural gas and interest rate derivatives during October 2008, the Company’s operations and existing cash balances are not sufficient to support interest requirements on existing debt balances for longer than one year.  The Company is currently in default under the senior secured credit facility and second lien term loan more fully described in Note 6 “Debt”.  The Company’s continued existence is dependent on  (1)  the lenders’ willingness to refrain from accelerating or demanding repayment on current debt obligations, (2) restructuring the Company’s current debt and interest payments, (3) securing alternative financing arrangements, and/or (4) asset divestitures.  Management continues discussions with existing lenders and is seeking alternative financing arrangements and opportunities for asset divestitures.  There is no assurance the lenders will not call the debt obligation or that the Company will be able to restructure or refinance its current debt or sell assets.

These uncertainties raise substantial doubt about the ability of the Company to continue as a going concern.  The accompanying condensed consolidated financial statements do not include any adjustments that might result from the outcome of these uncertainties should the Company be unable to continue as a going concern.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 4. RECENT ACCOUNTING PRONOUNCEMENTS

In April 2009, the FASB issued FASB Staff Position No. 107-1 and APB 28-1 which amends FASB Statement No. 107, “Disclosures about Fair Value of Financial Instruments,” and APB Opinion No. 28, “Interim Financial Reporting,” to require disclosures about the fair value of financial instruments for interim reporting periods as well as in annual financial statements.  FSP FAS 107-1 and APB 28-1 will be effective for interim reporting periods ending after June 15, 2009.  Management does not expect the adoption of FSP FAS 107-1 and APB 28-1 will have a material impact on the condensed consolidated financial statements.

In April 2009, the FASB issued FASB Staff Position No. 157-4, “Determining Whether a Market Is Not Active and a Transaction Is Not Distressed,” (“FSP FAS 157-4”).  FSP FAS 157-4 provides guidelines for making fair value measurements more consistent with the principles presented in FASB No. 157, “Fair Value Measurements.”  FSP FAS 157-4 also provides additional authoritative guidance in determining whether a market is active or inactive, and whether a transaction is distressed, and is applicable to all assets and liabilities (i.e. financial and nonfinancial).  FSP FAS 157-4 will be effective for interim and annual reporting periods ending after June 15, 2009.  Management does not expect the adoption of FSP FAS 157-4 will have a material impact on the condensed consolidated financial statements but may require certain additional disclosures.

In April 2009, the FASB issued FASB Staff Positions No. 115-2, No. FAS 124-2, and EITF 99-20-2, “Recognition and Presentation of Other-Than-Temporary Impairments,” (“FSP FAS 115-2, FAS 124-2, and EITF 99-20-2”).  FSP FAS 115-2, FAS 124-2, and EITF 99-20-2 amends the other-than-temporary impairment guidance for debt and equity securities and provides additional guidance to provide greater clarity about the credit and noncredit component of an other-than-temporary impairment event and to more effectively communicate when an other-than-temporary impairment event has occurred.  FSP FAS 115-2, FAS 124-2, and EITF 99-20-2 will be effective for interim and annual reporting periods ending after June 15, 2009.  Management does not expect the adoption of FSP FAS 115-2, FS 124-2, and EITF 99-20-2 will have a material impact on the condensed consolidated financial statements.

In November 2007, the FASB issued SFAS 160 and SFAS 141R.  SFAS 160 requires companies to present noncontrolling (minority) interests as equity (as opposed to a liability) and provides guidance on the accounting for transactions between an entity and noncontrolling interests.  In addition, SFAS 160 requires companies to report a consolidated net income (loss) measure that includes the amount attributable to such noncontrolling interests.  SFAS 141R amemded the principles and requirements for how an acquiror accounts for and discloses its business combinations. The Company adopted SFAS 160 and SFAS 141R effective January 1, 2009, and applies to noncontrolling interests prospectively from that date. However, the presentation and disclosure requirements of SFAS 160 were applied retrospectively for all periods presented.

NOTE 5. ACQUISITIONS AND DISPOSITIONS

2009 – North Knox

On February 19, 2009, the Company received proceeds of $17,800 in connection with the sale of a 45% working interest in the North Knox project.  The project is located in Knox County, Indiana, and covers approximately 791 gross (356 net) acres.

2009 – Deer Mountain Project

On January 8, 2009, the Company received proceeds of $8,718 in connection with the sale of all its interest in the Deer Mountain Project.  The project was located in Charlevoix County, Michigan, and covered approximately 1,062 gross (882 net) acres.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5. ACQUISITION AND DISPOSITIONS (Continued)

2009 – Other

During January 2009 through March 2009, the Company sold two meters and a generator and received proceeds of $12,785 in connection with the sales.

2008 – Goodwell and Smith Prospects

In January 2008, the Company received proceeds of $60,000 in connection with the sale of all its interest in the Goodwell and Smith prospect.  The prospect is located in Newaygo County, Michigan, and covers approximately 450 gross (270 net) acres.

NOTE 6. DEBT

Short-Term Bank Borrowings – Bach Services & Manufacturing Co., L.L.C. (“Bach”), a wholly-owned subsidiary

Effective December 8, 2008, Bach extended the expiration maturity date of its revolving line of credit to December 1, 2009.  As part of this extension agreement, Bach’s maximum borrowings were reduced to $250,000.  This revolving line of credit agreement is for general company purposes and is secured by all of Bach’s personal property owned or hereafter acquired and is non-recourse to the Company.  The interest rate under the revolving line of credit is Wall Street prime with a floor of 4.0% (effective rate of 4.0% at March 31, 2009) with interest payable monthly in arrears. Principal is payable at the expiration of the agreement.  No borrowings were outstanding on this line of credit as of March 31, 2009.  Interest expense for the three months ended March 31, 2009, and 2008, was $156 and $1,523, respectively.

Mortgage and Notes Payable - Bach

Bach’s outstanding debt at March 31, 2009, was as follows:

Description of Loan	Date of Loan	Maturity Date	Interest Rate	Principal Amount Outstanding
Mortgages payable:
Mortgages payable:
Land Mortgage	09/19/08	10/01/11	5.95%	$	68,566
Building Mortgage	12/18/06	06/15/10	6.00%		353,069
Total mortgages payable					421,635
Notes payable:
Vehicles	09/15/10-09/15/12	09/15/10-09/15/12	6.50% - 6.95%		78,102
Equipment	07/03/08-10/02/08	07/03/13–10/03/13	5.00%		97,014
Total notes payable				$	175,116

The obligations above are collateralized by the assets that are financed.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6. DEBT (continued)

Bach’s interest expense for the three months ended March 31, was as follows:

				Interest Expense
Description of Loan	Date of Loan	Maturity Date	Interest Rate	2009		2008
Mortgages payable:
Land Mortgage	09/19/08	10/01/11	5.95%	$	1,040	$	-
Building Mortgage	12/18/06	06/15/10	6.00%		5,321		5,525
Total mortgages payable					6,361		5,525
Notes payable:
Vehicles	10/06/06	Paid	7.50%		-		1,244
Vehicles	12/18/06	Paid	7.25%		-		854
Vehicles	04/23/07	Paid	7.00%		-		1,393
Vehicles	09/13/07-09/12/08	09/15/10-09/15/12	6.50%-6.95%		1,551		382
Equipment	09/13/07-09/12/08	07/03/12–10/03/13	5.00%		264		-
Total notes payable				$	1,815	$	3,873

Mortgage Payable

On October 4, 2005, the Company entered into a mortgage loan from Northwestern Bank in the amount of $2,925,000 for the purchase of an office condominium and associated interior improvements. The security for this mortgage is the office condominium real estate.  Effective February 14, 2008, the Company refinanced the existing loan by extending its maturity date through February 1, 2011.  The payment schedule is principal and interest in 36 monthly payments of $21,969 with one principal and interest payment of $2,364,419 on February 1, 2011.  The interest rate is 5.95% per year. As of March 31, 2009, the principal amount outstanding was $2.6 million.  Interest expense for the three months ended March 31, 2009, and 2008, was $38,621 and $42,407, respectively.

Senior Secured Credit Facility

On January 31, 2006, the Company entered into a $100 million senior secured credit facility with BNP and other lenders for drilling, development, and acquisitions, as well as other general corporate purposes.  In connection with the second term lien loan discussed below, the Company also agreed to the amendment and restatement of the senior secured credit facility, pursuant to which the borrowing base under the senior secured credit facility was increased from the then current authorized borrowing base of $50 million to $70 million effective August 20, 2007.  The amount of the borrowing base was based primarily upon the estimated value of the Company’s oil and gas reserves.  The borrowing base amount is redetermined by the lenders semi-annually on or about April 1 and October 1 of each year or at other times required by the lenders or at the Company’s request.  The security for this facility is substantially all of the Company’s oil and natural gas properties; guarantees from all material subsidiaries; and a pledge of 100% of the stock or member interest of all material subsidiaries.

The senior secured credit facility provides for borrowings tied to BNP’s prime rate (or, if higher, the federal funds effective rate plus 0.5%) or LIBOR-based rate plus 1.25% to 3.0% depending on the borrowing base utilization, as selected by the Company.  The borrowing base utilization is the percentage of the borrowing base that is drawn under the senior secured credit facility from time to time.  As the borrowing base utilization increases, the LIBOR-based interest rates increase under this facility.  As of March 31, 2009, interest on the borrowings had a weighted average interest rate of 6.37%.  For the three months ended March 31, 2009 and 2008, interest and fees incurred for the senior secured credit facility were $1.1 million and $0.9 million, respectively.  All outstanding principal and accrued and unpaid interest under the senior secured facility is due and payable on January 31, 2010.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6. DEBT (continued)

The maturity date of the outstanding loan may be accelerated by the lenders upon occurrence of an event of default under the senior secured credit facility.

On October 3, 2008, the Company received a notice of default from BNP with respect to the senior secured credit facility (the “Notice of Default”).  The Notice of Default informed the Company that the interest rate under the senior secured credit facility shall bear interest at the default rate of prime plus 3.0% thereby increasing the Company’s current interest rate under the senior secured credit facility by 2% to approximately 8.0% (6.25% at March 31, 2009).

On February 12, 2009, the Company and certain subsidiaries, as guarantors, entered into a forbearance agreement to the senior secured credit facility (the “Second Forbearance Agreement”) with BNP and the syndication.  In accordance with the Second Forbearance Agreement, during the period from December 31, 2008 until April 30, 2009 (the “Second Forbearance Period”), BNP agreed to forbear and refrain from (i) accelerating any loans outstanding and (ii) taking any other enforcement action under the senior secured credit facility at law or otherwise as a result of designated defaults or potential defaults, provided the Company complied with the forbearance covenants (collectively, the “Second Forbearance Covenants”).

A summary of the Second Forbearance Covenants were as follows: (i) the Company shall retain and employ a financial advisor, (ii) the Company shall deliver to BNP an initial detailed budget on or before February 20, 2009, and provide subsequent monthly updates, (iii) the Company shall deliver to BNP prior week aggregated cash balances on or before the last business day of the current week, (iv) no later than February 23, 2009, the Company will execute (or cause to be executed) additional mortgages and no later than February 18, 2009, the Company will execute (or cause to be executed) other security instruments such that, after giving effect to such additional mortgages and other security instruments, the syndication will have liens on 100% of all oil and gas properties, promissory notes, all significant overriding royalties, and all significant farmout agreements prior to such date, (v) the Company must obtain prior written approval of BNP to farmout any assets or sell any assets for more than $200,000; (vi) the Company shall provide BNP notice of any unwritten or written expressions of interest with respect to the purchase of assets of the Company or any of its subsidiaries for an amount in excess of $2.0 million, (vii) the Company and its financial advisor shall participate in weekly conference calls with BNP and the syndication during which a financial officer of the Company must provide updates on restructuring, sale prospects, and cost reduction efforts, (viii) the Company must deliver to BNP copies of any detailed audit reports, management letters, or recommendations submitted to the board of directors, (ix) no later than February 28, 2009, the Company must deliver a restructuring plan to resolve the borrowing base deficiency, (x) the Company must maintain a liquidity position of at least $4.0 million during Second Forbearance Period, and (xi) no later than February 23, 2009, the Company must obtain the consent of the second lien term loan syndication for the Company to defer until no earlier than the termination of the Second Forbearance Period, payment of the scheduled interest payment currently payable to the second lien term loan syndication on February 24, 2009.

On February 18, 2009, the Company executed the mortgages, security agreement and pledge agreements necessary to provide the senior secured credit facility lenders a first secured lien on substantially all of the Company’s oil and gas properties not previously pledged to them. The Company has also complied with the other Second Forbearance Covenants, except that the Company has not obtained the consent of the second lien lenders to defer payment of the $1.6 million interest payment scheduled to be paid by the Company on February 24, 2009.  The Company received correspondence from BNP dated February 27, 2009 indicating that the first lien lenders agree not to declare a forbearance termination event as a result of the Company’s failure to obtain the consent of the second lien lenders to defer payment of $1.6 million interest scheduled to be paid on February 24, 2009 (covering the period of November 25, 2008 to February 24, 2009), as long as the Company does not actually make the interest payment during the Second Forbearance Period. As more fully described below, Laminar Direct Capital, LLC (“Laminar”) and the second lien term loan syndication cannot take any enforcement or similar actions against the Company’s property for at least 180 days beginning November 24, 2008.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6. DEBT (continued)

The Company continues to engage in discussions with BNP and the syndication to restructure the Company’s debt.  The Company recognizes the senior secured credit facility is due and payable upon notification from BNP, and therefore the entire outstanding debt has been classified as a current liability on the accompanying March 31, 2009 and December 31, 2008 balance sheets.  In addition to discussions with BNP and the syndication, management is also seeking alternative financing arrangements and opportunities for asset divestitures.  There is no assurance that BNP and the syndication will not accelerate or demand repayment of the senior secured credit facility or that management will be successful in restructuring the Company’s debt, finding alternative financing arrangements, or selling Company assets.

The Company has incurred deferred financing fees of $0.7 million with regard to the senior secured credit facility.  The deferred financing fees are being amortized on a straight-line basis over the remaining terms of the debt obligation.  Amortization expense for the senior secured credit facility is estimated to be $0.2 million per year through 2009. Amortization expense was $0.1 million for each of the three months ended March 31, 2009, and 2008. In addition, the Company incurred $0.4 million in legal and consulting expenses related to restructuring efforts applicable to the senior secured credit facility for the three months ended March 31, 2009, which have been recorded as general and administrative expenses on the accompanying condensed consolidated financial statements.  The Company also incurs various annual fees associated with unused commitment and agency fees which are recorded to interest expense.

Second Lien Term Loan

On August, 20, 2007, the Company entered into a second lien term loan agreement with BNP as the arranger and administrative agent, and several other lenders forming a syndication (the “Term Loan”).  During August 2008, the Company was notified that Laminar succeeded BNP as the arranger and administrative agent for the second lien term loan.  The initial term loan was $50 million for a 5-year term (expires 8/20/12) which may increase up to $70 million under certain conditions over the life of the loan facility.  The proceeds of the second lien term loan were used to repay the outstanding balance under the Company’s mezzanine financing with Trust Company of the West and for general corporate purposes.  Interest under the second lien term loan is payable at rates based on the London Interbank Offered Rate (“LIBOR”) plus 950 basis points with a step-down of 25 basis points once the Company’s ratio of total indebtedness to earnings before interest, taxes, depreciation, depletion, amortization, and other non-cash charges is lower than or equal to a ratio of 4.0 to 1.0 on a trailing four quarters basis.

On October 6, 2008, the Company received a notice of default from Laminar with respect to the second lien term Loan (“the Term Loan Notice of Default”).  The Term Loan Notice of Default informed the Company that the interest rate under the second lien term loan shall bear interest at the default rate thereby increasing the Company’s current interest rate under the Term Loan by 2% to approximately 15.5%.  Laminar and the syndication cannot take any enforcement or similar actions against the Company or its property for at least 180 days beginning November 24, 2008, pursuant to the terms of the Intercreditor Agreement, dated August 20, 2007, between the second lien term loan syndication and the senior secured credit facility syndication.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6. DEBT (continued)

The Company continues to engage in discussions with Laminar and the syndication to restructure the Company’s debt.  The Company recognizes that the term loan is due and payable upon notification from Laminar after the expiration of the 180 days beginning November 24, 2008, and therefore the entire outstanding balance has been classified as a current liability on the accompanying March 31, 2009 and December 31, 2008 balance sheets.  In addition to discussions with Laminar and the syndication, management is also seeking alternative financing arrangements and opportunities for asset divestitures.  There is no assurance that management will be successful in restructuring the Company’s debt, finding alternative financing arrangements, or selling Company assets in an amount sufficient to remedy the Company’s loan defaults.

For the three months ended March 31, 2009 and 2008, interest and fees incurred for the second lien term loan was $2.0 million and $1.4 million, respectively.  The entire $2.0 million of interest incurred for the three months ended March 31, 2009 was treated as a payment-in-kind and recorded as an additional liability under the second lien term loan.  The Company has also incurred deferred financing fees of $1.3 million with regard to the second lien term loan.  The deferred financing fees are being amortized on a straight-line basis over the remaining terms of the second lien term loan obligation.  Amortization expense for the second lien term loan is estimated to be $0.3 million per year through 2011.  Amortization expense was $0.1 million for each of the three months ended March 31, 2009 and 2008.  The additional financing fees were recorded as an increase to general and administrative expense.  In addition, the Company incurred $0.1 million in legal and consulting expenses related to restructuring efforts applicable to the second lien term loan for the three months ended March 31, 2009, which have been recorded as general and administrative expenses on the accompanying condensed consolidated financial statements.  The Company also incurs annual agency fees which are recorded to interest expense.

NOTE 7. SHAREHOLDERS’ (DEFICIT) EQUITY

Common Stock

In January 2008, 30,000 common stock options were exercised by a Company employee under the existing stock option plans at an exercise price of $0.375 per share.  The Company received $11,250 in connection with this exercise.

In January 2008, 500,000 common stock options were exercised by an outside party at an exercise price of $0.625 per share.  The Company received $0.3 million in connection with this exercise.

In March 2008, 133,332 common stock options were exercised by two Company directors under the existing stock option plans at an exercise price of $0.375 per share.  The Company received $50,000 in connection with these exercises.

NOTE 8. COMMON STOCK OPTIONS

As of March 31, 2009, the Company maintains four stock option plans that are fully described in Note 11 “Common Stock Options” in the Company’s Annual Report on Form 10-K for the year-ended December 31, 2008.  These stock option plans provide for the award of options or restricted shares for compensatory purposes.  The purpose of these plans is to promote the interests of the Company by aligning the interests of employees (including directors and officers who are employees), consultants, and non-employee directors of the Company and to provide incentives for such persons to exert maximum efforts for the success of the Company and its subsidiaries.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8. COMMON STOCK OPTIONS (continued)

The following table sets forth activity for the stock option plans referenced above for the three months ended March 31, 2009 (shares shown in thousands):

	Number of Shares Underlying Options
Options outstanding at beginning of period		4,177
Options granted		-
Options exercised		-
Options forfeited and other adjustments		(6	)
Options outstanding at end of period		4,171

No options were granted during the three months ended March 31, 2009; therefore, weighted average assumptions used in the Black-Scholes option-pricing model are not presented.

All Stock Options

In addition, the Company issued options and warrants totaling 1,430,280 on an individualized basis that was considered outside the awards issued under its existing stock option plans.  Of the 1,430,280 options and warrants issued, 431,000 shares remain outstanding as of March 31, 2009.  Activity with respect to all stock options is presented below for the three months ended March 31, 2009 (shares and intrinsic value shown in thousands):

	Number of Shares Underlying Options			Weighted Average Exercise Price		Aggregate Intrinsic Value(a)
Options outstanding at beginning of period		4,608		$	1.99
Options granted		-			-
Options exercised		-			-
Forfeitures and other adjustments		(6	)	$	4.70
Options outstanding at end of period		4,602		$	1.98	$	-
Exercisable at end of period		2,744		$	2.47	$	-
Weighted average fair value of options granted during period		-

(a) The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option.  Since the exercise price of all stock options is greater than the current market value, no intrinsic value exists for options outstanding at March 31, 2009.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8. COMMON STOCK OPTIONS (continued)

The weighted average remaining life by exercise price as of March 31, 2009, is summarized below (shares shown in thousands):

Range of Exercise Prices	Outstanding Shares	Weighted Average Life	Exercisable Shares	Weighted Average Life
$0.38 - $0.63	733	2.0	733	2.0
$0.75	1,750	9.2	-	-
$1.75 - $2.55	385	3.6	374	3.3
$2.90 - $3.62	1,308	1.8	1,292	1.8
$4.45 - $4.70	426	4.6	344	4.3
$0.38 - $4.70	4,602	5.0	2,743	2.2

NOTE 9. COMMITMENTS AND CONTINGENCIES

Environmental Risk

Due to the nature of the oil and natural gas business, the Company is exposed to possible environmental risks. The Company manages its exposure to environmental liabilities for both properties it owns as well as properties to be acquired.  Management believes that the Company is in substantial compliance with all currently applicable environmental laws and regulations.

In 2007, the State of Michigan, Department of Environmental Quality (“DEQ”) instituted a water sampling and monitoring requirement for wells north of a line of demarcation that includes most of the Company’s Antrim projects.  The drilling permits for new wells in this area require produced water monitoring and reporting of gas and water volume and water quality.  If the water produced by a well has levels of chloride or total dissolved solids concentration below specified levels, the Company may be required to shut-in the well.  If such wells cannot be remediated so that fresh water is no longer produced, the Company may be required to plug such wells.

In September 2007, the DEQ collected and analyzed water samples from certain wells in the Arrowhead, Blue Chip, and Gaylord Fishing Club projects.  On January 31, 2008, management met with the DEQ to review the analyses.  Since the water composition in most of the wells fell within the range deemed by the DEQ to be fresh water, the DEQ requested that the Company plug six wells, plug or remediate an additional 15 wells, and collect water samples from the remaining wells that had not been previously sampled.  Management agreed to plug five of the six wells requested and collected a new round of water samples from each requested well for additional analysis.

In September 2008, the Company received a notice of violation from the DEQ requesting a proposal from management to plug 25 wells in the Arrowhead and Blue Chip projects.  Five of the wells listed on this notice had been agreed to during the January 31, 2008 meeting and were plugged during 2008.  In December 2008, management met again with the DEQ to discuss the remaining wells.  Management agreed to shut-in three additional wells bringing total shut-in wells to 13, and continues to provide water samples for the remaining wells for further analysis.  Management is expected to meet again with the DEQ during 2009 to discuss the results.  There is no assurance that the Company will not be required to plug the remaining wells in the Arrowhead project.  If the Company is required to plug the remaining wells, operations are not expected to be materially impacted as most of these wells are uneconomic and plugging costs are estimated to be $12,000 per well.

As more fully described in Note 11 “Subsequent Events” and unrelated to the situation as described previously, the Company received a letter from the DEQ dated April 29, 2009 denying the Company’s request to extend its temporary abandonment status on 19 wells located in the Antrim play known as the Tomahawk and Black Bear Central projects.

21

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9. COMMITMENTS AND CONTINGENCIES (continued)

Letters of Credit

For each salt water disposal well drilled in the State of Michigan, the Company is required to issue a letter of credit to the Michigan Supervisor of Wells.  The Supervisor of Wells may draw on the letter of credit if the Company fails to comply with the regulatory requirements relating to the locating, drilling, completing, producing, reworking, plugging, filling of pits, and clean up of the well site.  The letter of credit or a substitute financial instrument is required to be in place until the salt water disposal well is plugged and abandoned.  For drilling natural gas wells, the Company is required to issue a blanket letter of credit to the Michigan Supervisor of Wells.  This blanket letter of credit allows the Company to drill an unlimited number of natural gas wells.  The majority of existing letters of credit have been issued by Northwestern Bank of Traverse City, Michigan, (”Northwestern Bank”) and are secured only by a Reimbursement and Indemnification Commitment issued by the Company, together with a right of setoff against all of the Company’s deposit accounts with Northwestern Bank.  At March 31, 2009, letters of credit in the amount of $0.8 million were outstanding with the majority issued to the Michigan Supervisor of Wells.

As more fully described in Note 11 “Subsequent Events,” on April 15, 2009, the Company granted as collateral its short-term investments to secure the outstanding letters of credit.

General Legal Matters

The Company is currently involved in various disputes incidental to its business operations which includes claims from royalty owners regarding disputes of royalty payments. Although the outcome of these lawsuits and disputes cannot be predicted management, after consultation with legal counsel, is of the opinion that the final resolution of all currently pending or threatened litigation is not likely to have a material adverse effect on our consolidated financial position, results of operations, or cash flows.

NOTE 10. RELATED PARTY TRANSACTIONS

Presidium Energy, LC (“Presidium”)

AOK Energy LLC Purchase and Sale Agreement

In March 2006, the Company entered into a joint venture agreement with certain unrelated parties.  The joint venture covered the acquisition and development of oil and gas leases in various counties located in Oklahoma.  The joint venture project was known as the “Oak Tree Project.”  The Company participated in the joint venture through a wholly owned subsidiary, AOK Energy, LLC (“AOK”).  Effective March 28, 2008, the Company entered into an Agreement for the Purchase and Sale of Limited Liability Company Memberships with Presidium, which is wholly owned and operated by John V. Miller, who served as the Company’s Vice President from November 1, 2005, until he resigned on February 29, 2008.  Under the terms of the agreement, the Company would sell to Presidium all of the outstanding member interests in AOK for a purchase price that included the payment by Presidium of certain liabilities that the operator alleged were owed by the Company to other participants in the joint venture, a cash payment to the Company in the amount of $10,500,000, and an assignment to the Company of a 3% overriding royalty in certain leases in the Oak Tree Project.

Effective July 21, 2008, the Company amended the Purchase and Sale of Limited Liability Company Memberships with Presidium (the “First Amendment”) to extend Presidium’s exclusive right to purchase all of the outstanding member interests in AOK until September 15, 2008.  In exchange for the extension, Presidium made a $2.0 million non-refundable payment to the Company.

22

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10. RELATED PARTY TRANSACTIONS (continued)

Effective on September 12, 2008, the Company amended the Purchase and Sale of Limited Liability Company Memberships with Presidium (the “Second Amendment”) increasing the purchase price to $15,000,000.  The Second Amendment also required Presidium to pay another $1,000,000 in cash and execute a promissory note in the amount of $12,000,000 (“Promissory Note”).  In order to induce the Company to enter into the Second Amendment, Mr. Miller granted the Company an option to buy up to one million membership units in Presidium for the sum of $0.50 per unit during the period from six months to five years after closing.  The sale of the membership interest closed effective September 15, 2008.

Under the terms of the Promissory Note, Presidium is required to make monthly interest only payments calculated at the lesser of the maximum rate allowed by law or 9.0%.  As security for repayment of the Promissory Note, Presidium granted a first priority security interest in all of AOK interests and delivered mortgages on all oil and gas leases Presidium holds or will acquire in the Oak Tree Project.  In the event Presidium plans to drill a well in the Oak Tree Project, a principal payment on the Promissory Note equal to the amount of $400 per net acre of leases to be included in the drilling unit must be submitted to the Company in order for the Company to subordinate any mortgages held on leases that fall within the drilling unit.  Presidium shall be entitled to have outstanding mortgage subordinations for no more than five undrilled well sites at any one time.  The entire outstanding principal balance along with all accrued interest is due September 10, 2010.  For the three months ended March 31, 2009, the Company recorded $0.3 million of interest income related to the Promissory Note and received a principal payment in the amount of $0.2 million.

Simple Financial Solutions, Inc.

Consulting Agreements

Effective January 22, 2008, Barbara E. Lawson was named Chief Financial Officer of the Company.  Simple Financial Solutions, Inc., which Ms. Lawson holds an officer position and is owned and operated by Ms. Lawson’s spouse, provides consulting services on a continuous basis to the Company including Bach Services and Manufacturing Co., LLC, a Company subsidiary.  For the three months ended March 31, 2009 and 2008, Simple Financial Solutions, Inc. billed the Company $21,838 and $10,865, respectively, for services rendered.

Effective May 1, 2008, the Company entered into a month-to-month agreement with Simple Financial Solutions, Inc. to provide professional services for a subsidiary of the Company, Hudson Pipeline & Processing Co., LLC (“HPPC”).  On a monthly basis, Simple Financial Solutions, Inc. will be paid 2% of the gross revenues of HPPC and 3.5% of the net income to HPPC before compensation.  Certain revenue resulting from gas transportation will be excluded from the calculations.  For the three months ended March 31, 2009, the Company paid $26,109 for services received from Simple Financial Solutions, Inc. pursuant to this HPPC agreement. Effective May 1, 2009, this agreement has been terminated with the disposition of membership interest more fully described below.

Disposition of Membership Interest

Effective June 28, 2008, Lawson & Kidd, LLC purchased a 2.5% membership interest in HPPC for $0.1 million.  Lawson & Kidd, LLC is solely owned by Barbara E. Lawson who is the Company’s Chief Financial Officer and Ms. Lawson’s spouse.  The Company repurchased the 2.5% membership interest in HPPC from Lawson & Kidd, LLC during March 2009 for $0.1 million in cash and the assumption of a capital call of $0.1 million covering Aurora asset transfer. This was accounted for in accordance with SFAS 160.

23

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10. RELATED PARTY TRANSACTIONS (continued)

Other

Consulting Agreements

Effective August 15, 2008, the Company entered into a consulting agreement with Richard M. Deneau to provide advice and services at an hourly rate of $125 (not to exceed $1,000 per day) in connection with management’s negotiations with the Company’s existing bankers and the creation and maintenance of new banking relationships.  Mr. Deneau is the brother of the Company’s Chief Executive Officer and has served as a director of the Company since 2005.  For the three months ended March 31, 2009, the Company paid $33,443 for consulting services received from Mr. Deneau.  Of the $33,443, $3,130 was reimbursed for travel related expenses.

Working Interest in Certain Projects

Effective May 30, 2007, the Board of Directors named John C. Hunter as Vice President of Exploration and Production.  He has worked for AOG since 2005 as Senior Petroleum Engineer.  Prior to that, Mr. Hunter was instrumental in certain projects associated with the Company’s New Albany shale play.  Over a series of agreements with the Company, Mr. Hunter (controlling member of Venator Energy, LLC) has acquired 1.25% working interest in certain leases.  The leases cover approximately 132,600 acres (1,658) net in certain counties located in Indiana.  The 1.25% carried working interest shall be effective until development costs exceed $30 million.  Thereafter, participation may continue as a standard 1.25% working interest owner.  The Company is entitled to recovery of 100% of development costs (plus interest at a rate of 6.75% per annum compounded annually) from 85% of the net operating revenue generated from oil and gas production developed directly or indirectly in the area of mutual interest covered by the agreement.  As of March 31, 2009, there is no production associated with this working interest, and development costs were approximately $9.0 million.  Of the Company’s $0.4 million obligation to carry Mr. Hunter, $0.1 million was incurred on behalf of Mr. Hunter as of March 31, 2009.

On October 29, 2008, the Company entered into a farmout arrangement with Atlas Energy Resources, LLC to farm out 64.43% interest in undeveloped acreage in the Wabash project which includes the leases covered by the above arrangement with Mr. Hunter.  Mr. Hunter has elected to participate in the farmout arrangement and therefore Mr. Hunter’s working interest shall be carried by the Company until development costs exceed $30 million.

Effective July 1, 2004, Aurora Energy, Ltd., (“AEL”), entered into a Fee Sharing Agreement with Mr. Hunter as compensation for bringing Bluegrass Energy Enhancement Fund, LLC (“Bluegrass”) and AEL together for the development of the 1500 Antrim and Red Run projects in Michigan.  At this time, AEL (which has since merged into the Company) and Bluegrass have discontinued leasing activities in both projects.  In the 1500 Antrim project there are 23,989.41 acres. Mr. Hunter’s carried working interest share of 0.8333% is approximately 199.95 net acres.  The carried working interest relates to the first 55 wells that are drilled in the area of mutual interest.  Thereafter, Mr. Hunter would pay his proportionate share of working interest expenses.  Currently, there are no producing wells.  The Red Run project contains 12,893.64 acres.  Mr. Hunter’s carried working interest share of 0.8333% is approximately 107.44 net acres.  The carried working interest relates to the first 55 wells that are drilled in the area of mutual interest.  Thereafter, Mr. Hunter would pay his proportionate share of working interest expenses.  Currently, there are three wells permitted for the Red Run project and one well was drilled and temporarily abandoned.  As of March 31, 2009, there is no production associated with this working interest, and development costs were approximately $4.5 million.  The Company has incurred $0.1 million on behalf of Mr. Hunter.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 11. SUBSEQUENT EVENTS

NYSE Amex LLC Delisting

On April 9, 2009, the Company was notified by the NYSE Amex LLC (“the Exchange”) that it had fallen below the Exchange continued listing standard related to the Company’s financial resources and financial condition.  In the opinion of the Exchange, the Company is not in compliance with Section 1003(a)(iv) of the Exchange Guide in that the Company’s financial condition has become so impaired that it appears questionable as to whether the Company will be able to continue operations and/or meet its obligations as they mature.

As required under the listing standards, the Company had the option to submit a plan by May 11, 2009 to the Exchange that summarizes the action it can take to achieve compliance with the continued listing standard.  With great deliberation and in light of the costs the Company would incur to maintain continued listing with the Exchange, the Board of Directors has concluded that the Company should voluntarily delist from the Exchange.  The Company is expected to transfer its listing to the OTC on or about May 11, 2009.

Security Agreement

On April 15, 2009, the Company entered into a security agreement with Northwestern Bank granting the Company’s short-term investments as collateral to secure the outstanding letters of credit issued by the Bank.  The agreement will remain in effect until there is no longer any indebtedness owed to the Bank, all other obligations secured by this agreement have been fulfilled, and the Company has requested a release of this agreement from the Bank in writing.

DEQ Notification

On April 29, 2009, the Company received a letter from the DEQ denying the Company’s request to extend its temporary abandonment status on 19 wells located in the Tomahawk and Black Bear Central projects.  The DEQ is requesting the Company submit a plan to plug the 19 wells.  Management expects to contest this request and is currently discussing an appropriate form of response.  There is no assurance that the Company will not be required to plug the 19 wells.  If the Company is required to plug the 19 wells operations are not expected to be materially impacted as the wells are currently in a temporary abandonment status.  However, plugging costs are estimated to be $0.3 million.

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

You should read the following discussion in conjunction with management’s discussion and analysis contained in our 2008 Annual Report on Form 10-K, as well as the condensed consolidated financial statements and notes hereto included in this quarterly report on Form 10-Q.  The following discussion contains forward-looking statements that involve risks, uncertainties, and assumptions, such as statements of our plans, objectives, expectations, and intentions.  Our actual results may differ materially from those discussed in these forward-looking statements because of the risks and uncertainties inherent in future events.

Overview

We are an independent energy company focused on the exploration, exploitation, and development of unconventional natural gas reserves.  Our unconventional natural gas projects target shale plays where large acreage blocks can be easily evaluated with a series of low cost test wells. Shale plays tend to be characterized by high drilling success and relatively low drilling costs when compared to conventional exploration and development plays.  Our project areas are focused in the Antrim shale of Michigan and New Albany shale of Southern Indiana and Western Kentucky.

In 1969, we commenced operations to explore and mine natural resources under the name Royal Resources, Inc. In July 2001, we reorganized our business to pursue oil and gas exploration and development opportunities and changed our name to Cadence Resources Corporation (“Cadence”).  We acquired Aurora Energy, Ltd. (“Aurora”) on October 31, 2005, through the merger of our wholly-owned subsidiary with and into Aurora.  The acquisition of Aurora was accounted for as a reverse merger, with Aurora being the acquiring party for accounting purposes.  The Aurora executive management team also assumed management control at the time the merger closed, and we moved our corporate offices to Traverse City, Michigan.  Effective May 11, 2006, Cadence amended its articles of incorporation to change the parent company name to Aurora Oil & Gas Corporation (“AOG”).

Highlights

The following table sets forth as of March 31, 2009, the gross and net acres of both developed and undeveloped oil and gas leases which we hold.

	Developed(a)		Undeveloped(b)		Total(c)
Play/Trend	Gross	Net	Gross	Net	Gross	Net
Michigan Antrim	69,634	39,280	216,360	91,214	285,994	130,494
New Albany	20,460	7,090	761,927	446,468	782,387	453,558
Other	1,730	1,022	88,604	66,449	90,334	67,471
Total	91,824	47,392	1,066,891	604,131	1,158,715	651,523

(a) Developed refers to the number of acres which are allocated or assignable to producing wells or wells capable of production. Developed acreage includes acreage having wells shut-in awaiting the addition of infrastructure.

(b) Undeveloped refers to lease acreage on which wells have not been developed or completed to a point that would permit the production of commercial quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

(c) While we are focused on developing the shale, our acreage covers a variety of different formations in addition to the shale that have the possibility of being developed and marketed.

With regard to our drilling activities, we drilled or participated in 6 (1 net) wells for the three months ended March 31, 2009, with a 100% success rate.  As of March 31, 2009, we had 646 (287 net) producing wells, 21 (9 net) wells awaiting hook-up, 20 (7 net) wells undergoing resource assessment, and 53 (36 net) wells temporarily abandoned.  We operate 216 (206 net) wells, thus, operating 29% of our gross wells and 61% of our net wells.  Of the 206 net wells we operate, 170 net wells are producing in the Antrim; 4 net wells are undergoing resource assessment in the Antrim, 6 net wells are awaiting hook-up in the New Albany; and 26 net wells are temporarily abandoned.

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Oil and natural gas production for the three months ended March 31, 2009, was 616,780 mcfe, a 25% decrease from the 824,489 mcfe produced in the three months ended March 31, 2008.  For the three months ended March 31, 2009, production continues to be hampered by wells undergoing resource assessment and inefficient dewatering in the Antrim resulting from mechanical issues with downhole pumps, rat-hole limitations, and surface problems with pump-off controllers and booster compressors.

During May 2008, we implemented a well enhancement program on our operated Antrim shale properties to address our decline in production.  The objective of the well enhancement program was to perform downhole workovers on approximately 90 wells primarily located in the Hudson 34 and Hudson SW projects.  Wecompleted well enhancement activities on the majority of the 90 wells and experienced an approximate one to two days stoppage in production per well to complete the well enhancement activities.We also shut down the downhole pumps on various wells that were producing large volumes of water with insignificant volumes of gas.  Since we discontinued the pumping operations on these wells, we have observed a detrimental impact on the gas production levels in the remaining producing wells. We believe that maximizing water production from all operated Antrim shale wells, regardless of their individual economic impact, is necessary to maximize gas production from the projects as a whole. Therefore, we initiated a renewed well enhancement program in February 2009 that emphasizes measures to increase water production. As part of the process, we are planning to install water meters at each well location to track water production. The program was initially intended to be implemented in three phases throughout 2009 with the first phase incorporating the Hudson 19, Hudson 34, Hudson SW and Hudson West Units.  However, due to lack of capital available and significant declines in gas prices, we chose to delay the first phase and move to a pilot program from the second phase which incorporated the Corwith and Hudson 13 projects.  Additional time will be required before measurable progress in production can be recognized.

Our average daily production for the three months ended March 31, 2009, was 6,853 mcfe per day compared to 9,060 mcfe per day for the three months ended March 31, 2008.  Average daily production for operated properties was 4,136 mcfe and 5,901 mcfe for the three months ended March 31, 2009 and 2008, respectively.  Average daily production for non-operated properties was 2,717 mcfe and 3,159 mcfe for the three months ended March 31, 2009 and 2008, respectively.

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Operating Statistics

The following table sets forth certain key operating statistics for the three months ended March 31, 2009 (the “Current Quarter”), and the three months ended March 31, 2008 (the “Prior Year Quarter”):

						Increase (Decrease)
	2009		2008			Amount			Percentage
Net wells drilled
Antrim shale		-		1			(1	)	(100)%
New Albany shale (“NAS”)		-		-			-			-
Other		1		1			-		0%
Dry		-		-			-			-
Total		1		2			(1	)	(50)%
Total net wells
Antrim—producing		267		283			(16	)	(6)%
Antrim—awaiting hookup		2		2			-			-
NAS—producing		1		7			(6	)	(86)%
NAS—awaiting hookup		6		-			6			N/A
Other—producing		18		14			4		29%
Other—awaiting hookup		1		2			(1	)	(50)%
Total		295		308			(13	)	(4)%
Production
Natural gas (mcf)		582,730		779,483			(196,753	)	(25)%
Crude oil (bbls)		5,675		7,501			(1,826	)	(24)%
Natural gas equivalent (mcfe)		616,780		824,489			(207,709	)	(25)%
Average daily production
Natural gas (mcf)		6,475		8,566			(2,091	)	(24)%
Crude oil (bbls)		63		82			(19	)	(23)%
Natural gas equivalent (mcfe)		6,853		9,060			(2,207	)	(24)%
Average sales price (excluding all gains (losses) on derivatives)
Natural gas ($ per mcf)	$	5.08	$	8.29		$	(3.21	)	(39)%
Crude oil ($ per bbls)	$	36.48	$	83.19		$	(46.71	)	(56)%
Natural gas equivalent ($ per mcfe)	$	5.13	$	8.59		$	(3.46	)	(40)%
Average sales price (including all gains (losses) from derivatives)
Natural gas ($ per mcf)	$	5.08	$	7.47		$	(2.39	)	(32)%
Crude oil ($ per bbls)	$	36.48	$	83.19		$	(46.71	)	(56)%
Natural gas equivalent ($ per mcfe)	$	5.13	$	7.81		$	(2.68	)	(34)%
Production revenue ($ in thousands)
Natural gas	$	2,959	$	6,455		$	(3,496	)	(54)%
Natural gas derivatives—realized gains		-		333			(333	)	(100)%
Natural gas derivatives—unrealized losses		-		(969	)		969		100%
Crude oil		207		624			(417	)	(67)%
Total	$	3,166	$	6,443		$	(3,277	)	(51)%

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						Increase (Decrease)
	2009		2008			Amount			Percentage
Average expenses ($ per mcfe)
Production taxes	$	0.18	$	0.42		$	(0.24	)	(57)%
Post-production expenses	$	1.25	$	0.81		$	0.44		54%
Lease operating expenses	$	2.32	$	2.58		$	(0.26	)	(10)%
General and administrative expense	$	4.52	$	2.43		$	2.09		86%
General and administrative expense excluding stock-based compensation	$	4.08	$	1.61		$	2.47		153%
Oil and natural gas depletion and amortization expenses	$	0.97	$	1.19		$	(0.22	)	(18)%
Other assets depreciation and amortization	$	0.56	$	0.44		$	0.12		27%
Interest expenses	$	3.44	$	1.78		$	1.66		93%
Taxes	$	0.06	$	(0.09	)	$	0.15		167%
Number of employees including Bach		38		66			(28	)	(42)%

Results of Operations

Three Months Ended March 31, 2009, compared with Three Months Ended March 31, 2008

General.  For the Current Quarter, we had a net loss of $58.2 million, or $(0.56) per diluted common share, on total revenues of $4.2 million.  This compares to a net loss of $1.2 million, or $(0.01) per diluted common share, on total revenue of $6.7 million for the Prior Year Quarter.  The $57.0 million increase in net loss is primarily attributable to a decrease in oil and gas sales in the amount of $3.2 million, a ceiling test write-down of oil and gas properties in the amount of $53.6 million, increase in general and administrative expense in the amount of $0.8 million, and increase in interest expense in the amount of $0.6 million.  The $4.6 million increase in net loss was offset by an increase in interest and other revenue in the amount of $0.3 million, decrease in production and lease operating expenses in the amount of $0.5 million, and a decrease in oil and natural gas depletion and amortization in the amount of $0.4 million.

Oil and Natural Gas Sales.  During the Current Quarter, oil and natural gas sales were $3.2 million compared to $6.4 million in the Prior Year Quarter.  This decrease was primarily due to the significant decline in production and natural gas prices.  During October 2008, our natural gas contracts were terminated and therefore production during the Current Quarter was sold at prevailing market rates which have significantly declined when compared to the Prior Year Quarter.  In addition, during the Prior Year Quarter, our production was hedged against a decline in natural gas prices.  We produced 616,780 mcfe at a weighted average price of $5.13 during the Current Quarter compared to 824,489 mcfe at a weighted average price of $7.81 during the Prior Year Quarter which is a decline of 207,709 mcfe and weighted average price of $2.68.  The weighted average price for the Prior Year Quarter included $0.3 million or $0.41 per mcfe of realized gains from a gas derivative contract and $1.0 million or $1.08 per mcfe of unrealized losses from hedge ineffectiveness.

Production from the Antrim shale play represented approximately 91% of our oil and natural gas revenue for the Current Quarter.  The following table summarizes our oil and natural gas revenue by play/trend in the periods set forth below:

	Three Months Ended March 31, 2009				Three Months Ended March 31, 2008
Play/Trend	(mcfe)		Amount		(mcfe)		Amount
Antrim		567,144	$	2,875,700		740,841	$	5,482,339
New Albany		16,484		86,401		38,552		334,718
Other		33,152		204,074		45,096		625,501
Total		616,780	$	3,166,175		824,489	$	6,442,558

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Production from the Prior Year Quarter compared to the Current Quarter decreased by 25%. Lower than expected production resulted from wells undergoing resource assessment and inefficient dewatering in the Antrim resulting from mechanical issues with downhole pumps, rat-hole limitations, and surface problems with pump-off controllers and booster compressors.

Pipeline Transportation and Processing.  Pipeline transportation and processing revenues were $0.2 million in the Current Quarter compared to $0.1 million in the Prior Year Quarter.  This amount represents billings to royalty and working interest owners which are not expected to fluctuate significantly from period-to-period.

Field Service and Sales.  Field service and sales were $0.5 million in the Current Quarter compared to $0.1 million in the Prior Year Quarter.  The majority of services performed by our field services subsidiary, Bach Services and Manufacturing, Co., LLC (“Bach”), during the Prior Year Quarter were for us.  The increase during the Current Quarter was attributed to shifting Bach’s services to unrelated third parties.

Interest and Other Revenues.  Interest and other revenues were $0.4 million in the Current Quarter compared to $0.1 million in the Prior Year Quarter.  This increase is primarily attributed to interest received on the Presidium Energy, LC note receivable in the amount of $0.3 million.

Production Taxes.  Production taxes were $0.1 million in the Current Quarter compared to $0.3 million in the Prior Year Quarter.  This decrease is attributed to a decrease in natural gas prices which determines the amount of production taxes charged for Michigan properties.  On a unit of production basis, production taxes were $0.18 per mcfe in the Current Quarter compared to $0.42 per mcfe in the Prior Year Quarter.

Production and Lease Operating Expenses.  Our production and lease operating expenses include services related to producing oil and natural gas, such as post-production costs which includes marketing and transportation, and expenses to operate the wells and equipment on producing leases.

Production and lease operating expenses were $2.2 million in the Current Quarter compared to $2.7 million in the Prior Year Quarter.  We had 286 net wells producing as of March 31, 2009, as compared to 304 net wells producing as of March 31, 2008.  The reduction in producing wells has resulted in a decrease in utilities in the amount of $0.3 million, pumping in the amount of $0.1 million, and compressor repair and maintenance in the amount of $0.3 million.  The reduction was offset by an increase in non-operated production and lease operating expenses of $0.1 million and workover charges related to our well enhancement program of $0.1 million.  On a per unit of production basis, production and lease operating expenses were $3.57 per mcfe in the Current Quarter compared to $3.39 per mcfe in the Prior Year Quarter.  The increase in production and lease operating expenses on a per unit basis is a result of the significant decrease in production of 207,709 mcfe from the Prior Year Quarter as compared with the Current Quarter.

On a component basis, post-production expenses were $0.8 million, or $1.25 per mcfe, in the Current Quarter compared to $0.7 million, or $0.81 per mcfe, in the Prior Year Quarter.  Increase in post-production expenses were primarily related to additional compression charges incurred as a result of a rate increase administered during May 2008.  Lease operating expenses were $1.4 million, or $2.32 per mcfe, in the Current Quarter compared to $2.0 million, or $2.58 per mcfe, in the Prior Year Quarter.  Decreases in lease operating expenses were primarily related to the reduction in producing wells from the Prior Year quarter which resulted in decreases to utilities, pumping and compressor repair and maintenance expenses.

Production and lease operating expenses for operated properties were $2.26 per mcfe in the Current Quarter while non-operated production and lease operating expenses were $1.31 per mcfe in the Current Quarter.

Pipeline and Processing Operating Expenses.  Pipeline and processing operating expenses were $0.1 million in the Current Quarter and in the Prior Year Quarter.

Field Services Expenses.  Field services expenses were $0.4 million in the Current Quarter compared to $0.1 million in the Prior Year Quarter which are attributed to shifting services performed by Bach to unrelated third party customers.

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General and Administrative Expenses.  Our general and administrative expenses include officer and employee compensation, travel, audit, tax and legal fees, office supplies, utilities, insurance, consulting fees, and office related expenses.  General and administrative expenses in the Current Quarter increased by $0.8 million, or 40%, from the Prior Year Quarter.  This increase was primarily the result of additional legal and consulting services in connection with (1) restructuring efforts amounting to $0.5 million, (2) securing the forbearance agreement amounting to $0.4 million, and (3) general legal costs incurred for corporate matters in the amount of $0.2 million.  This increase was offset by a decrease in payroll and related costs by $0.3 million to $1.4 million in the Current Quarter due to lower employee payroll and stock-based compensation.

We follow the full cost method of accounting under which all costs associated with property acquisition, exploration, and development activities are capitalized.  We capitalized certain internal costs that can be directly identified with our acquisition, exploration, and development activities and do not include any costs related to production, general corporate overhead, or similar activities.  We capitalized $0.2 million of payroll and benefit costs for the Current Quarter compared to $0.6 million in the Prior Year Quarter.  This decrease was primarily related to the reduction in the number of employees associated with acquisition, exploration and development activities along with limited drilling which has reduced our ability to capitalize costs.

Oil and Natural Gas Depletion, Depreciation and Amortization (“DD&A”).  DD&A of oil and natural gas properties was $0.6 million and $1.0 million during the Current Quarter and the Prior Year Quarter, respectively. DD&A is a function of capitalized costs in the full cost pool and related underlying reserves in the periods presented.  This decrease is a combination of significant reductions in amortization base resulting from a full cost pool write-down during December 2008 and a significant reduction in volumes sold keeping the depletion percentage flat.  The average DD&A cost per mcfe also decreased to $0.97 in the Current Quarter compared to $1.19 in the Prior Year Quarter due to a significant reduction in amortization base.

Other Assets Depreciation and Amortization (“D&A”).  D&A of other assets was $0.3 million in the Current Quarter compared to $0.4 million in the Prior Year Quarter.  This decrease was primarily the result of the complete amortization of certain intangible assets during the Prior Year Quarter associated with the Cadence merger.

Interest Expense.  Interest expense was $2.1 million in the Current Quarter compared to $1.5 million in the Prior Year Quarter.  This increase is due to the higher utilization of debt.  In addition, as a result of our defaults on the senior secured credit facility and second lien term loan, interest rates increased resulting in an additional $0.7 million of interest expense for the Current Quarter.

Ceiling Write-Down of Oil and Gas Properties.During the Current Quarter, we recognized a ceiling write-down of oil and gas properties in the amount of $53.6 million as a result of the carrying amount of oil and gas properties subject to amortization exceeding the full cost ceiling limitations.

Taxes, Other.Other taxes include state franchise taxes, state income taxes, and state business taxes.  We have significant net operating loss carryforwards, thus no federal income tax expense has been recognized for either the Current Quarter or Prior Year Quarter.  Tax expense was $34,144 in the Current Quarter compared to a refund of $0.1 million in the Prior Year Quarter.  This increase resulted primarily from a 2006 State of Louisiana income tax refund received during the Prior Year Quarter which reduced tax expenses incurred.

Liquidity and Capital Resources

Our condensed consolidated financial statements for the three months ended March 31, 2009, have been prepared on a going concern basis which contemplates the realization of assets and the settlement of liabilities in the normal course of business.  With the loss of production and significant deficiencies in working capital along with an increase in interest rates and the termination of our natural gas and interest rate derivatives more fully described in the following paragraph, our operations and existing cash balances are not sufficient to support interest requirements on existing debt balances for longer than one year.  We are currently in default under the senior secured credit facility and second lien term loan.  We recognize our continued existence is dependent on (1) lenders’ willingness to refrain from accelerating or demanding repayment on current debt obligations, (2) restructuring of our current debt, (3) securing alternative financing arrangements, and/or (4) asset divestitures.  We continue discussions with existing lenders and are seeking alternative financing arrangements and opportunities for asset divestitures.  Due to the recent events within the banking industry we are having difficulty securing alternative financing arrangements.  While we continue discussions with our current lenders to restructure our debt obligations and continue to seek alternative financing arrangements, there is no assurance the lenders will not call the debt obligation or that we will be able to restructure or refinance our current debt or sell assets in an amount sufficient to remedy our loan defaults.  If we are unsuccessful restructuring our current debt obligations, securing alternative financing arrangements and/or selling assets in an amount sufficient to remedy our loan defaults, our liquidity would be affected in a material manner and we may elect to file for bankruptcy protection.

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On October 1, 2008, we received a notice of early termination from BNP with respect to our natural gas and interest rate swap derivatives (the “Early Termination Notice”) in accordance with the 1992 International Swap Dealers Association, Inc. (“ISDA”) master agreement dated August 20, 2007, between us and BNP.  The Early Termination Notice references Sections 6(a) and 6(b) of the ISDA master agreement which gives BNP the right to terminate following an event of default.  For the three months ended March 31, 2009, the effect of the termination of our natural gas derivatives resulted in a loss of oil and gas revenue in the approximate amount of $3.3 million.  If natural gas continues selling at current prices, our oil and gas revenue will be impacted negatively due to the inability to benefit from gains resulting from hedged production.  Currently, we do not have the ability to hedge our production due to our bank defaults and the lack of borrowing base capacity to meet margin calls.  Based on a sales price of $3.50 per mcf, we estimate lost revenues from our terminated natural gas contracts to be $13.3 million, $13.2 million, and $10.5 million for the years ended December 31, 2009, 2010, and 2011, respectively.  As a result of the natural gas derivative contracts termination, we are presently exposed to the fluctuation of natural gas prices.

Senior Secured Credit Facility

Our senior secured credit facility is a $100 million senior secured credit facility with BNP. In connection with the second lien term loan, we also agreed to the amendment and restatement of our senior secured credit facility with BNP and other lenders, pursuant to which the borrowing base under the senior secured credit facility was increased from the then current authorized borrowing base of $50 million to $70 million.  The amount of the borrowing base was based primarily upon the estimated value of our oil and natural gas reserves.  The borrowing base amount is redetermined by the lenders semi-annually on or about April 1 and October 1 of each year or at other times required by the lenders or at our request.  On June 6, 2008, we were notified that our borrowing base was determined to be only $50 million.  The security for this facility is substantially all of our oil and natural gas properties; guarantees from all material subsidiaries; and a pledge of 100% of our stock or member interest of all material subsidiaries.

The senior secured credit facility provides for borrowings tied to BNP’s prime rate (or, if higher, the federal funds effective rate plus 0.5%) or LIBOR-based rate plus 1.25% to 3.0% depending on the borrowing base utilization, as selected by us. The borrowing base utilization is the percentage of the borrowing base that is drawn under the senior secured credit facility from time to time.  As the borrowing base utilization increases, the LIBOR-based interest rates increase under this facility.  As of March 31, 2009, interest on the borrowings had a weighted average interest rate of 6.37%.  The maturity date of the outstanding loan may be accelerated by the lenders upon occurrence of an event of default under the senior secured credit facility.

On February 12, 2009, we entered into a forbearance agreement to the senior secured credit facility (the “Second Forbearance Agreement”) with BNP Paribas (“BNP” or the “Administrative Agent”) and the syndication.  In accordance with the Second Forbearance Agreement, during the period from December 31, 2008 until April 30, 2009 (the “Second Forbearance Period”), BNP agreed to forbear and refrain from (i) accelerating any loans outstanding and (ii) taking any other enforcement action under the senior secured credit facility at law or otherwise as a result of designated defaults or potential defaults, provided we complied with the forbearance covenants (collectively, the “Second Forbearance Covenants”).

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A summary of the Second Forbearance Covenants were as follows: (i) we shall retain and employ a financial advisor, (ii) we shall deliver to the Administrative Agent an initial detailed budget on or before February 20, 2009, and provide subsequent monthly updates, (iii) we shall deliver to the Administrative Agent prior week aggregated cash balances on or before the last business day of the current week, (iv) no later than February 23, 2009, we will execute (or cause to be executed) additional mortgages and no later than February 18, 2009, we will execute  (or cause to be executed) other security instruments such that, after giving effect to such additional mortgages and other security instruments, the syndication will have liens on 100% of our oil and gas properties, promissory notes, all significant overriding royalties, and all significant farmout agreements prior to such date, (v) we must obtain prior written approval of the Administrative Agent to farmout any assets or sell any assets for more than $200,000; (vi) we shall provide the Administrative Agent notice of any unwritten or written expressions of interest with respect to the purchase of assets of the Company or any of our subsidiaries for an amount in excess of $2.0 million, (vii) us and the financial advisor shall participate in weekly conference calls with the Administrative Agent and the syndication during which a financial officer of the Company must provide updates on restructuring, sale prospects, and cost reduction efforts, (viii) we must deliver to the Administrative Agent copies of any detailed audit reports, management letters, or recommendations submitted to the board of directors, (ix) no later than February 28, 2009, we must deliver a restructuring plan to resolve the borrowing base deficiency, (x) we must maintain a liquidity position of at least $4.0 million during Second Forbearance Period, and (xi) no later than February 23, 2009, we must obtain the consent of the second lien term loan syndication for us to defer until no earlier than the termination of the Second Forbearance Period, payment of the scheduled interest payment currently payable to the second lien term loan syndication on February 24, 2009.

On February 18, 2009, we executed the mortgages, security agreement and pledge agreements necessary to provide the senior secured credit facility lenders a first secured lien on substantially all of our oil and gas properties not previously pledged to them.  We have also complied with the other Second Forbearance Covenants, except that we have not obtained the consent of the second lien lenders to defer payment of the $1.6 million interest payment scheduled to be paid by us on February 24, 2009.  We received correspondence from BNP dated February 27, 2009, indicating that the first lien lenders agree not to declare a forbearance termination event as a result of our failure to obtain the consent of the second lien lenders to defer payment of the interest scheduled to be paid on February 24, 2009, as long as we do not actually make the interest payment during the Second Forbearance Period.  We have recorded the $1.6 million interest payment due to the second lien lenders as a liability included with the second lien term loan obligation.  As more fully described below, Laminar Direct Capital, LLC (“Laminar”) and the second lien term loan syndication cannot take any enforcement or similar actions against our property for at least 180 days beginning November 24, 2008.

We continue to engage in discussions with BNP and the syndication to restructure our debt.  We recognize the senior secured credit facility is due and payable upon notification from BNP, and therefore the entire outstanding debt has been classified as a current liability on the accompanying March 31, 2009 and December 31, 2008 balance sheets.  In addition to discussions with BNP and the syndication, we are also seeking alternative financing arrangements and opportunities for asset divestitures.  There is no assurance that BNP and the syndication will not accelerate or demand repayment of the senior secured credit facility or that we will be successful in restructuring the Company’s debt, finding alternative financing arrangements, or selling our assets.

Second Term Lien Loan

On August 20, 2007, we entered into a second lien term loan agreement with BNP, as the arranger and administrative agent, and several other lenders forming a syndication.  During August 2008 we were notified that Laminar succeeded BNP as the arranger and administrative agent for the second term lien loan.  The initial term loan is $50 million for a 5-year term which may increase up to $70 million under certain conditions over the life of the loan facility.  The proceeds of the second lien term loan were used to payoff our existing mezzanine financing with TCW and for general corporate purposes.  Interest under the second lien term loan is payable at rates based on the London Interbank Offered Rate plus 950 basis points.

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We continue to engage in discussions with Laminar and the syndication to restructure our second lien term loan debt. We recognize that the second term lien loan is due and payable upon notification from Laminar after the expiration of the 180 days beginning November 24, 2008, and therefore the entire outstanding debt has been classified as a current liability on the March 31, 2009 and December 31, 2008 balance sheets.  In addition to discussions with Laminar and the syndication, we are also seeking alternative financing arrangements and opportunities for asset divestitures.  There is no assurance that we will be successful in restructuring our debt, finding alternative financing arrangements, or selling company assets in an amount sufficient to remedy our loan defaults.

Cash Flows from Operating Activities

Cash used in operating activities increased 130% to $1.0 million in the Current Quarter, compared to cash provided by operating activities of $3.2 million in the Prior Year Quarter.  This $4.2 million increase in net cash used in operating activities was primarily due to a significant decrease in oil and gas sales resulting from a reduction in production and gas prices.  See “Results of Operations” for discussion of changes in revenues and expenses.  Noncash charges increased primarily due to interest paid-in-kind on the second lien term loan in the amount of $2.0 million.  Changes in current operating assets and liabilities decreased cash flow from operations by $1.0 million.

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Cash Flows Used in Investing Activities

Cash flows used in investing activities was $1.3 million in the Current Quarter compared to $7.5 million in the Prior Year Quarter.  The following table describes our significant investing transactions that we completed in the periods set forth below:

	Three Months Ended March 31,
	2009			2008
Acquisitions and extensions of leasehold
Michigan Antrim shale	$	20,134		$	335,986
New Albany shale		292,838			417,673
Woodford shale		-			319,361
Other		1,375			24,154
Drilling and development of oil and natural gas properties
Michigan Antrim shale		260,085			1,253,516
Indiana Antrim shale		176			9,874
New Albany shale		35,497			930,868
Other		106,393			644,434
Infrastructure properties
Michigan Antrim shale		-			7,536
New Albany shale		20,836			2,188,704
Capitalized interest and general and administrative costs on exploration, development and leasehold		1,202,478			1,418,420
Purchase of member interest in Hudson Pipeline & Processing Co., LLC		132,087			-
Acquisitions/additions for pipeline, property, and equipment		-			16,947
Other, net		-			3,491
Subtotal of capital expenditures		2,071,899			7,570,964
Sale of oil and natural gas properties		(39,303	)		(60,000	)
Payments received on note receivable		(243,795	)		-
Sales of other investment and other		-			(9,334	)
Redesignation of cash equivalents to short-term investments		(455,984	)		-
Subtotal of capital divestitures		(739,082	)		(69,334	)
Total	$	1,332,817		$	7,501,630

Cash Flows Provided by Financing Activities

Cash flows used in financing activities was $45,285 in the Current Quarter compared to cash flows provided by financing activities of $9.2 million in the Prior Year Quarter. Cash flows used in the Current Quarter included $45,285 pay-down of mortgage and notes payable obligations.

Cash flows provided by financing activities in the Prior Year Quarter included: (1) $9.0 million of senior secured credit borrowing; and (2) $0.4 million of net proceeds received from exercise of common stock options and warrants.  Cash flows used by financing in the Prior Year Quarter included: (1) pay-down of $43,867 in mortgage and notes payable obligations; and (2) payment of $29,142 in financing fees; and (3) payment of $0.1 million on other liabilities.

Recent Accounting Pronouncements

Reference is made to Note 4 to the condensed consolidated financial statements included elsewhere in this filing for a description of certain recently issued accounting pronouncements.  On January 1, 2009, we adopted SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51,” and SFAS No. 141R “Business Combinations”.  SFAS 160 changed the presentation requirements for noncontrolling (minority) interests and SFAS 141R changed the accounting and reporting requirements for business acquisitions.  Refer to Note 4 on page 14 of the condensed consolidated financial statements included in this Form 10-Q for more information.  We do not expect any of the recently issued accounting pronouncements to have a material effect on our consolidated financial position or results of operations.

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Critical Accounting Policies

We consider accounting policies related to use of estimates, oil and natural gas properties, oil and natural gas reserves, stock-based compensation, and income taxes to be critical policies.  These accounting policies are summarized in the audited consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2008.

Off Balance Sheet Arrangements

We have no special purpose entities, financing partnerships, guarantees, or off-balance sheet arrangements other than the $0.8 million of outstanding letter of credits discussed in Note 9 “Commitments and Contingencies” to the condensed consolidated financial statements.

ITEM 3. QUANTITIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our results of operations and operating cash flows are impacted by the fluctuations in the market prices of natural gas.  To mitigate a portion of the exposure to adverse market changes, we previously entered into various derivative instruments with BNP.  The purpose of the derivative instrument was to provide a measure of stability to our cash flow in meeting financial obligations while operating in a volatile natural gas market environment.  The derivative instrument reduced our exposure on the hedged production volumes to decreases in commodity prices and limited the benefit we might otherwise receive from any increases in commodity prices on the hedged production volumes.  Currently, we do not have the ability to hedge our production due to our bank default and the lack of borrowing base capacity to meet margin calls.  Based on current production levels, a $1.00 increase or decrease in natural gas prices would have the effect of causing $0.2 million addition or reduction to our monthly production revenue.

Interest Rate Risk

Our use of debt directly exposes us to interest rate risk. Our policy is to manage interest rate risk through the use of a combination of fixed and floating rate debt. Interest rate swaps may be used to adjust interest rate exposure when appropriate.  On October 1, 2008, we received a letter of termination for our interest rate derivative instrument from BNP.  Since BNP terminated our interest rate derivative, we are presently exposed to the fluctuation of interest rates.  Based on current borrowing levels, a 1.0% increase or decrease in current market rates would have the effect of causing $0.1 million additional charge or reduction to our monthly interest expenses.

The following table sets forth our principal financing obligation and the related interest rates as of March 31, 2009:

	Expected Maturity	Average Interest Rate as of March 31, 2009	Principal Outstanding
Notes payable	09/15/10–10/03/13	5.00–6.95%	$	175,116
Mortgage payable	06/15/10	Fixed at 6.00%		353,069
Mortgage payable	02/01/11	Fixed at 5.95%		2,586,586
Mortgage payable	10/01/11	Fixed at 5.95%		68,566
Second lien term loan	02/01/11	Default at 15.50%		52,999,397
Senior secured credit facility	01/31/10	Default at 6.25%(a)		72,021,446
Total debt			$	128,204,180

(a) Current default rate as of April 30, 2009.

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in our periodic filings under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission's rules and forms, and that such information is accumulated and communicated to our management to allow timely decisions regarding required disclosure.

As discussed in “Part II. Item 9 A. Controls and Procedures” in our Form 10-K for the year ended December 31, 2008, we disclosed a material weakness in our control over financial reporting relating to an error made by us during our initial pricing of our reserve report.  This error resulted in us understating impairment of the full cost pool.  While we have not yet completed a remediation plan, we have instituted certain additional controls over reserve pricing to ensure accuracy for the internally generated reserve report at March 31, 2009.  Accordingly, our Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) of the Securities Exchange Act of 1934, as amended) as of March 31, 2009, and have concluded that these disclosure controls and procedures are effective at the reasonable assurance level. Our CEO and CFO believe that the condensed consolidated financial statements included in this report on Form 10-Q fairly present in all material respects our financial condition, results of operations, and cash flows for the periods presented in conformity with generally accepted accounting principles.

As a result of the error in initially pricing our reserves, we are currently formulating a remediation plan to address this material weakness.  We will have this plan in place prior to commencing preparation procedures for the next reserve report.  This remediation plan is expected to include certain checklists, additional education and training for those employees involved in the reserve reporting process, expanded reserve planning and assumption meetings, and require supporting documentation for the prices to be used in calculating reserve values and any other assumptions that have a material impact in the reserve evaluation.

Our management, including ourCEO and CFO, do not expect that our internal controls will prevent or detect all errors and all fraud.  A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met with respect to financial statement preparation and presentation.  In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or because the degree of compliance with the policies or procedures deteriorates.

Changes in Internal Controls over Financial Reporting

Other than the additional controls over reserve pricing as described above, there have been no changes in our internal controls over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.  As noted above, we are currently formulating a remediation plan to address the material weakness which will result in additional changes to our internal controls during 2009.

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PART II

ITEM 1.  LEGAL PROCEEDINGS

Refer to Note 9 beginning on page 21 of the condensed consolidated financial statements included in this Form 10-Q.

ITEM 1A. RISK FACTORS

Our business has many risks.  Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock are described under “Risk Factors” in Item 1 of our Annual Report on Form 10-K for the year ended December 31, 2008.  This information should be considered carefully, together with other information in this report and other reports and materials we file with the Securities and Exchange Commission.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES

We did not sell any of our unregistered equity securities nor did we repurchase any of our outstanding equity securities during the quarter ended March 31, 2009.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

3.1(1) Restated Articles of Incorporation of Aurora Oil & Gas Corporation.

3.2 By-Laws of Aurora Oil & Gas Corporation. (filed as an Exhibit 3.2 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)

10.1 Securities Purchase Agreement between Cadence Resources Corporation and the investors signatory thereto, dated January 31, 2005 (filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on February 2, 2005, and incorporated herein by reference.)

10.2(2) Asset Purchase Agreement with Nor Am Energy, L.L.C., Provins Family, L.L.C. and O.I.L. Energy Corp. dated January 10, 2006.

10.3 First Amended and Restated Note Purchase Agreement between Aurora Antrim North, L.L.C. et al. and TCW Asset Management Company, dated December 8, 2005 (filed as an Exhibit to our report on Form 10-KSB for the fiscal year ended September 30, 2005 filed with the SEC on December 29, 2005 and incorporated herein by reference.)

10.4(2) First Amendment to First Amended and Restated Note Purchase Agreement between Aurora Antrim North, L.L.C., et al., and TCW Asset Management Company, dated January 31, 2006.

10.5 Amended and Restated Credit Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent and the Lenders Party hereto. (filed as an Exhibit 10.7 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)

10.6(2) Confirmation from BNP Paribas to Aurora Antrim North, L.L.C., dated February 22, 2006 relating to gas sale commitment.

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10.7 2006 Stock Incentive Plan. (filed as Exhibit 99.1 to our Form S-8 Registration Statement filed with the SEC on May 15, 2006 and incorporated herein by reference.)

10.8(1) Employment Agreement with Ronald E. Huff dated June 19, 2006.

10.9(1) Letter Agreement with Bach Enterprises dated July 10, 2006. (A redacted copy is filed as an exhibit to Amendment No. 4 to our Form 10-QSB/A filed on January 30, 2008.)

10.10(1) First Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated July 14, 2006.

10.11(3) LLC Membership Interest Purchase Agreement dated October 6, 2006 relating to Kingsley Development Company, L.L.C.

10.12(3) Asset Purchase Agreement with Bach Enterprises, Inc., et al., dated October 6, 2006.

10.13(3) Form of indemnification letter agreement between Aurora Oil & Gas Corporation and Rubicon Master Fund.

10.14 Second Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated December 21, 2006. (filed as an Exhibit 10.24 to our report on Form 10-KSB for the fiscal year ended December 31, 2006, filed with the SEC on March 15, 2007 and incorporated herein by reference.)

10.15 Third Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated June 20, 2007. (filed as an Exhibit 10.25 to our Form 10-Q for the period ended June 30, 2007, filed with the SEC on August 9, 2007 and incorporated herein by reference.)

10.16 Intercreditor Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent and the Lenders Party hereto. (Replaced Exhibit 10.8 Intercreditor and Subordination Agreement among, BNP Paribas, et al., TCW Asset Management Company, and Aurora Antrim North, L.L.C., dated January 31, 2006.) (filed as an Exhibit 10.26 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)

10.17 Second Lien Term Loan Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent and the Lenders Party hereto. (filed as an Exhibit 10.27 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)

10.18 Promissory Note from Aurora Oil & Gas Corporation to Northwestern Bank dated February 14, 2008 (filed as Exhibit 10.18 to our Form 10-K as originally filed with the SEC on March 7, 2008, and incorporated herein by reference).

10.19 Forbearance Agreement and Amendment No. 1 to Credit Agreement dated June 2, 2008, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent for the Lenders, the Lenders and the Secured Swap Providers. (filed as Exhibit 10.19 to our Form 8-K dated June 6, 2008, filed with the SEC on June 12, 2008, and incorporated herein by reference.)

10.20 Forbearance Agreement and Amendment No. 1 to Second Lien Term Loan Agreement dated June 2, 2008, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent for the Lenders, and the Lenders (filed as Exhibit 10.20 to our Form 8-K dated June 6, 2008, filed with the SEC on June 12, 2008, and incorporated herein by reference.)

10.21 Forbearance Agreement dated February 12, 2009, among Aurora Oil & Gas Corporation, as Borrower, BNP Paribas, as Administrative Agent for the Lenders, and the Lenders.  (filed as Exhibit 10.21 to our Form 8-K dated February 12, 2009, filed with the SEC on February 18, 2009, and incorporated herein by reference).

14.1 Code of Conduct and Ethics (updated 2/1/08) (filed as exhibit 14.1 to our Form 10-K as originally filed with the SEC on March 7, 2008, and incorporated herein by reference).

16.1 Letter concerning change of certifying accountant from Rachlin Cohen & Holtz, LLP (filed as an Exhibit 16.1 to our Form 8-K dated March 23, 2007, filed with the SEC on March 29, 2007, and incorporated herein by reference).

*31.1 Rule 13a-14(a) Certification of Principal Executive Officer.

*31.2 Rule 13a-14(a) Certification of Principal Financial and Accounting Officer.

*32.1 Section 1350 Certification of Principal Executive Officer.

*32.2 Section 1350 Certification of Principal Financial and Accounting Officer.

* Filed with this Form 10-Q.

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(1) Filed as an exhibit to our Form 10-QSB for the period ended June 30, 2006, filed with the SEC on August 7, 2006, and incorporated herein by reference.

(2) Filed as an exhibit to our Form 10-KSB for the fiscal year ended December 31, 2005, filed with the SEC on March 31, 2006, and incorporated herein by reference.

(3) Filed on October 27, 2006, with our Amendment No. 3 to Form SB-2 registration statement filing, registration no. 333-137176, and incorporated herein by reference.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this quarterly report on Form 10-Q to be signed on its behalf by the undersigned thereunto duly authorized.

	AURORA OIL & GAS CORPORATION
Date:  May 8, 2009	By:	/s/ William W. Deneau
		Name:   William W. Deneau
		Title:      Chief Executive Officer

Date:  May 8, 2009	By:	/s/ Barbara E. Lawson
		Name:    Barbara E. Lawson
		Title:      Chief Financial Officer

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