Aurora Oil & Gas 10-Q 2008 Q1 Quarterly report

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, 2008

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

FOR THE TRANSITION PERIOD FROM ___________ TO _____________.

Commission file number: 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 o

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

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

Yes o No x 

The number of shares of the registrant’s common stock outstanding as of May 7, 2008, was 102,932,788.

FORM 10-Q

INDEX

PART I	FINANCIAL INFORMATION	1
Item 1.	Condensed Consolidated Financial Statements	2
Condensed Consolidated Balance Sheets as of March 31, 2008 (Unaudited), and December 31, 2007 (Audited)		2
Unaudited Statements of Operations for the Three Months Ended March 31, 2008, and 2007		4
Unaudited Statements of Shareholders’ Equity for the Three Months Ended March 31, 2008, and 2007		5
Unaudited Statements of Cash Flows for the Three Months Ended March 31, 2008, and 2007		6
Notes to Unaudited Condensed Consolidated Financial Statements		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	33
PART II	OTHER INFORMATION	34
Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3.	Defaults Upon Senior Securities	34
Item 4.	Submission of Matters to a Vote of Security Holders	34
Item 5.	Other Information	34
Item 6.	Exhibits	34
Signatures		36

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:

· the quality of our properties with regard to, among other things, the existence of reserves in economic quantities;

· uncertainties about the estimates of reserves;

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

· the number of well locations to be drilled and the time frame within which they will be drilled;

· the timing and extent of changes in commodity prices for natural gas and crude oil;

· domestic demand for oil and natural gas;

· drilling and operating risks;

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

· changes in our drilling plans and related budgets; and

· 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, 2008 (Unaudited)			December 31, 2007 (Audited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	7,326,118		$	2,425,678
Accounts receivable
Oil and natural gas sales		3,855,060			5,036,416
Joint interest owners		876,975			851,638
Prepaid expenses and other current assets		911,909			765,730
Short-term derivative instruments		-			2,247,990
Total current assets		12,970,062			11,327,452
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, using full cost accounting:
Proved properties		173,732,742			167,282,245
Unproved properties		55,897,796			56,937,683
Less: accumulated depletion and amortization		(15,384,015	)		(14,401,584	)
Total oil and natural gas properties, net		214,246,523			209,818,344
Other property and equipment:
Pipelines, processing facilities, and compression		6,458,979			6,469,336
Other property and equipment		5,511,511			5,450,452
Less: accumulated depreciation		(1,777,458	)		(1,554,189	)
Total other property and equipment, net		10,193,032			10,365,599
Total property and equipment, net		224,439,555			220,183,943
OTHER ASSETS:
Goodwill		19,373,264			19,373,264
Intangibles (net of accumulated amortization of $4,630,000 and $4,497,920, respectively)		325,000			457,080
Other investments		208,381			733,836
Debt issuance costs (net of accumulated amortization of $479,661 and $360,972, respectively)		1,547,056			1,661,603
Other		1,024,119			934,490
Total other assets		22,477,820			23,160,273
TOTAL ASSETS	$	259,887,437		$	254,671,668

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, 2008 (Unaudited)			December 31, 2007 (Audited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	5,251,746		$	6,490,981
Accrued exploration, development, and leasehold costs		393,785			1,341,917
Current portion of obligations under capital leases		6,675			6,288
Current portion of note payable		87,889			76,416
Current portion of mortgage payable		117,672			112,326
Drilling advances		46,594			168,356
Short-term derivative instruments		6,930,646			384,706
Total current liabilities		12,835,007			8,580,990
LONG-TERM LIABILITIES:
Obligations under capital leases, net of current portion		-			1,496
Asset retirement obligation		1,536,607			1,494,745
Notes payable		157,528			143,062
Mortgage payable		2,939,254			2,969,870
Senior secured credit facility		65,000,000			56,000,000
Second lien term loan		50,000,000			50,000,000
Long-term derivative instruments		5,936,268			2,248,326
Other long-term liabilities		839,340			977,529
Total long-term liabilities		126,408,997			113,835,028
Total liabilities		139,244,004			122,416,018
Minority interest in net assets of subsidiaries		127,766			112,661
COMMITMENTS, CONTINGENCIES, AND SUBSEQUENT EVENT (Note 9 and Note 11)
SHAREHOLDERS’ EQUITY
Common stock, $0.01 par value; authorized 250,000,000 shares; issued and outstanding 102,432,788 and 101,769,456 shares, respectively		1,024,328			1,017,695
Additional paid-in capital		141,602,229			140,541,460
Accumulated other comprehensive loss		(11,898,359	)		(385,043	)
Accumulated deficit		(10,212,531	)		(9,031,123	)
Total shareholders’ equity		120,515,667			132,142,989
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	259,887,437		$	254,671,668

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,
	2008			2007
REVENUES:
Oil and natural gas sales	$	6,442,558		$	5,929,576
Pipeline transportation and processing		224,171			129,268
Field service and sales		123,559			189,518
Interest and other		102,687			13,513
Total revenues		6,892,975			6,261,875
EXPENSES:
Production taxes		339,314			263,098
Production and lease operating expenses		2,787,724			1,925,893
Pipeline and processing operating expenses		89,223			113,420
Field services expense		119,155			154,272
General and administrative expenses		1,997,061			2,260,343
Oil and natural gas depletion and amortization		979,908			746,865
Other assets depreciation and amortization		355,773			568,606
Interest expense		1,462,412			981,532
Taxes (refunds), other		(71,292	)		(25,182	)
Total expenses		8,059,278			6,988,847
LOSS BEFORE MINORITY INTEREST		(1,166,303	)		(726,972	)
MINORITY INTEREST IN LOSS OF SUBSIDIARIES		(15,105	)		(13,347	)
NET LOSS	$	(1,181,408	)	$	(740,319	)
NET LOSS PER COMMON SHARE—BASIC and DILUTED	$	(0.01	)	$	(0.01	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING—BASIC and DILUTED		102,227,258			101,552,888

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

4

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Unaudited)

	Three Months Ended March 31,
	2008					2007
	Shares		Amount			Shares		Amount
COMMON STOCK:
Balance, beginning		101,769,456	$	1,017,695			101,412,966	$	1,014,130
Cashless exercise of stock options and warrants		-		-			78,158		782
Exercise of stock options and warrants		663,332		6,633			153,332		1,533
Balance, ending		102,432,788		1,024,328			101,644,456		1,016,445
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning				140,541,460					138,105,626
Cashless exercise of stock options and warrants				-					(782	)
Issuance of stock in connection with public equity offering				-					(10,096	)
Stock-based compensation				693,652					661,380
Exercise of stock options and warrants				367,117					55,966
Balance, ending				141,602,229					138,812,094
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Balance, beginning				(385,043	)				5,220,633
Changes in fair value of derivative instruments				(11,253,481	)				(3,027,593	)
Recognition of gain on derivative instruments				(259,835	)				(785,000	)
Balance, ending				(11,898,359	)				1,408,040
ACCUMULATED DEFICIT:
Balance, beginning				(9,031,123	)				(4,609,290	)
Net loss				(1,181,408	)				(740,319	)
Balance, ending				(10,212,531	)				(5,349,609	)
TOTAL SHAREHOLDERS’ EQUITY			$	120,515,667				$	135,886,970

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,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,181,408	)	$	(740,319	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization		1,335,681			1,315,471
Amortization of debt issuance costs		137,512			218,234
Accretion of asset retirement obligation		27,545			18,895
Deferred gain on sale of natural gas compression equipment		(33,207	)		-
Stock-based compensation		672,962			594,044
Equity loss of other investments and other		30			96,181
Unrealized loss on ineffective commodity derivative		968,556			-
Minority interest income of subsidiaries		15,105			13,347
Changes in operating assets and liabilities:
Accounts receivable – oil and natural gas sales		1,181,356			(154,854	)
Accounts receivable – joint interest owners		(31,507	)		1,016,489
Drilling advance – liabilities		(121,762	)		186,640
Prepaid expenses and other assets		(133,980	)		(367,824	)
Accounts payable and accrued liabilities		237,460			(557,848	)
Net cash provided by operating activities		3,074,343			1,638,456
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and natural gas properties		(6,237,928	)		(16,691,086	)
Leasehold expenditures, net		(1,174,830	)		(2,781,677	)
Sale of oil and natural gas properties		60,000			1,025,000
Acquisitions/additions for pipeline, property, and equipment		(16,947	)		(144,456	)
Additions in other investments		(3,491	)		-
Sales of other investments		9,334			-
Other		-			(37,412	)
Net cash used in investing activities		(7,363,862	)		(18,629,631	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term bank borrowings		100,000			390,000
Short-term bank payments		(100,000	)		(924,173	)
Advances on senior secured credit facility		9,000,000			18,000,000
Payments on mortgage obligations		(25,270	)		(32,656	)
Payments on notes payable		(18,597	)		(45,514	)
Payments of financing fees on credit facilities		(29,142	)		(25,000	)
Payments on other long-term liabilities		(19,687	)		-
Proceeds from exercise of options and warrants		373,750			57,499
Other		(91,095	)		(14,611	)
Net cash provided by financing activities		9,189,959			17,405,545
Net increase in cash and cash equivalents		4,900,440			414,370
Cash and cash equivalents, beginning of the period		2,425,678			1,735,396
Cash and cash equivalents, end of the period	$	7,326,118		$	2,149,766

6

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited-continued)

	Three Months Ended March 31,
	2008			2007
NONCASH FINANCING AND INVESTING ACTIVITIES:
Oil and natural gas properties asset retirement obligation	$	14,317		$	(581,840	)
Accrued exploration and development costs on oil and natural gas properties		73,304			4,321,933
Accrued leasehold costs		320,481			463,366
Oil and natural gas properties capitalized stock-based compensation		20,690			67,336
Conversion of accounts receivable to notes receivable		6,170			10,632
Vehicle purchase through financing		44,536			-
SUPPLEMENTAL INFORMATION OF INTEREST AND INCOME TAXES PAID (RECEIVED):
Interest, net of amount capitalized of $1,177,104 and $869,810, respectively	$	1,325,766		$	434,955
Income taxes		(111,789	)		107,600

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 a growing 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 currently focused on acquiring and developing operating interests in unconventional drilling programs in the Michigan Antrim shale, the New Albany shale of Indiana and Kentucky and the Woodford shale in Oklahoma. The Company is a Utah corporation whose common stock is listed and traded on the American Stock Exchange.

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. A substantial 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.

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, 2007, which has been derived from our audited consolidated financial statements as of December 31, 2007. 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 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/A for the year ended December 31, 2007.

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.

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)

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 financial derivative instruments, and the estimated fair value of asset retirement obligations.

Reclassifications

Certain reclassifications have been made to the condensed financial statements for the three months ended March 31, 2007, in order to conform to the December 31, 2007, and March 31, 2008, presentation. These reclassifications had no effect on net loss or net cash flows as previously reported.

Asset Retirement Obligation

On January 1, 2006, the Company adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” which is an interpretation of FASB Statement No. 143 “Accounting for Asset Retirement Obligations.” Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value can be reasonably estimated. The Company estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future dismantlement and removal of production equipment and facilities and the restoration and reclamation of a field’s surface to a condition similar to that existing before oil and natural gas extraction began.

In general, the amount of an Asset Retirement Obligation (“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.

Effective January 1, 2007, the accretion of the ARO on producing wells was adjusted for a change in the estimated life of the wells based on a reserve study prepared by Data & Consulting Services, Division of Schlumberger Technology Corporation, an independent reserve engineering firm. The estimated life of the wells was increased by 10 years to an estimated life of 50 years per well resulting in a reduction of $0.6 million to estimated liabilities for the three months ended March 31, 2007. Revisions for the three months ended March 31, 2008, are not considered material and primarily relate to changes in working interest on certain properties.

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)

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

	2008			2007
Beginning balance	$	1,495		$	1,332
Liabilities incurred		14			67
Liabilities settled		(3	)		(34	)
Accretion expense		28			19
Revisions of estimated liabilities		3			(617	)
Ending balance	$	1,537		$	767

Natural Gas Derivative Instruments

The Company’s 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, the Company will periodically enter into various derivative instruments with a major financial institution. The purpose of the derivative instrument is to provide a measure of stability to the Company’s cash flow in meeting financial obligations while operating in a volatile natural gas market environment. The derivative instrument reduces the Company’s exposure on the hedged production volumes to decreases in commodity prices and limits the benefit the Company might otherwise receive from any increases in commodity prices on the hedged production volumes.

The Company recognizes all derivative instruments as assets or liabilities in the balance sheet at fair value. The accounting treatment for changes in fair value, as specified in SFAS No. 133 “Accounting for Derivative Investments and Hedging Activities,” is dependent upon whether or not a derivative instrument is designated as a hedge. For derivatives designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in Accumulated Other Comprehensive Income on the accompanying balance sheet until the hedged item is recognized in earnings as natural gas revenue. If the hedge has an ineffective portion, that particular portion of the gain or loss would be immediately reported in earnings. The following natural gas contracts were in place as of March 31, 2008, and qualified as cash flow hedges (fair value $ in thousands):

Period	Type of Contract		Natural Gas Volume per Day		Price per mmbtu		Fair Value Asset (Liability)
April 2007—December 2008		Swap		5,000 mmbtu	$	9.00	$	(2,037	)
April 2007—December 2008		Collar		2,000 mmbtu	$	7.55/$ 9.00		(942	)
January 2008 – December 2008		Swap		2,000 mmbtu	$	8.41		(1,140	)
January 2009—December 2009		Swap		7,000 mmbtu	$	8.72		(2,991	)
January 2010—March 2011		Swap		7,000 mmbtu	$	8.68		(1,860	)
April 2011 - September 2011		Swap		7,000 mmbtu	$	7.62		(1,156	)
Total Estimated Fair Value							$	(10,126	)

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)

For the three months ended March 31, 2008, the Company has recognized in Comprehensive Income (Loss) changes in fair value of $(10.0) million on the contracts that have been designated as cash flow hedges on forecasted sales of natural gas. See “Comprehensive Income (Loss)” found in this note section.

For the Company’s cash flow hedges, the designated hedged risk is primarily the risk of changes in cash flows attributable to changes in the production of gas. The Company’s natural gas contracts require the Company to produce certain volumes on a daily basis. During January 2008, the Company determined that it was unable to meet a portion of the volume required by one of the natural gas contracts. As a result, that portion was deemed to be ineffective. The following components of oil and natural gas sales were recorded for the three months ended March 31 ($ in thousands):

	2008			2007
Oil and natural gas sales	$	7,079		$	5,145
Realized gains on natural gas derivatives		314			785
Realized gains on ineffectiveness of cash flow hedges		19			-
Unrealized losses on ineffectiveness of cash flow hedges		(969	)		-
	$	6,443		$	5,930

Interest Rate Derivative Instruments

The Company’s use of debt directly exposes it to interest rate risk. The Company’s 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. These derivatives are used as hedges and are not for speculative purposes. These derivatives involve the exchange of amounts based on variable interest rates and amounts based on a fixed interest rate over the life of the agreement without an exchange of the notional amount upon which payments are based. The interest rate differential to be received or paid on the swaps is recognized over the lives of the swaps as an adjustment to interest expense.

In August 2007, the Company entered into a 3-year interest rate swap agreement in the notional amount of $50 million with BNP to hedge its exposure to the floating interest rate on the $50 million second lien term loan. The swap converted the debt’s floating three month LIBOR base to 4.86% fixed base. This swap on $50 million will yield an effective interest rate of 11.86% for the period from August 23, 2007 through August 23, 2010 on the second lien term loan.

For the three months ended March 31, 2008, the Company has recognized in Comprehensive Income (Loss) changes in fair value of $(1.5) million on the interest rate swap. See “Comprehensive Income (Loss)” found in this note section. For the three months ended March 31, 2008, the Company recognized $0.1 million in interest expense related to the hedge activity which is recorded as an adjustment to interest expense. Fair value liability of the interest rate swap agreement at March 31, 2008, amounted to $2.8 million.

Financial Instruments

The Company’s financial instruments consist primarily of cash, accounts receivable, loans receivable, accounts payable, accrued expenses, and debt. The carrying amounts of such financial instruments approximate their respective estimated fair value due to the short-term maturities and approximate market interest rates of these instruments.

11

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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):

	2008		2007
General and administrative expenses	$	673	$	594
Oil and natural gas properties		21		67
Total	$	694	$	661

The following table provides the unrecognized compensation expense related to unvested stock options as of March 31, 2008. The expense is expected to be recognized over the following 3-year period ($ in thousands).

Period to be Recognized	2008		2009		2010		Total Unrecognized Compensation Expense
1st Quarter	$	-	$	37	$	1
2nd Quarter		141		17		-
3rd Quarter		125		6		-
4th Quarter		103		3		-
Total	$	369	$	63	$	1	$	433

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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. The details of comprehensive income (loss) are as follows for the three months ended March 31 ($ in thousands):

	2008			2007
Net loss	$	(1,181	)	$	(740	)
Other comprehensive loss:
Change in fair value of natural gas derivative instruments		(9,698	)		(3,028	)
Change in fair value of interest rate derivative instruments		(1,555	)		-
Recognition of gains on derivative instruments		(260	)		(785	)
Comprehensive loss	$	(12,694	)	$	(4,553	)

Income (Loss) Per Share

Basic net income (loss) per 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, 2008, and 2007, respectively, options to purchase 4,356,280 and 2,284,500 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. RECENT ACCOUNTING PRONOUNCEMENTS

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS 161”). SFAS 161 requires enhanced disclosures about an entity’s derivative instruments and hedging activities, including: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with earlier application encouraged. The adoption of SFAS 161 will require increased financial statement disclosures but will not affect our consolidated financial position, operating results, or cash flows.

NOTE 4. FAIR VALUE MEASUREMENT

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which is effective for fiscal years beginning after November 15, 2007, and for interim periods within those years. This statement defines fair value, establishes a framework for measuring fair value and expands the related disclosure requirements. This statement applies under other accounting pronouncements that require or permit fair value measurements. The statement indicates, among other things, that a fair value measurement assumes that the transaction to sell an asset or transfer a liability occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability. SFAS 157 defines fair value based upon an exit price model.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 4. FAIR VALUE MEASUREMENT (continued)

Relative to SFAS 157, the FASB issued FASB Staff Positions (“FSP”) 157-1 and 157-2. FSP 157-1 amends SFAS 157 to exclude SFAS No. 13, “Accounting for Leases” (“SFAS 13”), and its related interpretive accounting pronouncements that address leasing transactions, while FSP 157-2 delays the effective date of the application of SFAS 157 to fiscal years beginning after November 14, 2008, for all nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis.

We adopted SFAS 157 as of January 1, 2008, with the exception of the application of the statement to nonrecurring nonfinancial assets and nonfinancial liabilities. Nonrecurring nonfinancial assets and nonfinancial liabilities for which we have not applied the provisions of SFAS 157 include those measured at fair value in goodwill impairment testing, indefinite lived intangible assets measured at fair value for impairment testing, and asset retirement obligations initially measured at fair value.

Valuation Hierarchy. SFAS 157 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into three broad levels as follows. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument. Level 3 inputs are unobservable inputs based on our own assumptions used to measure assets and liabilities at fair value. A financial asset or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.

The following table provides the assets and liabilities carried at fair value measured on a recurring basis as of March 31, 2008 ($ in thousands):

			Fair Value Measurements at March 31, 2008, Using
	Total Carrying Value at March 31, 2008		Quoted prices in active markets (Level 1)		Significant other unobservable inputs (Level 2)		Significant unobservable inputs (Level 3)
Derivative liabilities—cash flow hedges	$	10,126		-	$	10,126		-
Derivative liabilities—interest rate swap		2,741		-		2,741		-

Valuation Techniques. The fair value of these derivatives are based on quoted prices from a commercial bank using a discounted cash flow model and are classified within Level 2 of the valuation hierarchy.

NOTE 5. ACQUISITIONS AND DISPOSITIONS

2007 - Kansas Project

On February 7, 2007, the Company entered into a Purchase and Sale Letter Agreement to sell to Harvest Energy, LLC all of the Company’s interest in various developed and undeveloped oil and natural gas properties located in Lane and Ness Counties in the State of Kansas for approximately $1.0 million. The properties included two net wells, 98 mmcfe in proven reserves, and approximately 23,110 net acres. This transaction closed on March 9, 2007.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6. DEBT

Short-Term Bank Borrowings

The Company had a $5.0 million revolving line of credit agreement with Northwestern Bank for general corporate purposes through October 15, 2007. The Company elected not to request an extension of this revolving line of credit beyond the expiration date of October 15, 2007. Interest expense on the revolving line of credit for the three months ended March 31, 2007, was $28,098.

Northwestern Bank continues to provide letters of credit for the Company’s drilling program (as described in Note 9 “Commitments and Contingencies”). These letters of credit may be extended or may be replaced upon their expiration dates by letters of credit under the Company’s senior secured credit facility.

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

Effective December 12, 2007, Bach obtained an increase in its borrowing capacity under the revolving line of credit from $0.5 million to $1.0 million with Northwestern Bank. 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 (5.25% at March 31, 2008, and 8.25% at March 31, 2007) with interest payable monthly in arrears. Principal is payable at the expiration of the revolving line of credit agreement. The expiration date is October 1, 2008. Interest expense for the three months ended March 31, 2008, and 2007, was $1,523 and $1,163, respectively.

Mortgage and Notes Payable - Bach

On October 6, 2006, Bach entered into a mortgage loan from Northwestern Bank in the amount of $383,026 for the purchase of an office and storage building. The mortgage is collateralized by the building. The payment schedule is principal and interest in 36 monthly payments of $2,899 with one principal and interest payment of $348,988 on November 15, 2009. The interest rate is 6.00% per year. As of March 31, 2008, the principal amount outstanding was $0.4 million. Interest expense for the three months ended March 31, 2008, and 2007, was $5,525 and $5,930, respectively.

On various dates ranging from October 5, 2006, through March 31, 2008, Bach entered into six note payable obligations with Northwestern Bank for the financing of 13 vehicles. The note payable obligations mature on various dates ranging from October 15, 2009, through April 1, 2012. Fixed interest rates are charged at percentages ranging from 6.50% to 7.50%. As of March 31, 2008, the total principal amount outstanding was $0.2 million. Total interest expense for the three months ended March 31, 2008, and 2007, was $3,873 and $2,900, respectively.

On October 6, 2006, Bach entered into a note payable obligation with Northwestern Bank for the purchase of equipment. This obligation was paid in full during September 2007. Total interest expense for the three months ended March 31, 2007, was $168.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6. DEBT (continued)

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 $2,692,849 on February 1, 2011. The interest rate is 5.95% per year. As of March 31, 2008, the principal amount outstanding was $2.7 million. Interest expense for the three months ended March 31, 2008, and 2007, was $42,407 and $36,252, respectively.

Note Payable - Directors and Officers Insurance

On November 13, 2006, the Company entered into a financing agreement with AICCO, Inc. to finance the insurance premium related to director and officer liability insurance coverage in the amount of $184,230. This obligation was paid in full during August 2007. Interest expense for the three months ended March 31, 2007, was $36,252.

Second Lien Term Loan

On August 20, 2007, the Company entered into a second lien term loan agreement with BNP Paribas (“BNP”), as the arranger and administrative agent, and several other lenders forming a syndicate. The initial term loan is $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 (“TCW”) 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 700 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. The Company has the ability to prepay the second lien term loan during the first year at a price equal to 103% of par, during the second year at a price equal to 102% of par, and thereafter at a price equal to 100% of par.

The second lien term loan contains, among other things, a number of financial and non-financial covenants relating to restricted payments (as defined), loans or advances to others, additional indebtedness, incurrence of liens, geographic limitations on operations to the United States, and maintenance of certain financial and operating ratios, including (i) maintenance of a maximum of indebtedness to earnings before interest, income taxes, depreciation, depletion and amortization and non-cash expenses, and (ii) maintenance of minimum reserve value to indebtedness. Any event of default under the senior secured credit facility that accelerates the maturity of any indebtedness thereunder is also an event of default under the second lien term loan.

In both the second lien term loan and senior secured credit facility, the Company agreed to an affirmative covenant regarding production exit rates. The production exit target is 12.0 MMcfe per day as of December 31, 2007 (which was achieved), and as of the last day of each quarter thereafter. In addition, the Company was required to purchase financial hedges at prices and aggregate notional volumes satisfactory to BNP, as administrative agent.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6. DEBT (continued)

On April 29, 2008 management became aware that the Company failed to achieve daily production of 12.0 mmcfe per day and exceeded the maximum total debt to EBITDAX ratio as of March 31, 2008. According to the second lien term loan agreement the Company has until May 29, 2008 (30 days) to remediate the covenant failures in order to avoid an event of default. Management has developed a plan to remediate the covenant deficiencies which includes among other items, production enhancements, a plan to reduce general, administrative, and production expenses, and the possible sale of certain non-core assets. In case the Company is unable to successfully remediate the covenant failures, management has also requested BNP to waive the Company’s failure to observe or perform the daily production of 12.0 mmcfe per day and to meet the total debt to EBITDAX ratio requirement as of March 31, 2008. There are no assurances the Company will be able to successfully remediate the covenant failures by May 29, 2008, or that the Company will receive a waiver from BNP. If an event of default occurs, BNP has the right to demand repayment of the second lien term loan obligation which would adversely affect the Company’s liquidity in a material manner.

For the three months ended March 31, 2008, interest and fees incurred for the second lien term loan was $1.4 million. The Company has also incurred deferred financing fees of approximately $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 $65,686 for the three months ended March 31, 2008. In addition, the Company incurs annual agency fees which are recorded to interest expense.

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 lien term loan discussed above, 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 is based primarily upon the estimated value of the Company’s 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 the Company’s request. The required semi-annual reserve report may result in an increase or decrease in credit availability. 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 2.0% 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, 2008, interest on the borrowings had a weighted average interest rate of 4.66%. For the three months ended March 31, 2008, and 2007, interest and fees incurred for the senior secured credit facility were $0.9 million and $0.4 million, respectively. All outstanding principal and accrued and unpaid interest under the senior secured facility is due and payable on January 31, 2010. 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.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6. DEBT (continued)

The senior secured credit facility contains, among other things, a number of financial and non-financial covenants relating to restricted payments (as defined), loans or advances to others, additional indebtedness, incurrence of liens, geographic limitations on operations to the United States, and maintenance of certain financial and operating ratios, including (i) maintenance of a minimum current ratio, and (ii) maintenance of a minimum interest coverage ratio. Any event of default under the second lien term loan that accelerates the maturity of any indebtedness thereunder is also an event of default under the senior secured credit facility.

On April 29, 2008 management became aware that the Company failed to achieve daily production of 12.0 mmcfe per day and meet the required interest coverage ratio as of March 31, 2008. According to the senior secured credit facility agreement the Company has until May 29, 2008 (30 days) to remediate the covenant failures in order to avoid an event of default. Management has developed a plan to remediate the covenant deficiencies which includes among other items, production enhancements, a plan to reduce general, administrative, and production expenses, and the possible sale of certain non-core assets. In case the Company is unable to successfully remediate the covenant failures, management has also requested BNP to waive the Company’s failure to observe or perform the daily production of 12.0 mmcfe per day and to meet the interest coverage ratio requirement as of March 31, 2008. There are no assurances the Company will be able to successfully remediate the covenant failures by May 29, 2008, or that the Company will receive a waiver from BNP. If an event of default occurs, BNP has the right to demand repayment of the senior secured credit facility obligation which would adversely affect the Company’s liquidity in a material manner.

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 $53,003 and $34,050 for the three months ended March 31, 2008, and 2007, respectively. In addition, the Company incurs various annual fees associated with unused commitment and agency fees which are recorded to interest expense.

Mezzanine Financing

Effective August 20, 2007, the Company’s subsidiary Aurora Antrim North, L.L.C. (“North”) terminated its Amended Note Purchase Agreement with TCW which provided $50 million in mezzanine financing. As of the effective date, North had outstanding borrowing of $40 million. The interest rate was fixed at 11.5% per year, compounded quarterly, and payable in arrears. TCW had limited the borrowing base and the agreement contained a commitment expiration date of August 12, 2007. Under the termination provisions, the Company was required to pay certain fees and prepayment charges associated with early termination.

As part of the mezzanine financing with TCW, North provided an affiliate of TCW an overriding royalty interest of 4% in certain leases to be drilled or developed in the Counties of Alcona, Alpena, Charlevoix, Cheboygan, Montmorency, and Otsego in the State of Michigan. The overriding royalty interest will also continue on leases, including extensions or renewals, held by the Company and its affiliates at August 20, 2007, that may be developed through September 29, 2009.

For the three months ended March 31, 2007, interest and fees incurred for the mezzanine credit facility was $1.2 million.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7. SHAREHOLDERS’ 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.

In January 2007, 78,158 shares of the Company’s common stock were issued in connection with the exercise of outstanding warrants by an outside party in a net issue (cashless) exercise transaction.

In February and March 2007, 60,000 common stock options were exercised by various Company employees under the existing stock option plans at an exercise price of $0.375 per share. The Company received $22,500 in connection with this exercise.

In February and March 2007, 93,332 common stock options were exercised by various Company directors under the existing stock option plans at an exercise price of $0.375 per share. The Company received $35,000 in connection with these exercises.

Common Stock Warrants

The following table sets forth information related to stock warrant activity for the three months ended March 31, 2008 (shares shown in thousands):

	Number of Shares Underlying Warrants		Weighted Average Exercise Price		Weighted Average Contract Life in Years
Outstanding at the beginning of the period		1,952	$	1.74		1.09
Granted		-		-		-
Exercised		-		-		-
Forfeitures and other adjustments		-		-		-
Outstanding at the end of the period		1,952	$	1.74		0.84

NOTE 8. COMMON STOCK OPTIONS

As of March 31, 2008, the Company maintains four stock option plans that are fully described in Note 10 “Common Stock Options” in the Company’s Annual Report on Form 10-K/A for the year-ended December 31, 2007. 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, 2008 (shares shown in thousands):

	Number of Shares Underlying Options
Options outstanding at beginning of period		2,873
Options granted		-
Options exercised		(163	)
Options forfeited and other adjustments		(3	)
Options outstanding at end of period		2,707

No options were granted during the three months ended March 31, 2008; therefore, weighted average assumptions used in the Black-Scholes option-pricing model are not presented.

All Stock Options

In addition, the Company has awarded compensatory options and warrants totaling 1,430,280 on an individualized basis that was considered outside the awards issued under its existing stock option plans. Activity with respect to all stock options is presented below for the three months ended March 31, 2008 (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		4,304		$	2.25
Options granted		-			-
Options exercised		(663	)		0.56
Forfeitures and other adjustments		(3	)		4.70
Options outstanding at end of period		3,638		$	2.56	$	102
Exercisable at end of period		2,756		$	2.15	$	102
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. The intrinsic value of the options exercised during the three months ended March 31, 2008, was approximately $51,000.

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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, 2008, 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		1,233		1.8		1,233		1.8
$1.75 - $2.55		406		5.3		373		5.1
$2.90 - $3.55		268		8.1		136		7.6
$3.62		1,140		2.8		720		2.7
$4.45 - $4.70		491		7.5		194		7.0
$5.50		100		0.1		100		0.1
$0.38 - $5.50		3,638		3.7		2,756		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. The Company has historically not experienced any significant environmental liability and is not aware of any potential material environmental issues or claims at March 31, 2008.

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, 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, 2008, letters of credit in the amount of $1.0 million were outstanding with the majority issued to the Michigan Supervisor of Wells.

Employment Agreement

Ronald E. Huff resigned as President, Chief Financial Officer and Director of AOG effective January 21, 2008. The Company had a 2-year Employment Agreement with Mr. Huff, providing for an annual salary of $200,000 per year and an award of a stock bonus in the amount of 500,000 shares of the Company’s common stock on January 1, 2009, so long as he remained employed by the Company through June 18, 2008, which requires the Company to record approximately $2.1 million in stock-based compensation expense over the contract period. The Company will pay Mr. Huff the compensation provided for in the employment agreement through June 18, 2008. This agreement has been modified to accelerate the award of Mr. Huff’s stock bonus in the amount of 500,000 shares of common stock from January 1, 2009, to June 18, 2008. As a result of the acceleration, $0.5 million was recorded as stock-based compensation during the three months ended March 31, 2008.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9. COMMITMENTS AND CONTINGENCIES (continued)

Retention Bonus

On September 19, 2007, the Company announced that it had retained Johnson Rice & Company, L.L.C. to assist the Board of Directors with investigating strategic alternatives for the Company. The Board of Directors of the Company has approved a retention bonus arrangement to encourage certain key officers and employees to remain with the Company through the completion of the Company’s review of potential strategic alternatives. The services of Johnson Rice & Company, L.L.C. were concluded on March 7, 2008. As of March 31, 2008, the Company had recorded $118,750 for retention bonuses in 2008. A final payment in the amount of $83,429 was made in April 2008 to those employees actively participating in the strategic alternative process.

Letter of Intent

Effective January 22, 2008, the Board of Directors named John E. McDevitt as President, Chief Operating Officer and Director. The Board of Directors also named Gilbert A. Smith as Vice President of Business Development effective as of February 1, 2008. The Company has signed a non-binding Letter of Intent to acquire Acadian Energy, LLC. Mr. McDevitt (through a controlled entity) and Mr. Smith are the only members of Acadian Energy, LLC (60% and 40% respectively). The proposed acquisition is valued at approximately $12.5 million and will include over 10,000 acres of New Albany Shale properties, 4 development wells, and approximately 7 bcf in proved reserves.

Oak Tree Joint Venture

In March 2006, the Company entered into a Joint Venture Agreement covering the acquisition and development of oil and gas leases in an Area of Mutual Interest (“AMI”) in Oklahoma. The Company’s joint venture partner is the manager of the leasing program and is designated as Operator for the AMI. A dispute has arisen with respect to operations under the Joint Venture Agreement. In late March 2008, the Company’s joint venture partner filed a complaint alleging breach of contract and unjust enrichment and is seeking a declaratory judgment to terminate the Joint Venture Agreement and to rescind the assignment of leases to the Company’s subsidiary, AOK Energy, LLC. Company management is of the opinion that the complaint is without merit and plans to vigorously contest the lawsuit.

General Legal Matters

The Company is currently involved in various disputes incidental to its business operations. 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

Effective January 22, 2008, Barbara E. Lawson was named Chief Financial Officer of the Company. Simple Financial Solutions, Inc., which is owned and operated by Ms. Lawson’s spouse, provides consulting services on a continuous basis to the Company. For the three months ended March 31, 2008, Simple Financial Solutions, Inc. billed the Company $10,865 for services rendered.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10.RELATED PARTY TRANSACTIONS (continued)

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, 2008, there is no production associated with this working interest and development costs were approximately $12.9 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 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 3 wells permitted for the Red Run project and one well was temporarily abandoned.

NOTE 11. SUBSEQUENT EVENT

Effective April 1, 2008, the Company entered into an agreement with Acadian Energy, LLC to provide oil and gas operating services on properties located in the State of Indiana. Mr. McDevitt (through a controlled entity) and Mr. Smith are the only members of Acadian Energy, LLC (60% and 40%, respectively). This agreement will remain effective through the acquisition closing date or December 31, 2008, whichever comes first. Under the terms of the agreement, the Company is not entitled to monetary consideration. Services will be performed to maintain the value of the properties prior to transfer of ownership from Acadian Energy, LLC to the Company.

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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 2007 Annual Report on Form 10-K/A, 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 a growing 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.

Highlights

For the three months ended March 31, 2008, we continued to shift our focus from acquisition of properties to an early stage developer of unconventional shale development projects. As of March 31, 2008, our leasehold acres were 1,301,186 (717,621 net) which represent a 1% increase over our December 31, 2007, net acres. These leasehold acres are included in the following plays: 310,470 (155,733 net) leasehold acres in the Michigan Antrim shale play, 15,837 (15,837 net) leasehold acres in the Indiana Antrim shale play, 849,900 (447,013 net) acres in the New Albany shale play, 36,802 (32,753 net) acres in the Woodford shale play, and 88,177 (66,285 net) acres in the other play areas.

With regard to our strategy to generate growth through drilling, we drilled or participated in 5 (2 net) wells for the three months ended March 31, 2008, with a 100% success rate. As of March 31, 2008, we had 649 (304 net) producing wells, 9 (4 net) wells awaiting hook-up, 41 (20 net) wells undergoing resource assessment, and 46 (31 net) wells temporarily abandoned. We also continued our strategy to have greater control over our projects by operating 257 (239 net) wells, thus, operating 35% of our gross wells and 67% of our net wells.

Of the 239 net wells we operate, 189 net wells are producing in the Antrim; 1 net well is awaiting hook-up in the Antrim; 13 net wells are undergoing resource assessment in the Antrim, 6 net wells are producing in the New Albany; 1 net well is undergoing resource assessment in the other plays; and 29 net wells are temporarily abandoned.

Oil and natural gas production for the three months ended March 31, 2008, was 824,489 mcfe, a 13% increase over the 732,430 mcfe produced in the three months ended March 31, 2007. For the three months ended March 31, 2008, production continues to be hampered by wells undergoing resource assessment and dewatering.

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Operating Statistics

The following table sets forth certain key operating statistics for the three months ended March 31, 2008 (the “Current Quarter”), and the three months ended March 31, 2007 (the “Prior Year Quarter”):

						Increase (Decrease)
	2008			2007		Amount			Percentage
Net wells drilled
Antrim shale		1			8		(7	)		(88	)%
New Albany shale (“NAS”)		-			-		-			-
Other		1			4		(3	)		(75	)%
Dry		-			4		(4	)		(100	)%
Total		2			16		(14	)		(88	)%
Total net wells
Antrim—producing		283			219		64			30	%
Antrim—awaiting hookup		2			42		(40	)		(96	)%
NAS—producing		7			1		6			600	%
NAS—awaiting hookup		-			7		(7	)		(100	)%
Other—producing		14			12		2			17	%
Other—awaiting hookup		2			5		(3	)		(60	)%
Total		308			286		22			8	%
Production
Natural gas (mcf)		779,483			690,435		89,048			13	%
Crude oil (bbls)		7,501			6,999		502			8	%
Natural gas equivalent (mcfe)		824,489			732,430		92,059			13	%
Average daily production
Natural gas (mcf)		8,566			7,672		989			13	%
Crude oil (bbls)		82			78		5			7	%
Natural gas equivalent (mcfe)		9,060			8,140		1,021			13	%
Average sales price (excluding all gains (losses) on derivatives)
Natural gas ($ per mcf)	$	8.29		$	6.91	$	1.38			20	%
Crude oil ($ per bbls)	$	83.19		$	53.87	$	29.32			55	%
Natural gas equivalent ($ per mcfe)	$	8.59		$	7.03	$	1.56			23	%
Average sales price (excluding unrealized losses from derivatives)
Natural gas ($ per mcf)	$	8.71		$	8.05	$	0.66			9	%
Crude oil ($ per bbls)	$	83.19		$	53.87	$	29.32			55	%
Natural gas equivalent ($ per mcfe)	$	8.99		$	8.10	$	0.89			11	%
Production revenue ($ in thousands)
Natural gas	$	6,455		$	4,768	$	1,687			36	%
Natural gas derivatives—realized gains		333			785		(452	)		(58	)%
Natural gas derivatives—unrealized losses		(969	)		-		(969	)		(100	)%
Crude oil		624			377		250			67	%
Total	$	6,443		$	5,930	$	513			9	%

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							Increase (Decrease)
	2008			2007			Amount			Percentage
Average expenses ($ per mcfe)
Production taxes	$	0.42		$	0.36		$	0.06			17	%
Post-production expenses	$	0.81		$	0.39		$	0.42			108	%
Lease operating expenses	$	2.58		$	2.24		$	0.34			16	%
General and administrative expense	$	2.43		$	3.09		$	(0.66	)		(22	)%
General and administrative expense excluding stock-based compensation	$	1.61		$	2.28		$	(0.67	)		(30	)%
Oil and natural gas depletion and amortization expenses	$	1.19		$	1.02		$	0.17			17	%
Other assets depreciation and amortization	$	0.44		$	0.78		$	(0.34	)		(44	)%
Interest expenses	$	1.78		$	1.34		$	0.44			33	%
Taxes	$	(0.09	)	$	(0.03	)	$	(0.06	)		200	%
Number of employees including Bach		66			90			(24	)		(27	)%

Results of Operations

Three Months Ended March 31, 2008, compared with Three Months Ended March 31, 2007

General. For the Current Quarter, we had a net loss of $1.2 million, or $(0.01) per diluted common share, on total revenues of $6.9 million. This compares to a net loss of $0.7 million, or $(0.01) per diluted common share, on total revenue of $6.3 million for the Prior Year Quarter. The $0.6 million increase in revenue represents our initial steps as an early stage developer of oil and natural gas properties.

Oil and Natural Gas Sales. During the Current Quarter, oil and natural gas sales were $6.4 million compared to $5.9 million in the Prior Year Quarter. We produced 824,489 mcfe at a weighted average price of $8.99 compared to 732,430 mcfe at a weighted average price of $8.10. This increase in production was due to new wells placed online. We had 304 net wells producing as of March 31, 2008, as compared to 232 net wells producing as of March 31, 2007. The weighted average price included $0.3 million or $0.41 per mcfe and $0.8 million or $1.08 per mcfe of realized gains from the gas derivative contract for Current Quarter and Prior Year Quarter, respectively. For the three months ended March 31, 2008, the weighted average price did not include $1.0 million or $1.18 per mcfe of unrealized losses from hedge ineffectiveness. For our cash flow hedges, the designated hedged risk is primarily the risk of changes in cash flows attributable to changes in the production of gas. Our natural gas contracts require us to produce certain volumes on a daily basis. During January 2008, we determined that we were unable to meet a portion of the volume required by one of our natural gas contracts. As a result, that portion was deemed to be ineffective.

Production from the Antrim shale play represented approximately 90% 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:

Play/Trend	Three Months Ended March 31, 2008				Three Months Ended March 31, 2007
	(mcfe)		Amount		(mcfe)		Amount
Antrim		740,841	$	5,482,339		675,353	$	5,455,370
New Albany		38,552		334,718		10,344		74,400
Other		45,096		625,501		46,733		399,806
Total		824,489	$	6,442,558		732,430	$	5,929,576

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Production from the Prior Year Quarter compared to the Current Quarter increased marginally by 13%. Lower than expected production resulted from Warner Plant outages and heavy snowfall causing delays in response to freezing complications associated with compressors, booster stations, and water lines.

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. The increase is attributed to the recovery of additional post-production costs which were previously being absorbed as operating expenses by the Company.

Field Service and Sales. Field service and sales were $0.1 million in the Current Quarter compared to $0.2 million in the Prior Year Quarter. The majority of Bach’s services are performed for the Company. The decrease in the Current Quarter was attributable to the reduction in services performed for unrelated third party customers.

Interest and Other Revenues. Interest and other revenues were $102,687 in the Current Quarter compared to $13,513 in the Prior Year Quarter. This increase is primarily attributed to realizing a portion of the gain resulting from a sale-leaseback transaction executed during December 2007.

Production Taxes. Production taxes were $339,314 in the Current Quarter compared to $263,098 in the Prior Year Quarter. This increase is attributed to production growth and the state mix of production. On a unit of production basis, production taxes were $0.42 per mcfe in the Current Quarter compared to $0.36 per mcfe in the Prior Year Quarter representing an increase of production taxes by 31% in the Current Quarter from 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 $2.8 million in the Current Quarter compared to $1.9 million in the Prior Year Quarter. On a per unit of production basis, production and lease operating expenses were $3.39 per mcfe in the Current Quarter compared to $2.63 per mcfe in the Prior Year Quarter. The increase in the Current Quarter was primarily attributable to our expanding operations which increased energy costs, pumping costs, repair, and maintenance associated with meters, compressors, pumps, production personnel, and compressor sale-leaseback expenses.

On a component basis, post-production expenses were $0.7 million, or $0.81 per mcfe, in the Current Quarter compared to $0.3 million, or $0.39 per mcfe, in the Prior Year Quarter, and lease operating expenses were $2.1 million, or $2.58 per mcfe, in the Current Quarter compared to $1.6 million, or $2.24 per mcfe, in the Prior Year Quarter. The unit of production increases are attributable to an increase of post-production expenses by 134% and an increase of lease operating expenses by 32% compared to the Prior Year Quarter due to our expanding operations which increased energy costs, pumping costs, repair, and maintenance associated with meters, compressors, pumps, production personnel, and compressor sale-leaseback expenses.

Production and lease operating expenses for operated properties were $3.65 per mcfe in the Current Quarter while non-operated production and lease operating expenses were $2.89 per mcfe in the Current Quarter. Our operated Arrowhead, Blue Chip, and Gaylord Fishing Club projects continue to negatively impact our operating cost controls and efficiency due to dewatering. Production and lease operating expenses for operated properties excluding Arrowhead, Blue Chip, and Gaylord Fishing Club projects were $3.47 per mcfe in the Current Quarter.

Pipeline and Processing Operating Expenses. Pipeline and processing operating expenses were $89,223 in the Current Quarter compared to $113,420 in the Prior Year Quarter. This decrease was the result of recovering additional post-production costs which was previously being absorbed as operating expenses by the Company.

Field Services Expenses. Field services expenses were $0.1 million in the Current Quarter compared to $0.2 million in the Prior Year Quarter which are attributable to the reduction in services performed by Bach for 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 expense. General and administrative expenses in the Current Quarter decreased by $0.3 million, or 12%, from the Prior Year Quarter. This decrease was primarily the result of a reduction in accounting and other consulting services.

Excluding the acceleration of Ronald E. Huff’s stock bonus award in the amount of $0.5 million, payroll and related costs decreased by $0.5 million to $1.0 million in the Current Quarter due to lower employee payroll and stock-based compensation of $0.6 million. This amount was offset by a retention bonus in the amount of $0.1 million.

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 $0.5 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 from the Prior Year Quarter.

Oil and Natural Gas Depletion, Depreciation and Amortization (“DD&A”). DD&A of oil and natural gas properties was $1.0 million and $0.7 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 increase is the result of $6.5 million being added to proved properties in the full cost pool and production growth. The average DD&A cost per mcfe also increased to $1.19 in the Current Quarter compared to $1.02 in the Prior Year Quarter due to the additional proved properties added to the full cost pool.

Other Assets Depreciation and Amortization (“D&A”). D&A of other assets was $0.4 million in the Current Quarter compared to $0.6 million in the Prior Year Quarter. This decrease was primarily the result of the complete amortization of certain intangible assets during January 2008 associated with the Cadence merger.

Interest Expense. Interest expense was $1.5 million in the Current Quarter compared to $1.0 million in the Prior Year Quarter. This increase is due to the higher utilization of debt to continue our growth strategy of acquiring and developing operating interests primarily in the New Albany shale.

Taxes, Other.Other taxes primarily include state franchise taxes and personal property 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 refund was $71,292 in the Current Quarter compared to a refund of $25,182 in the Prior Year Quarter. This increase primarily represents a 2006 State of Louisiana income tax refund received during 2008.

Liquidity and Capital Resources

Currently, we are able to maintain our existing operations through the existing cash balances and internally generated cash flows from sales of oil and natural gas production. However, we have determined that our existing capital structure is not adequate to fund our planned growth. We believe the best way to pursue our growth strategy is with project financing for our emerging plays in the New Albany shale and the Woodford shale. At this time, we are in the process of negotiating several term sheets with certain recognized energy lenders offering mezzanine/project equity financing for at least two areas in our emerging plays. Our goal is to establish separate financing entities for each emerging play while ensuring the financing structure is non-recourse to our parent entity. Our current credit facilities are reserve-based lending which is appropriate for a mature development play like our Antrim shale. We are currently in discussion to improve our existing credit facilities. As of the date of this filing, no project financing or amendments to our existing credit facilities have been procured. There can be no assurance that we will be successful in procuring the financing and amendments we are seeking. Future cash flows are subject to a number of variables, including the level of production, natural gas prices and successful drilling efforts. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures.

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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 syndicate. 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 700 basis points with a step-down of 25 basis points once our ratio of total indebtedness to earnings before interest, taxes, depreciation, depletion, amortization, and other noncash charges is lower than or equal to a ratio of 4.0 to 1.0 on a trailing four quarters basis. We have the ability to prepay the second lien term loan during the first year at a price equal to 103% of par, during the second year at a price equal to 102% of par, and thereafter at a price equal to 100% of par.

The second lien term loan contains, among other things, a number of financial and non-financial covenants relating to restricted payments (as defined), loans or advances to others, additional indebtedness, incurrence of liens, geographic limitations on operations to the United States, and maintenance of certain financial and operating ratios, including (i) maintenance of a maximum of indebtedness to earnings before interest, income taxes, depreciation, depletion and amortization and non-cash expenses, and (ii) maintenance of minimum reserve value to indebtedness. Any event of default under the senior secured credit facility that accelerates the maturity of any indebtedness thereunder is also an event of default under the second lien term loan.

In both the second lien term loan and senior secured credit facility, we agreed to an affirmative covenant regarding production exit rates. The production exit target is 12.0 MMcfe per day as December 31, 2007, and as of the last day of each quarter thereafter. In addition, we were required to purchase financial hedges at prices and aggregate notional volumes satisfactory to BNP, as administrative agent, which requirement has been satisfied.

On April 29, 2008 management became aware that we failed to achieve daily production of 12.0 mmcfe per day and exceeded the maximum total debt to EBITDAX ratio as of March 31, 2008. According to the second lien term loan agreement we have until May 29, 2008 (30 days) to remediate the covenant failures in order to avoid an event of default. Management has developed a plan to remediate the covenant deficiencies which includes among other items, production enhancements, a plan to reduce general, administrative, and production expenses and the possible sale of certain non-core assets. In case we are unable to successfully remediate the covenant failures, we have also requested BNP to waive our failure to observe or perform the daily production of 12.0 mmcfe per day and meet the total debt to EBITDAX ratio requirement as of March 31, 2008. There are no assurances we will be able to successfully remediate the covenant failures by May 29, 2008, or that we will receive a waiver from BNP. If an event of default occurs, BNP has the right to demand repayment of the second lien term loan obligation which would adversely affect our liquidity in a material manner.

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 current authorized borrowing base of $50 million to $70 million. The amount of the borrowing base is 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. The required semiannual reserve report may result in an increase or decrease in credit availability. 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 2.0% 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, 2008, interest on the borrowings had a weighted average interest rate of 4.66%. 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.

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The senior secured credit facility contains, among other things, a number of financial and non-financial covenants relating to restricted payments (as defined), loans or advances to others, additional indebtedness, incurrence of liens, geographic limitations on operations to the United States, and maintenance of certain financial and operating ratios, including (i) maintenance of a minimum current ratio, and (ii) maintenance of a minimum interest coverage ratio. Any event of default under the second lien term loan that accelerates the maturity of any indebtedness thereunder is also an event of default under the senior secured credit facility.

On April 29, 2008 management became aware that we failed to achieve daily production of 12.0 mmcfe per day and meet the required interest coverage ratio as of March 31, 2008. According to the senior secured credit facility agreement we have until May 29, 2008 (30 days) to remediate the covenant failures in order to avoid an event of default. Management has developed a plan to remediate the covenant deficiencies which includes among other items, production enhancements, a plan to reduce general, administrative, and production expenses and the possible sale of certain non-core assets. In case we are unable to successfully remediate the covenant failures, we have also requested BNP to waive our failure to observe or perform the daily production of 12.0 mmcfe per day and meet the interest coverage ratio requirement as of March 31, 2008. There are no assurances we will be able to successfully remediate the covenant failures by May 29, 2008, or that we will receive a waiver from BNP. If an event of default occurs, BNP has the right to demand repayment of the senior secured credit facility obligation which would adversely affect our liquidity in a material manner.

Our total capitalization was as follows:

	As of March 31, 2008		As of December 31, 2007
Obligations under capital lease	$	6,675	$	7,784
Notes payable		245,417		219,478
Mortgage payables		3,056,926		3,082,196
Senior secured credit facility		65,000,000		56,000,000
Second lien term loan		50,000,000		50,000,000
Total debt		118,309,018		109,309,458
Minority interest in net assets of subsidiaries		127,766		112,661
Shareholders’ equity		120,515,667		132,142,989
Total capitalization	$	238,952,451	$	241,565,108

Cash Flows from Operating Activities

Cash provided by operating activities increased 88% to $3.1 million in the Current Quarter, compared to $1.6 million in the Prior Year Quarter. This $1.5 million increase in net cash provided by operating activities was due to an increase in production, as well as a reduction in outstanding payables. See “Results of Operations” for discussion of changes in revenues and expenses. Non-cash charges such as depreciation, depletion and amortization and stock-based compensation remained relatively flat except for the non-cash charge of unrealized losses on ineffectiveness of commodity derivative. Changes in current operating assets and liabilities increased cash flow from operations by $1.1 million.

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Cash Flows Used in Investing Activities

Cash flows used in investing activities was $7.4 million in the Current Quarter compared to $18.6 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,
	2008			2007
Acquisitions of leasehold
Michigan Antrim shale	$	335,986		$	629,444
Indiana Antrim shale		3,018			45,866
New Albany shale		417,673			840,626
Woodford shale		319,361			1,108,200
Other		21,136			33,109
Drilling and development of oil and natural gas properties
Michigan Antrim shale		1,115,748	(a)		10,462,221
Indiana Antrim shale		9,874			210,141
New Albany shale		930,868			620,049
Other		644,434			113,240
Infrastructure properties
Michigan Antrim shale		7,536			3,750,934
New Albany shale		2,188,704			373,443
Other		-			21,308
Capitalized interest and general and administrative costs on exploration, development and leasehold		1,418,420			1,264,182
Acquisitions/additions for pipeline, property, and equipment		16,947			144,456
Other, net		3,491			37,412
Subtotal of capital expenditures		7,433,196			19,654,631
Sale of oil and natural gas properties		(60,000	)		(1,025,000	)
Sales of other investment and other		(9,334	)		-
Subtotal of capital divestitures		(69,334	)		(1,025,000	)
Total	$	7,363,862		$	18,629,631

(a) Drilling and development costs in the amount of $1,037,169 relate to non-operated properties.

Cash Flows Provided by Financing Activities

Cash flows provided by financing activities were $9.2 million in the Current Quarter compared to $17.4 million in the Prior Year Quarter. Cash flows provided in the Current Quarter included: (1) $9.0 million of senior secured borrowing; and (2) $0.4 million of proceeds received from exercise of common stock options and warrants. Cash flows used in the Current Quarter included: (1) paydown of $43,867 in mortgage and notes payable obligations; (2) payment of $29,142 in financing fees; and (3) payment of $0.1 million on other liabilities.

Cash flows provided by financing activities in the Prior Year Quarter included: (1) $18.0 million of senior secured credit borrowing; and (2) $0.1 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) net pay-down of $0.5 million within short-term bank borrowings; (2) pay-down of $0.1 million within mortgage obligations; and (3) payments of $25,000 in financing fees.

Recent Accounting Pronouncements

Reference is made to Note 3 and Note 4 to the Financial Statements included elsewhere in this filing for a description of certain recently issued accounting pronouncements. We do not expect any of such 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/A for the year ended December 31, 2007.

Off Balance Sheet Arrangements

We have no special purpose entities, financing partnerships, guarantees, or off-balance sheet arrangements other than the $1.0 million of outstanding letter of credits discussed in Note 9 “Commitments and Contingencies.”

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 will periodically enter into various derivative instruments with a major financial institution. The purpose of the derivative instrument is 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 reduces our exposure on the hedged production volumes to decreases in commodity prices and limits the benefit we might otherwise receive from any increases in commodity prices on the hedged production volumes. The following natural gas contracts were in place as of March 31, 2008 (fair value $ in thousands):

Period	Type of Contract		Natural Gas Volume per Day		Price per mmbtu		Fair Value Asset (Liability) ($ in thousands)
April 2007—December 2008		Swap		5,000 mmbtu	$	9.00		(2,037	)
April 2007—December 2008		Collar		2,000 mmbtu	$	7.55/$ 9.00		(942	)
January 2008—December 2008		Swap		2,000 mmbtu	$	8.41		(1,140	)
January 2009—December 2009		Swap		7,000 mmbtu	$	8.72		(2,991	)
January 2010—March 2011		Swap		7,000 mmbtu	$	8.68		(1,860	)
April 2011—September 2011		Swap		7,000 mmbtu	$	7.62		(1,156	)
Total estimated fair value								(10,126	)

For our cash flow hedges, the designated hedged risk is primarily the risk of changes in cash flows attributable to changes in the production of gas. Our natural gas contracts require us to produce certain volumes on a daily basis. During January 2008, a portion of the swap contract for the period January 2008 through December 2008 was deemed ineffective. As a result, ineffectiveness amounting to $1.0 million for the three months ended March 31, 2008, was included as a reduction to oil and natural gas sales.

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. In August 2007, we entered into a 3-year interest rate swap agreement in the notional amount of $50 million with BNP to hedge our exposure to the floating interest rate on the $50 million second lien term loan. The swap converted the debt’s floating three month LIBOR base to 4.86% fixed base. This swap on $50 million will yield an effective interest rate of 11.86% for the period from August 23, 2007 through August 23, 2010, on the second lien term loan. Fair value liability of the interest rate swap agreement at March 31, 2008, amounted to $2.7 million.

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The following table sets forth our principal financing obligation and the related interest rates as of March 31, 2008:

	Expected  Maturity		Average Interest Rate as of  March 31, 2008			Principal Outstanding
Obligations under capital lease		01/10/09		8.25	%	$	6,675
Notes payable		08/01/07-04/25/11		6.50% - 7.50	%		245,417
Mortgage payable		10/15/09		Fixed at 6.00	%		366,237
Mortgage payable		11/01/08		Fixed at 5.95	%		2,690,689
Second lien term loan		02/01/11		Hedged at 11.86	%		50,000,000
Senior secured credit facility		01/31/10		Variable - 7.125	%		65,000,000
Total debt						$	118,309,018

While our senior secured facility exposes us to the risk of rising interest rates, management does not believe that the potential exposure is material to our overall financial position or results of operations. Based on current borrowing levels, a 1.0% increase or decrease in current market interest rates would have the effect of causing $0.8 million additional charge or reduction to our statement of operations.

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.

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, 2008, 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.

Our management, including our CEO 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

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.

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PART II

ITEM 1. LEGAL PROCEEDINGS

Refer to Note 9 on page 21 of 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/A for the year ended December 31, 2007. 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 unregisterd equity securities nor did we repurchase any of our outstanding equity securities during the quarter ended March 31, 2008.

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(4)	Promissory Note from Aurora Oil & Gas Corporation to Northwestern Bank dated February 14, 2008.
14.1(4)	Code of Conduct and Ethics (updated 2/1/08).
16.1(4)	Letter concerning change of certifying accountant from Rachlin Cohen & Holtz, LLP
*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.

(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.

(4) Filed as an exhibit to our Form 10-K for the fiscal year ended December 31, 2007, filed with the SEC on March 7, 2008, 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 9, 2008	By:	/s/ William W. Deneau
	Name:	William W. Deneau
	Title:	Chief Executive Officer
Date: May 9, 2008	By:	/s/ Barbara E. Lawson
	Name:	Barbara E. Lawson
	Title:	Chief Financial Officer

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