Aurora Oil & Gas 10-Q 2008 Q2 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 JUNE 30, 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 August 4, 2008, was 103,382,788.

FORM 10-Q

INDEX

PART I	FINANCIAL INFORMATION	1
Item 1.	Condensed Consolidated Financial Statements	2
Condensed Consolidated Balance Sheets as of June 30, 2008 (Unaudited), and December 31, 2007 (Audited)		2
Unaudited Statements of Operations for the Three and Six Months Ended June 30, 2008, and 2007		4
Unaudited Statements of Shareholders’ Equity for the Six Months Ended June 30, 2008, and 2007		5
Unaudited Statements of Cash Flows for the Six Months Ended June 30, 2008, and 2007		6
Notes to Unaudited Condensed Consolidated Financial Statements		7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 4.	Controls and Procedures	40
PART II	OTHER INFORMATION	42
Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 3.	Defaults Upon Senior Securities	42
Item 4.	Submission of Matters to a Vote of Security Holders	42
Item 5.	Other Information	42
Item 6.	Exhibits	42
Signatures		45

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

	June 30, 2008 (Unaudited)			December 31, 2007 (Audited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	12,267,973		$	2,425,678
Accounts receivable
Oil and natural gas sales		4,324,564			5,036,416
Joint interest owners		673,075			851,638
Prepaid expenses and other current assets		868,029			765,730
Short-term derivative instruments		-			2,247,990
Total current assets		18,133,641			11,327,452
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, using full cost accounting:
Proved properties		174,779,049			167,282,245
Unproved properties		56,358,220			56,937,683
Less: accumulated depletion and amortization		(16,312,856	)		(14,401,584	)
Total oil and natural gas properties, net		214,824,413			209,818,344
Other property and equipment:
Pipelines, processing facilities, and compression		6,484,410			6,469,336
Other property and equipment		5,516,706			5,450,452
Less: accumulated depreciation		(2,003,613	)		(1,554,189	)
Total other property and equipment, net		9,997,503			10,365,599
Total property and equipment, net		224,821,916			220,183,943
OTHER ASSETS:
Goodwill		19,373,264			19,373,264
Intangibles (net of accumulated amortization of $4,634,166 and $4,497,920, respectively)		320,834			457,080
Other investments		217,096			733,836
Debt issuance costs (net of accumulated amortization of $606,658 and $360,972, respectively)		1,730,879			1,661,603
Other		1,307,786			934,490
Total other assets		22,949,859			23,160,273
TOTAL ASSETS	$	265,905,416		$	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)

	June 30, 2008 (Unaudited)			December 31, 2007 (Audited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	6,519,556		$	6,490,981
Accrued exploration, development, and leasehold costs		268,345			1,341,917
Current portion of obligations under capital leases		4,984			6,288
Current portion of note payable		89,500			76,416
Current portion of mortgage payable		119,468			112,326
Senior secured credit facility		69,800,000			-
Second lien term loan		50,000,000			-
Drilling advances		118,248			168,356
Short-term derivative instruments		13,259,368			384,706
Total current liabilities		140,179,469			8,580,990
LONG-TERM LIABILITIES:
Obligations under capital leases, net of current portion		-			1,496
Asset retirement obligation		1,578,080			1,494,745
Notes payable		134,558			143,062
Mortgage payable		2,909,120			2,969,870
Senior secured credit facility		-			56,000,000
Second lien term loan		-			50,000,000
Long-term derivative instruments		16,559,608			2,248,326
Other long-term liabilities		720,539			977,529
Total long-term liabilities		21,901,905			113,835,028
Total liabilities		162,081,374			122,416,018
Minority interest in net assets of subsidiaries		143,536			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 103,282,788 and 101,769,456 shares, respectively		1,032,828			1,017,695
Additional paid-in capital		142,265,351			140,541,460
Accumulated other comprehensive loss		(28,702,254	)		(385,043	)
Accumulated deficit		(10,915,419	)		(9,031,123	)
Total shareholders’ equity		103,680,506			132,142,989
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	265,905,416		$	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 June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
REVENUES:
Oil and natural gas sales	$	6,795,093		$	6,602,429		$	13,237,651		$	12,532,005
Pipeline transportation and marketing		333,182			157,664			557,353			286,932
Field service and sales		590,509			60,084			714,068			249,602
Interest and other		141,621			461,245			244,308			474,758
Total revenues		7,860,405			7,281,422			14,753,380			13,543,297
EXPENSES:
Production taxes		402,763			303,871			742,077			566,969
Production and lease operating expense		2,758,478			2,200,807			5,546,202			4,126,700
Pipeline and processing operating expense		176,218			64,382			265,441			177,802
Field services expense		458,550			45,824			577,705			200,096
General and administrative expense		1,802,347			1,973,358			3,799,408			4,233,701
Oil and natural gas depletion and amortization		928,233			776,595			1,908,141			1,523,460
Other assets depreciation and amortization		230,321			573,498			586,094			1,142,104
Interest expense		1,763,293			1,068,871			3,225,705			2,050,403
Taxes (refunds), other		26,046			25,129			(45,246	)		(53	)
Total expenses		8,546,249			7,032,335			16,605,527			14,021,182
INCOME (LOSS) BEFORE MINORITY INTEREST		(685,844	)		249,087			(1,852,147	)		(477,885	)
MINORITY INTEREST IN INCOME OF SUBSIDIARIES		(17,044	)		(19,610	)		(32,149	)		(32,957	)
NET INCOME (LOSS)	$	(702,888	)	$	229,477		$	(1,884,296	)	$	(510,842	)
NET INCOME (LOSS) PER COMMON SHARE
—BASIC	$	(0.01	)	$	0.00		$	(0.02	)	$	(0.01	)
—DILUTED				$	0.00
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
—BASIC		103,683,887			101,650,665			104,353,520			101,602,875
—DILUTED					103,735,539

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)

	Six Months Ended June 30,
	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		1,163,332		11,633			173,332			1,733
Issuance of stock to officers and directors in lieu of compensation		350,000		3,500			-			-
Adjustment to stock ledger		-		-			(75,000	)		(750	)
Balance, ending		103,282,788		1,032,828			101,589,456			1,015,895
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning				140,541,460						138,105,626
Cashless exercise of stock options and warrants				-						(782	)
Costs of equity offerings				-						(10,096	)
Stock-based compensation				933,225						1,335,523
Exercise of stock options and warrants				674,616						63,266
Issuance of stock to officers and directors in lieu of compensation				116,050						-
Adjustment to stock ledger				-						(146,250	)
Balance, ending				142,265,351						139,347,287
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Balance, beginning				(385,043	)					5,220,633
Changes in fair value of derivative instruments				(30,214,422	)					(1,099,949	)
Recognition of gain on derivative instruments				1,897,211						(1,358,250	)
Balance, ending				(28,702,254	)					2,762,434
ACCUMULATED DEFICIT:
Balance, beginning				(9,031,123	)					(4,609,290	)
Net loss				(1,884,296	)					(510,842	)
Balance, ending				(10,915,419	)					(5,120,132	)
TOTAL SHAREHOLDERS’ EQUITY			$	103,680,506					$	138,005,484

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)

	Six Months Ended June 30,
		2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,884,296	)	$	(510,842	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization		2,494,235			2,665,564
Amortization of debt issuance costs		283,107			446,790
Accretion of asset retirement obligation		55,167			31,112
Deferred gain on sale of natural gas compression equipment		(66,414	)		-
Stock-based compensation		1,097,375			1,201,756
Equity loss of other investments and other		30			(67,418	)
Realized gain on sale of other investments		-			(418,147	)
Unrealized loss on ineffective commodity derivative		1,116,723			-
Minority interest income of subsidiaries		32,149			32,957
Changes in operating assets and liabilities:
Accounts receivable - oil and natural gas sales		711,852			(900,656	)
Accounts receivable - joint interest owners		172,375			2,150,169
Notes receivable		-			221,788
Drilling advance - liabilities		(50,108	)		546,508
Prepaid expenses and other assets		(87,825	)		(267,838	)
Accounts payable and accrued liabilities		1,482,482			280,032
Net cash provided by operating activities		5,356,852			5,411,775
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and natural gas properties		(7,620,990	)		(28,725,363	)
Leasehold expenditures, net		(1,478,336	)		(5,614,924	)
Sale of oil and natural gas properties		143,542			1,024,663
Sales and leaseback of gas compression equipment		-			1,202,000
Acquisitions/additions for pipeline, property, and equipment		(61,481	)		(356,288	)
Additions in other investments		(12,206	)		(4,759	)
Sales of other investments		9,334			457,762
Net cash used in investing activities		(9,020,137	)		(32,016,909	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term bank borrowings		100,000			5,335,000
Short-term bank payments		(100,000	)		(4,459,173	)
Advances on senior secured credit facility		13,800,000			26,000,000
Payments on senior secured credit facility		-			(1,000,000	)
Payments on mortgage obligations		(53,608	)		(46,556	)
Payments on notes payable		(39,956	)		(110,559	)
Payments of financing fees on credit facilities		(339,963	)		(152,826	)
Payments on other long-term liabilities		(68,585	)		-
Capital contributions from minority interest members		-			24,837
Distributions to minority interest members		(21,230	)		(49,839	)
Proceeds from exercise of options and warrants		686,249			64,999
Other		(457,327	)		(15,647	)
Net cash provided by financing activities		13,505,580			25,590,236
Net increase (decrease) in cash and cash equivalents		9,842,295			(1,014,898	)
Cash and cash equivalents, beginning of the period		2,425,678			1,735,396
Cash and cash equivalents, end of the period	$	12,267,973		$	720,498
NONCASH FINANCING AND INVESTING ACTIVITIES:
Oil and natural gas properties asset retirement obligation	$	28,168		$	(370,842	)
Accrued exploration and development costs on oil and natural gas properties		216,568			2,945,868
Accrued leasehold costs		51,777			348,345
Oil and natural gas properties capitalized stock-based compensation		45,850			133,767
Conversion of accounts receivable to notes receivable		6,188			26,349
Vehicle purchase through financing		44,536			94,407
Common stock received in connection with the sale of mining claims		-			56,885
SUPPLEMENTAL INFORMATION OF INTEREST AND INCOME TAXES PAID :
Interest, net of amount capitalized of $2,180,405 and $1,857,689, respectively	$	2,702,119		$	1,352,151
Income taxes		4,121			107,700

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

6

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.

7

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.

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 and six months ended June 30, 2007. For the three months ended June 30, 2007, revisions of estimated liabilities included increases due to removal of equipment salvage valve totaling $0.2 million. Revisions for the six months ended June 30, 2008, are not considered material and primarily relate to changes in working interest on certain properties. No revisions of estimated liabilities were made for the three months ended June 30, 2008.

8

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

The following table sets forth a reconciliation of the Company’s ARO liability for the periods indicated ($ in thousands):

Three Months Ended June 30,	2008			2007
Beginning balance	$	1,537		$	767
Liabilities incurred		14			57
Liabilities settled		(1	)		-
Accretion expense		28			12
Revisions of estimated liabilities		-			154
Ending balance	$	1,578		$	990

Six Months Ended June 30,	2008			2007
Beginning balance	$	1,495		$	1,332
Liabilities incurred		28			124
Liabilities settled		(4	)		(34	)
Accretion expense		56			31
Revisions of estimated liabilities		3			(463	)
Ending balance	$	1,578		$	990

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 June 30, 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	$	(4,313	)
April 2007—December 2008		Collar		2,000 mmbtu	$	7.55/$ 9.00		(1,734	)
January 2008 - December 2008		Swap		2,000 mmbtu	$	8.41		(1,941	)
January 2009—December 2009		Swap		7,000 mmbtu	$	8.72		(8,719	)
January 2010—March 2011		Swap		7,000 mmbtu	$	8.68		(8,383	)
April 2011 - September 2011		Swap		7,000 mmbtu	$	7.62		(3,342	)
Total Estimated Fair Value							$	(28,432	)

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)

For the six months ended June 30, 2008, the Company has recognized in Comprehensive Income (Loss) changes in fair value of $(30.0) 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 table sets forth components of oil and natural gas sales for the periods indicated ($ in thousands):

For the Three Months Ended June 30,	2008			2007
Oil and natural gas sales	$	8,849		$	6,029
Realized (losses) gains on natural gas derivatives		(1,578	)		573
Realized losses on ineffectiveness of cash flow hedges		(328	)		-
Unrealized losses on ineffectiveness of cash flow hedges		(148	)		-
Total	$	6,795		$	6,602

For the Six Months Ended June 30,	2008			2007
Oil and natural gas sales	$	15,928		$	11,174
Realized (losses) gains on natural gas derivatives		(1,264	)		1,358
Realized losses on ineffectiveness of cash flow hedges		(309	)		-
Unrealized losses on ineffectiveness of cash flow hedges		(1,117	)		-
Total	$	13,238		$	12,532

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. However, based on the Term Loan Forbearance and Amendment Agreement more fully described in Note 6 “Debt,” LIBOR rate had a floor of 4.0% established as of June 21, 2008.

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 six months ended June 30, 2008, the Company has recognized in Comprehensive Income (Loss) changes in fair value of $(0.5) million on the interest rate swap. See “Comprehensive Income (Loss)” found in this note section. For the six months ended June 30, 2008, the Company recognized $0.3 million in interest expense related to the hedge activity which is recorded as an adjustment to interest expense. For the three months ended June 30, 2008, the Company recognized $0.2 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 June 30, 2008, amounted to $1.5 million.

Financial Instruments

The Company has financial instruments whereby the fair value of the financial instruments could be different than that recorded on a historical basis in the accompanying balance sheets. The Company’s financial instruments consist of cash, accounts receivable, loans receivable, accounts payable, accrued expenses, and debt. The carrying amounts of the Company’s financial instruments approximate their fair values as of June 30, 2008 due to their short-term nature.

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 periods indicated ($ in thousands):

For the Three Months Ended June 30,	2008		2007
General and administrative expenses	$	415	$	608
Production and lease operating expenses		8		-
Pipeline and processing operating expenses		1		-
Oil and natural gas properties		25		66
Total	$	449	$	674

For the Six Months Ended June 30,	2008		2007
General and administrative expenses	$	1,088	$	1,202
Production and lease operating expenses		8		-
Pipeline and processing operating expenses		1		-
Oil and natural gas properties		46		133
Total	$	1,143	$	1,335

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

During May 2008, the Board of Directors granted a special common stock award under the 2006 Stock Incentive Plan to each of the five non-employee directors totaling 250,000 shares, or 50,000 each, for past services rendered. In addition, two of the non-employee directors were granted a special common stock award of an additional 15,000 shares each for services rendered on special projects. All shares vested immediately, but have not been issued as of June 30, 2008. The shares were recorded at $0.75 per share (closing price on the grant date) resulting in total stock based compensation expense in the amount of $0.2 million included in the above table as general and administrative expenses for the three and six months ended June 30, 2008.

The following table provides the unrecognized compensation expense related to unvested stock options as of June 30, 2008. The expense is expected to be recognized over the following 3-year period ($ in thousands).

Period to be Recognized	2008		2009		2010		2011		Total Unrecognized Compensation Expense
1st Quarter	$	-	$	252	$	99	$	39
2nd Quarter		-		193		78		26
3rd Quarter		345		106		40		-
4th Quarter		324		102		40		-
Total	$	669	$	653	$	257	$	65	$	1,644

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 periods indicated ($ in thousands):

Three Months Ended June 30,	2008			2007
Net (loss) income	$	(702	)	$	229
Other comprehensive loss:
Change in fair value of natural gas derivative instruments		(20,064	)		1,928
Change in fair value of interest rate derivative instruments		1,103			-
Recognition of losses (gains) on derivative instruments		2,157			(573	)
Comprehensive (loss) income	$	(17,506	)	$	1,584

Six Months Ended June 30,	2008			2007
Net loss	$	(1,884	)	$	(511	)
Other comprehensive loss:
Change in fair value of natural gas derivative instruments		(29,762	)		(1,100	)
Change in fair value of interest rate derivative instruments		(452	)		-
Recognition of losses (gains) on derivative instruments		1,897			(1,358	)
Comprehensive loss	$	(30,201	)	$	(2,969	)

12

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)

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. For the three months ended June 30, 2008, and 2007, respectively, options to purchase 7,633,280 and 2,395,780 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. For the six months ended June 30, 2008, and 2007, respectively, options to purchase 4,233,280 and 2,375,780 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 May 2008, the FASB issued SFAS No. 162 “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. This statement shall be effective 60 days following the Securities Exchange and Commission’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” We do not expect its adoption will have a material impact on our consolidated financial statements.

In April 2008, the FASB issued FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Assets.” FSP No. FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The intent of the position is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R, and other U.S. generally accepted accounting principles. The provisions of FSP No. FAS 142-3 are effective for fiscal years beginning after December 15, 2008. We are currently evaluating the impact, if any, that the adoption of FSP No. FAS 142-3 could have on our consolidated financial statements or results of operations.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS 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.

13

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

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 June 30, 2008 ($ in thousands):

			Fair Value Measurements, Using
	Total Carrying Value		Quoted prices in active markets (Level 1)		Significant other unobservable inputs (Level 2)		Significant unobservable inputs (Level 3)
Derivative liabilities—cash flow hedges	$	28,432		-	$	28,432		-
Derivative liabilities—interest rate swap		1,507		-		1,507		-

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.

14

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5. ACQUISITIONS AND DISPOSITIONS

2008 – Crystal 36 Prospect

In May 2008, the Company received proceeds of $4,220 in connection with the sale of a 20% working interest in the Crystal 36 prospect. The prospect is located in Benzie County, Michigan and covers approximately 4,220 net acres.

2008 – Geopetra

In April 2008, the Company sold a 3.75% interest in the Geopetra prospect for $79,322. The interest covers approximately 285 net acres in St. Martin and Iberville Counties, Louisiana.

2008 – Goodwell and Smith Prospect

In January 2008, the Company received proceeds of $60,000 in connection with the sale of all its interest in the Goodwell and Smith prospect. The prospect is located in Newaygo County, Michigan and covers approximately 960 acres.

2007 – Mining Claims

On May 15, 2007, the Company sold certain mining claims and mineral leases to U.S. Silver-Idaho, Inc. for $400,000 in cash and 50,000 shares of common stock in U.S. Silver Corporation. This non-core property sale consisted of 14 unpatented and 27 patented mining claims as well as 5 mineral leases located in Idaho. A $418,000 gain was recognized in other income since these non-core properties were being recognized as an investment.

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.

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 and six months ended June 30, 2007, was $6,015 and $6,882, respectively.

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.

15

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6.DEBT (continued)

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 (5.00% at June 30, 2008, and 8.25% at June 30, 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. No interest expense was incurred for the three months ended June 30, 2008. Interest expense for the three months ended June 30, 2007, was $180. Interest expense for the six months ended June 30, 2008, and 2007, was $1,523 and $1,343, 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 June 30, 2008, the principal amount outstanding was $0.4 million. Interest expense for the three months ended June 30, 2008, and 2007, was $5,478 and $5,414, respectively. Interest expense for the six months ended June 30, 2008, and 2007, was $11,033 and $11,344, 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 June 30, 2008, the total principal amount outstanding was $0.2 million. Total interest expense for the three months ended June 30, 2008, and 2007, was $4,287 and $3,290, respectively. Total interest expense for the six months ended June 30, 2008, and 2007, was $8,161 and $6,211, 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 and six months ended June 30, 2007, was $85 and $232, respectively.

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 June 30, 2008, the principal amount outstanding was $2.7 million. Interest expense for the three months ended June 30, 2008, and 2007, was $40,219 and $33,089, respectively. Interest expense for the six months ended June 30, 2008, and 2007, was $82,625 and $69,336, 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 and six months ended June 30, 2007, was $1,091 and $2,273, respectively.

16

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6.      DEBT (continued)

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 below, the Company also agreed to the amendment and restatement of the senior secured credit facility, pursuant to which the borrowing base under the senior secured credit facility was increased from the then current authorized borrowing base of $50 million to $70 million effective August 20, 2007. The amount of the borrowing base 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 3.0% (increased range by 1.0% from 2.0% to 3.0% as a result of the forbearance agreement and amendment no. 1 to the senior secured credit facility dated June 12, 2008, more fully described in the following paragraphs) 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 June 30, 2008, interest on the borrowings had a weighted average interest rate of 5.43%. For the three months ended June 30, 2008, and 2007, interest and fees incurred for the senior secured credit facility were $0.9 million and $0.6 million, respectively. For the six months ended June 30, 2008, and 2007, interest and fees incurred for the senior secured credit facility were $1.8 million and $1.0 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.

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 June 6, 2008, BNP notified the Company that the syndicate had redetermined the Company’s borrowing base to be $50 million. As a result, there was a potential borrowing base deficiency of as much as $20 million. According to the senior secured credit facility, the Company would be required to repay any deficiency in three equal monthly installments within 90 days following notification, subject to, among other things, the Company’s right to request an interim redetermination of the borrowing base.

17

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6.      DEBT (continued)

On June 12, 2008 (but as of June 2, 2008), the Company and certain subsidiaries, as guarantors, entered into a forbearance agreement and amendment no. 1 to the senior secured credit facility (the “Forbearance and Amendment Agreement”) with BNP and the syndication to address the Company’s failure of certain financial and non-financial covenants for the first quarter ended March 31, 2008. In accordance with the Forbearance and Amendment Agreement, BNP has permanently waived any defaults or events of default resulting from the non-compliance with any covenant failures for any date of determination prior to and including March 31, 2008. BNP has also agreed to forbear and refrain from (i) accelerating any loans outstanding (including any borrowing base deficiency), (ii) exercising all rights and remedies, and (iii) taking any enforcement action under the senior secured credit facility or otherwise as a result of certain potential covenant defaults during the period from June 2, 2008, until August 15, 2008 (the “Standstill Period”), provided the Company complies with certain forbearance covenants (collectively, the “Forbearance Covenants”). The Forbearance Covenants are (i) the Company shall deliver to the syndication on or before the twentieth business day of each month, a detailed monthly financial reporting package for the previous month that shall include account payables aging, working capital, monthly production reports and lease operating statements, (ii) the Company shall participate in monthly conference calls with the syndication during which a financial officer of the Company shall provide the syndication with an update on restructuring and cost reduction efforts, and (iii) no later than August 18, 2008, the Company will execute (or cause to be executed) additional mortgages such that, after giving effect to such additional mortgages, the syndication will have liens on not less than 90% of the PV10 of all proved oil and gas properties evaluated in the reserve report most recently delivered prior to such date. The Company’s failure to comply with the Forbearance Covenants will terminate the Forbearance and Amendment Agreement and allow the syndication to exercise any or all of their rights and remedies under the senior secured credit facility. The Forbearance and Amendment Agreement also increased the additional margin spread from 2.0% to 3.0% when electing a LIBOR-based borrowing rate.

On August 11, 2008, management determined that the Company failed to meet certain financial and non-financial covenants required by the senior secured credit facility for the quarter ended June 30, 2008. Management has requested BNP to permanently waive the Company’s failure to observe or perform the required covenants for the quarter ended June 30, 2008. Management has also requested BNP to extend the Forbearance and Amendment Agreement and Standstill Period for an additional period of time.

Since BNP and the Company have yet to reach an extended forbearance agreement and BNP has the right to demand repayment after the Standstill Period, the entire outstanding debt under the senior secured credit facility has been reclassified as a current liability on the accompanying June 30, 2008 balance sheet. The Company continues negotiations with various institutions and existing lenders to restructure the Company’s debt. However, given the conditions of the existing credit market, the Company has experienced difficulties in closing these restructuring agreements. The Company continues to find interested credit lenders as well as potential acquirers of non-core assets. There can be no assurance that the Company will obtain an extended forbearance agreement or be able to restructure the Company’s debt within an adequate period of time. 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 $0.1 million and $0.2 million for the three months ended June 30, 2008, and 2007, respectively. Amortization expense was $0.1 million and $0.4 million for the six months ended June 30, 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.

18

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6.      DEBT (continued)

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 950 basis points (increased from 700 basis points as a result of the forbearance agreement and amendment no. 1 to the second lien term loan dated June 12, 2008, more fully described in the following paragraphs) 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.

On June 12, 2008 (but as of June 2, 2008), the Company and certain subsidiaries, as guarantors, entered into a forbearance agreement and amendment no. 1 to the Term Loan (the “Term Loan Forbearance and Amendment Agreement”) with BNP and the syndication to address the Company’s failure of certain financial and non-financial covenants for the first quarter ended March 31, 2008. In accordance with the Term Loan Forbearance and Amendment Agreement, BNP has permanently waived any defaults or events of default resulting from the non-compliance with any covenant failures for any date of determination prior to and including March 31, 2008. BNP has also agreed to forbear and refrain from (i) accelerating any loans outstanding, (ii) exercising all rights and remedies and (iii) taking any enforcement action under the Term Loan or otherwise as a result of certain potential covenant defaults during the Standstill Period, provided the Company complies with the Forbearance Covenants, as applicable to the Term Loan. The company’s failure to comply with the Forbearance Covenants will terminate the Term Loan Forbearance and Amendment Agreement and allow the syndication to exercise any or all of their rights and remedies under Term Loan. The Term Loan Forbearance and Amendment Agreement also increased the interest rate payable from LIBOR-based plus 700 basis points to LIBOR-based plus 950 basis points. The Term Loan Forbearance and Amendment Agreement also provides that in no event shall the LIBOR-based rate be less than 4.0%. In addition, the Term Loan Forbearance and Amendment Agreement modified the treatment of interest payments under the Term Loan.

19

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6.      DEBT (continued)

On August 11, 2008, management determined that the Company failed to meet certain financial and non-financial covenants required by the second lien term loan for the quarter ended June 30, 2008. Management has requested BNP to permanently waive the Company’s failure to observe or perform the required covenants for the quarter ended June 30, 2008. Management has also requested BNP to extend the Term Loan Forbearance and Amendment Agreement and Standstill Period for an additional period of time.

Since BNP and the Company have yet to reach an extended forbearance agreement and BNP has the right to demand repayment after the Standstill Period, the entire outstanding debt under the second lien term loan has been reclassified as a current liability on the accompanying June 30, 2008 balance sheet. The Company continues negotiations with various institutions and existing lenders to restructure the Company’s debt. However, given the conditions of the existing credit market, the Company has experienced difficulties in closing these restructuring agreements. The Company continues to find interested credit lenders as well as potential acquirers of non-core assets. There can be no assurance that the Company will obtain an extended forbearance agreement or be able to restructure the Company’s debt within an adequate period of time. 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 and six months ended June 30, 2008, interest and fees incurred for the second lien term loan was $1.4 million and $2.8 million, respectively. 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 $0.1 million for the three and six months ended June 30, 2008. In addition, the Company incurs annual 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 and six months ended June 30, 2007, interest and fees incurred for the mezzanine credit facility was $1.2 million and $2.4 million, respectively. Since this agreement was terminated in 2007, no interest or fees were incurred during 2008.

20

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7. SHAREHOLDERS’ EQUITY

Common Stock

2008

In June 2008, 350,000 shares of the Company’s stock were issued in connection with a stock grant awarded to the Company’s former Chief Financial Officer. The original grant was for 500,000 and the former Chief Financial Officer elected to forfeit 150,000 shares in exchange for the Company paying taxes associated with the stock award in the amount of $90,450.

In April 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 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.

2007

In June 2007, 75,000 shares of the Company’s common stock valued at $147,000 were cancelled in order to reconcile with the Company’s transfer agent.

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.

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 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.

21

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7.       SHAREHOLDERS’ EQUITY (continued)

Common Stock Warrants

The following table sets forth information related to stock warrant activity for the six months ended June 30, 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		0.59
Granted		-		-		-
Exercised		-		-		-
Forfeitures and other adjustments		-		-		-
Outstanding at the end of the period		1,952	$	1.74		0.59

NOTE 8. COMMON STOCK OPTIONS

As of June 30, 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.

The following table sets forth activity for the stock option plans referenced above for the six months ended June 30, 2008 (shares shown in thousands):

	Number of Shares  Underlying Options
Options outstanding at beginning of period		2,874
Options granted		3,000
Options exercised		(163	)
Options forfeited and other adjustments		(126	)
Options outstanding at end of period		5,585

The weighted average assumptions used in the Black-Scholes option-pricing model used to determine fair value were as follows:

Risk-free interest rate	3.68	%
Expected years until exercise	6.0
Expected stock volatility	76.38	%
Dividend yield	0	%

22

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8.      COMMON STOCK OPTIONS (continued)

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 six months ended June 30, 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		3,000			0.75
Options exercised		(1,163	)		0.59
Forfeitures and other adjustments		(126	)		4.86
Options outstanding at end of period		6,015		$	1.77	$	18,333
Exercisable at end of period		2,258		$	2.48	$	18,333
Weighted average fair value of options granted during period		0.52

(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 six months ended June 30, 2008, was approximately $9,000.

The weighted average remaining life by exercise price as of June 30, 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		733		2.7		733		2.7
$0.75		3,000		9.9		-		-
$1.75 - $2.55		385		5.3		353		5.2
$2.90 - $3.62		1,408		3.5		856		3.3
$4.45 - $4.70		489		7.2		315		7.1
$0.38 - $4.70		6,015		7.0		2,257		2.9

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 June 30, 2008.

23

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9.       COMMITMENTS AND CONTINGENCIES (continued)

Letters of Credit

For each salt water disposal well drilled in the State of Michigan, the Company is required to issue a letter of credit to the Michigan Supervisor of Wells. The Supervisor of Wells may draw on the letter of credit if the Company fails to comply with the regulatory requirements relating to the locating, drilling, completing, producing, reworking, plugging, filling of pits, and clean up of the well site. The letter of credit or a substitute financial instrument is required to be in place until the salt water disposal well is plugged and abandoned. For drilling natural gas wells, the Company is required to issue a blanket letter of credit to the Michigan Supervisor of Wells. This blanket letter of credit allows the Company to drill an unlimited number of natural gas wells. The majority of existing letters of credit have been issued by Northwestern Bank of Traverse City, Michigan, 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 June 30, 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 required the Company to record approximately $2.1 million in stock-based compensation expense over the contract period. The Company paid Mr. Huff the compensation provided for in the employment agreement through June 18, 2008. This agreement was 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 six months ended June 30, 2008.

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. For the six months ended June 30, 2008, the Company had recorded $202,179 for retention bonuses in 2008.

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.

On January 10, 2008, the Company signed a non-binding Letter of Intent to acquire Acadian Energy, LLC (“Acadian”). Mr. McDevitt (through a controlled entity) and Mr. Smith are the only members of Acadian (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.

24

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9.       COMMITMENTS AND CONTINGENCIES (continued)

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. The Company and the joint venture partner have agreed, to the best of their abilities, to withhold from pursuing further action and activities related to this lawsuit until August 3, 2008, in order to give Presidium Energy, LC (“Presidium”) sufficient time to secure financing to purchase all outstanding member interests in AOK from the Company as more fully described in Note 10 “Related Party Transactions.”

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

Operating Agreements

Subsequent to the Company executing a Letter of Intent with Acadian as more fully described in Note 9 “Commitment and Contingencies,” on June 24, 2008, the Company entered into an agreement with Acadian to provide funding to maintain and preserve the value of Acadian’s properties located in the State of Indiana pending the Company’s acquisition of Acadian. The Company agreed to advance approximately $83,000 pursuant to an authority for expenditure to be used for the purpose of bringing wells into compliance with the requirements of the State of Indiana and if practical, into production. The Company may also advance additional funds, subject to prior written approval. If the Company acquires Acadian or its assets by October 1, 2008, the advances will become the Company’s obligation. If the Company does not acquire Acadian or its assets by October 1, 2008, Acadian will be required to reimburse the Company for the amount of the advance using 100% of the net revenue proceeds earned by Acadian from the wells that are subject to the agreement, provided, however, that Acadian is required to reimburse the Company for the entire amount of the advances no later than October 1, 2009. The Company also agreed to pay certain legal expenses on behalf of Acadian in connection with the proposed acquisition of Acadian.

Effective April 1, 2008, the Company entered into an agreement with Acadian to provide oil and gas operating services on properties located in the State of Indiana. 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 to the Company.

For the three and six months ended June 30, 2008, the Company incurred expenses in the amount of $0.2 million under the operating agreements with Acadian.

25

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10.     RELATED PARTY TRANSACTIONS (continued)

Disposition Agreement

In March 2006, the Company entered into a joint venture agreement with certain unrelated parties. The joint venture covered the acquisition and development of oil and gas leases in various counties located in Oklahoma. The joint venture project was known as the "Oak Tree Project." The Company participated in the joint venture through a wholly owned subsidiary, AOK Energy, LLC ("AOK"). Effective May 28, 2008, the Company entered into an Agreement for the Purchase and Sale of Limited Liability Company Memberships with Presidium, pursuant to which the Company will sell to Presidium all of the outstanding member interests in AOK for a purchase price that includes the payment by Presidium of certain liabilities that the operator alleges are owed by the Company to other participants in the joint venture, a cash payment to the Company in the amount of $10,500,000, and an assignment to the Company of a 3% overriding royalty in certain leases in the Oak Tree Project.

Presidium is wholly owned and operated by John V. Miller, who served as the Company’s Vice President from November 1, 2005 until he resigned on February 29, 2008. The Company has not had an appraisal of the value of the AOK member interest performed, and the Company is not able to estimate its value. It is unknown whether Mr. Miller will be able to retain the entire value of the AOK member interest by virtue of his ownership of Presidium, or whether his interest will be diluted before the transaction is consummated.

Consulting Agreements

Effective May 20, 2008, the Company entered into a consulting agreement with Presidium in which the Company agreed to provide Presidium services in connection with certain oil and gas leasing, exploration, development, and business projects. This agreement expires December 31, 2008. For the three and six months ended June 30, 2008, the Company billed Presidium $23,097 for services rendered.

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 and six months ended June 30, 2008, Simple Financial Solutions, Inc. billed the Company $65,573 and $76,438, respectively, for services rendered.

Effective May 1, 2008, the Company entered into a month-to-month agreement with Simple Financial Solutions, Inc. to provide professional services for a subsidiary of the Company, Hudson Pipeline & Processing Co., LLC (“HPPC”). On a monthly basis, Simple Financial Solutions, Inc. will be paid 2% of the gross revenues of HPPC and 3.5% of the net income to HPPC before compensation. Certain revenue resulting from gas transportation will be excluded from the calculations. For the three and six months ended June 30, 2008, the Company accrued $20,000 for services received from Simple Financial Solutions, Inc. pursuant to this HPPC agreement.

26

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10.     RELATED PARTY TRANSACTIONS (continued)

Working Interest in Certain Projects

Effective May 30, 2007, the board of directors named John C. Hunter as Vice President of Exploration and Production. He has worked for AOG since 2005 as Senior Petroleum Engineer. Prior to that, Mr. Hunter was instrumental in certain projects associated with the Company’s New Albany shale play. Over a series of agreements with the Company, Mr. Hunter (controlling member of Venator Energy, LLC) has acquired 1.25% working interest in certain leases. The leases cover approximately 132,600 acres (1,658 net) in certain counties located in Indiana. The 1.25% carried working interest shall be effective until development costs exceed $30 million. Thereafter, participation may continue as a standard 1.25% working interest owner. The Company is entitled to recovery of 100% of development costs (plus interest at a rate of 6.75% per annum compounded annually) from 85% of the net operating revenue generated from oil and gas production developed directly or indirectly in the area of mutual interest covered by the agreement. As of June 30, 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 July 21, 2008, the Company amended the Purchase and Sale of Limited Liability Company memberships with Presidium to extend Presidium’s exclusive right to purchase all of the outstanding member interests in AOK until September 15, 2008. In exchange for the extension, Presidium agreed to make a $2 million non-refundable payment to the Company. If Presidium does not need the extension and is able to close on or before August 3, 2008, the entire $2 million will be applied to the purchase price at closing. If Presidium closes within the extension period, the total purchase price will increase by $1 million and the $2 million non-refundable payment will be applied against the purchase price.

27

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 and the Woodford shale in Oklahoma.

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

As of June 30, 2008, our leasehold acres were 1,291,859 (713,287 net) which represent a 1% increase over our December 31, 2007, net acres. These leasehold acres are included in the following plays: 307,400 (153,138 net) leasehold acres in the Michigan Antrim shale play, 15,837 (15,837 net) leasehold acres in the Indiana Antrim shale play, 844,370 (445,685 net) acres in the New Albany shale play, 36,802 (32,753 net) acres in the Woodford shale play, and 87,450 (65,874 net) acres in the other play areas.

With regard to our strategy to generate growth through drilling, we drilled or participated in 14 (3 net) wells for the six months ended June 30, 2008, with a 79% success rate. As of June 30, 2008, we had 629 (284 net) producing wells, 7 (3 net) wells awaiting hook-up, 37 (11 net) wells undergoing resource assessment, and 50 (35 net) wells temporarily abandoned. We also continued our strategy to have greater control over our projects by operating 232 (209 net) wells, thus, operating 35% of our gross wells and 67% of our net wells.

Of the 209 net wells we operate, 167 net wells are producing in the Antrim; 1 net well is awaiting hook-up in the Antrim; 1 net well is 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 33 net wells are temporarily abandoned.

Oil and natural gas production for the six months ended June 30, 2008, was 1,587,067 mcfe, a 6% increase over the 1,493,453 mcfe produced in the six months ended June 30, 2007. For the six months ended June 30, 2008, production continues to be hampered by wells undergoing resource assessment and dewatering. During May 2008, we began a well enhancement program to address our decline in production. The program is expected to address 90 wells primarily located in the Hudson 34 and Hudson SW projects located in the Antrim play. To date, we have completed well enhancement activities on 50 wells and experienced an approximate one to two days stoppage in production per well to complete the well enhancement activities. Management believes that production decline has been arrested, but additional time will be required before measurable progress in production can be recognized. In addition, a number of Antrim wells have been identified for refracing. This project is expected to continue through the end of 2008 with an anticipated completion date in early 2009.

28

Operating Statistics

The following table sets forth certain key operating statistics for the three and six months ended June 30, 2008 (the “Current Quarter” and the “Current Period”), and the three and six months ended June 30, 2007 (the “Prior Year Quarter” and the “Prior Year Period”):

	Three Months Ended June 30,					Six Months Ended June 30,
	2008			2007		2008			2007
Net wells drilled
Antrim shale		-			4		1			12
New Albany shale (“NAS”)		-			4		-			4
Other		-			4		1			8
Dry		1			-		1			4
Total		1			12		3			28
Total net wells
Antrim—producing		261			227		261			227
Antrim—awaiting hookup		2			33		2			33
NAS—producing		7			1		7			1
NAS—awaiting hookup		-			1		-			1
Other—producing		16			13		16			13
Other—awaiting hookup		1			1		1			1
Total		287			276		287			276
Production
Natural gas (mcf)		726,484			720,385		1,504,411			1,410,820
Crude oil (bbls)		5,984			6,773		13,485			13,772
Natural gas equivalent (mcfe)		762,580			761,023		1,587,067			1,493,453
Average daily production
Natural gas (mcf)		7,983			7,916		8,266			7,795
Crude oil (bbls)		66			74		74			76
Natural gas equivalent (mcfe)		8,380			8,363		8,720			8,251
Average sales price (excluding all gains (losses) on derivatives)
Natural gas ($ per mcf)	$	10.99		$	7.80	$	9.60		$	7.36
Crude oil ($ per bbls)	$	144.22		$	60.39	$	110.34		$	57.00
Natural gas equivalent ($ per mcfe)	$	11.60		$	7.92	$	10.04		$	7.48
Average sales price (including all gains (losses) from derivatives)
Natural gas ($ per mcf)	$	8.16		$	8.60	$	7.81		$	8.32
Crude oil ($ per bbls)	$	144.22		$	60.39	$	110.34		$	57.00
Natural gas equivalent ($ per mcfe)	$	8.91		$	8.68	$	8.34		$	8.39
Production revenue ($ in thousands)
Natural gas	$	7,986		$	5,620	$	14,440		$	10,389
Natural gas derivatives—realized (losses) gains		(1,906	)		573		(1,573	)		1,358
Natural gas derivatives—unrealized losses		(148	)		-		(1,117	)		-
Crude oil		863			409		1,488			785
Total	$	6,795		$	6,602	$	13,238		$	12,532

29

	Three Months Ended June 30,					Six Months Ended June 30,
	2008		2007			2008			2007
Average expenses ($ per mcfe)
Production taxes	$	0.53	$	0.40		$	0.47		$	0.38
Post-production expenses	$	1.12	$	0.67		$	0.96		$	0.54
Lease operating expenses	$	2.49	$	2.22		$	2.54		$	2.23
General and administrative expense	$	2.34	$	2.59		$	2.38		$	2.83
General and administrative expense excluding stock-based compensation	$	1.80	$	1.79		$	1.70		$	2.03
Oil and natural gas depletion and amortization expenses	$	1.22	$	1.02		$	1.20		$	1.02
Other assets depreciation and amortization	$	0.30	$	0.75		$	0.37		$	0.76
Interest expenses	$	2.31	$	1.40		$	2.03		$	1.37
Taxes	$	0.03	$	(0.03	)	$	(0.03	)	$	-
Number of employees including Bach		70		88			70			88

Results of Operations

Three Months Ended June 30, 2008, compared with Three Months Ended June 30, 2007

General. For the Current Quarter, we had a net loss of $0.7 million, or $(0.01) diluted common share, on total revenues of $7.9 million. This compares to net income of $0.2 million, or $0.00 per diluted common share, on total revenue of $7.3 million for the Prior Year Quarter. The $0.6 million increase in revenue is primarily attributable to increases in pipeline transportation and marketing services along with increases in field services.

Oil and Natural Gas Sales. During the Current Quarter, oil and natural gas sales were $6.8 million compared to $6.6 million in the Prior Year Quarter. We produced 762,580 mcfe at a weighted average price of $8.91 compared to 761,023 mcfe at a weighted average price of $8.68. The increase in oil and gas sales was primarily the result of increases in sales price. We had 284 net wells producing as of June 30, 2008, as compared to 241 net wells producing as of June 30, 2007. The weighted average price included $1.9 million or $2.49 per mcfe of realized losses from the gas derivative contract for the Current Quarter, and $0.6 million or $0.75 per mcfe of realized gains from the gas derivative contract for the Prior Year Quarter. For the Current Quarter, we also recognized $0.1 million or $0.19 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. Hedge ineffectiveness will continue until our production increases to the level required by the contract or the contract expires.

Production from the Antrim shale play represented approximately 92% of our oil and natural gas revenue for the Current Quarter. The following table summarizes our oil and natural gas revenue by play/trend in the periods set forth below:

	Three Months Ended  June 30, 2008				Three Months Ended  June 30, 2007
Play/Trend	(mcfe)		Amount		(mcfe)		Amount
Antrim		704,369	$	5,678,246		709,155	$	6,104,828
New Albany		22,258		253,124		12,548		98,944
Other		35,953		863,723		39,320		398,657
Total		762,580	$	6,795,093		761,023	$	6,602,429

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Production from the Prior Year Quarter compared to the Current Quarter increased marginally by less than 1%. Lower than expected production resulted from Warner Plant outages, pumping deficiencies, and continued dewatering problems within the Antrim play. We are currently undergoing a well enhancement program to address our decline in production.

Pipeline Transportation and Processing. Pipeline transportation and processing revenues were $0.3 million in the Current Quarter compared to $0.2 million in the Prior Year Quarter. During the Current Quarter, we identified certain post-production costs which were previously being absorbed as lease operating expenses. We recovered the majority of these expenses through retroactive billings of $0.1 million. In addition, we received pipeline revenue of $0.1 million associated with our non-operated Custer 7 project.

Field Service and Sales. Field service and sales were $0.6 million in the Current Quarter compared to $0.1 million in the Prior Year Quarter. In the Prior Year Quarter, the majority of Bach’s services were performed for the Company. The increase in the Current Quarter was attributable to shifting Bach’s services to unrelated third party customers.

Interest and Other Revenues. Interest and other revenues were $0.1 million in the Current Quarter compared to $0.5 million in the Prior Year Quarter. This decrease is primarily attributed to realizing a gain resulting from the sale of mining assets executed during May 2007.

Production Taxes. Production taxes were $0.4 million in the Current Quarter compared to $0.3 million 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 $0.53 per mcfe in the Current Quarter compared to $0.40 per mcfe in the Prior Year Quarter representing an increase of production taxes by 33% 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, processing 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 $2.2 million in the Prior Year Quarter. On a per unit of production basis, production and lease operating expenses were $3.61 per mcfe in the Current Quarter compared to $2.89 per mcfe in the Prior Year Quarter. The increase in the Current Quarter was 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. We also incurred one time consulting charges related to compression analysis and repair along with workover charges related to our well enhancement program.

On a component basis, post-production expenses were $0.9 million, or $1.12 per mcfe, in the Current Quarter compared to $0.5 million, or $0.67 per mcfe, in the Prior Year Quarter. Increase in post-production expenses were primarily related to additional sulfide treatment and pipeline transportation charges including one-time retroactive charges associated with transportation adjustments to royalty owners and certain rate increases for compression and pipeline transportation. Lease operating expenses were $1.9 million, or $2.49 per mcfe, in the Current Quarter compared to $1.7 million, or $2.22 per mcfe, in the Prior Year Quarter. Increase in lease operating expenses were primarily related to one-time consulting charges for compression analysis and repair along with workover charges related to our well enhancement program.

Production and lease operating expenses for operated properties were $4.06 per mcfe in the Current Quarter while non-operated production and lease operating expenses were $2.81 per mcfe in the Current Quarter. Our operated Black Bear East and South Knox projects are negatively impacting our operating cost controls and efficiency due to dewatering and flooding. During the Current Quarter, we have experienced improving results from the Arrowhead, Blue Chip, and Gaylord Fishing Club projects, primarily as a result of reducing our operating expenses by shutting in various uneconomical wells. Production and lease operating expenses for operated properties excluding Black Bear East and South Knox projects were $3.32 per mcfe in the Current Quarter.

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Pipeline and Processing Operating Expenses. Pipeline and processing operating expenses were $0.2 million in the Current Quarter compared to $0.1 million in the Prior Year Quarter. This increase was the result of incurring additional post-production costs which we were previously being absorbing as operating expenses.

Field Services Expenses. Field services expenses were $0.5 million in the Current Quarter compared to $45,824 in the Prior Year Quarter which are attributable to shifting services performed by Bach to unrelated third party customers.

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 $0.2 million, or 10%, from the Prior Year Quarter. This decrease was primarily the result of a reduction in bonus expenses, stock based compensation, and accounting services.

Payroll and related costs decreased by $0.3 million to $1.3 million in the Current Quarter due to lower employee payroll, bonus expenses, and stock-based compensation.

We follow the full cost method of accounting under which all costs associated with property acquisition, exploration, and development activities are capitalized. We capitalized certain internal costs that can be directly identified with our acquisition, exploration, and development activities and do not include any costs related to production, general corporate overhead, or similar activities. We capitalized $0.2 million of payroll and benefit costs for the Current Quarter compared to $0.5 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 along with limited drilling which has reduced our ability to capitalize associated costs.

   Oil and Natural Gas Depletion, Depreciation and Amortization (“DD&A”). DD&A of oil and natural gas properties was $0.9 million and $0.8 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 $1.0 million being added to proved properties in the full cost pool and production growth. The average DD&A cost per mcfe also increased to $1.22 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 $0.2 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 $1.8 million in the Current Quarter compared to $1.1 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. In addition, as part of the forbearance and amendment agreements executed during June 2008, more fully described in the liquidity section, interest rates for the senior secured credit facility and second lien term loan increased.

             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 expense was $26,046 in the Current Quarter compared to $25,129 in the Prior Year Quarter.

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Six Months Ended June 30, 2008, compared with Three Months Ended June 30, 2007

General. For the Current Period, we had a net loss of 1.9 million, or $(0.02) per diluted common share, on total revenues of $14.8 million. This compares to a net loss of $0.5 million, or $(0.01) per diluted common share, on total revenue of $13.5 million for the Prior Year Period. The $1.3 million increase in revenue is primarily attributable to increases in pipeline transportation and marketing services along with increases in field services.

Oil and Natural Gas Sales. During the Current Period, oil and natural gas sales were $13.2 million compared to $12.5 million in the Prior Year Period. We produced 1,587,067 mcfe at a weighted average price of $8.34 compared to 1,493,453 mcfe at a weighted average price of $8.39. This increase in production was due to new wells placed online as well as the increase in sales price. We had 284 net wells producing as of June 30, 2008, as compared to 241 net wells producing as of June 30, 2007. The weighted average price included $1.6 million or $0.99 per mcfe of realized losses from the gas derivative contract for the Current Period, and $1.4 million or $0.91 per mcfe of realized gains from the gas derivative contract for the Prior Year Period. For the six months ended June 30, 2008, we also recognized $1.1 million or $0.70 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. Hedge ineffectiveness will continue until our production increases to the levels required by the contract or the contract expires.

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

	Six Months Ended June 30, 2008				Six Months Ended June 30, 2007
Play/Trend	(mcfe)		Amount		(mcfe)		Amount
Antrim		1,445,211	$	11,160,586		1,384,508	$	11,560,199
New Albany		60,810		587,843		22,892		173,344
Other		81,046		1,489,222		86,053		798,462
Total		1,587,067	$	13,237,651		1,493,453	$	12,532,005

Production from the Prior Year Period compared to the Current Period increased marginally by 6%. Lower than expected production resulted from Warner Plant outages, pumping deficiencies, continued dewatering problem within the Antrim play, and heavy snowfall causing delays in response to freezing complications associated with compressors, booster stations, and water lines. We are currently undergoing a well enhancement program to address our limited production.

Pipeline Transportation and Processing. Pipeline transportation and processing revenues were $0.6 million in the Current Period compared to $0.3 million in the Prior Year Period. During the Current Period, we identified certain post-production costs which were previously being absorbed as lease operating expenses. We recovered the majority of these expenses through retroactive billings of $0.1 million. In addition, we also received pipeline revenue of $0.1 million associated with our non-operated Custer 7 project.

Field Service and Sales. Field service and sales were $0.7 million in the Current Period compared to $0.2 million in the Prior Year Period. In the Prior Year Period, the majority of Bach’s services were performed for the Company. The increase in the Current Period was attributable to shifting Bach’s services to unrelated third party customers.

Interest and Other Revenues. Interest and other revenues were $0.2 million in the Current Period compared to $0.5 million in the Prior Year Period. This decrease is attributed to realizing a gain resulting from the sale of mining assets executed during May 2007.

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Production Taxes. Production taxes were $0.7 million in the Current Period compared to $0.6 million in the Prior Year Period. This increase is attributed to production growth and the state mix of production. On a unit of production basis, production taxes were $0.47 per mcfe in the Current Period compared to $0.38 per mcfe in the Prior Year Period representing an increase of production taxes by 31% in the Current Period from the Prior Year Period.

    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, transportation, processing and expenses to operate the wells and equipment on producing leases.

Production and lease operating expenses were $5.5 million in the Current Period compared to $4.1 million in the Prior Year Period. On a per unit of production basis, production and lease operating expenses were $3.50 per mcfe in the Current Period compared to $2.77 per mcfe in the Prior Year Period. The increase in the Current Period was 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. We also incurred one time consulting charges related to compression analysis and repair along with workover charges related to our well enhancement program.

On a component basis, post-production expenses were $1.5 million, or $0.96 per mcfe, in the Current Period compared to $0.8 million, or $0.54 per mcfe, in the Prior Year Period. Increase in post-production expenses were primarily related to additional sulfide treatment and pipeline transportation charges, including one-time retroactive charges associated with transportation adjustments to royalty owners and certain rate increases for compression and pipeline transportation. Lease operating expenses were $4.0 million, or $2.54 per mcfe, in the Current Period compared to $3.3 million, or $2.23 per mcfe, in the Prior Year Period. Increases in lease operating expenses were primarily related to one-time consulting charges for compression analysis and repair along with workover charges related to our well enhancement program.

Production and lease operating expenses for operated properties were $3.85 per mcfe in the Current Period while non-operated production and lease operating expenses were $2.85 per mcfe in the Current Period. Our operated Arrowhead, Black Bear East, and South Knox projects are negatively impacting our operating cost controls and efficiency due to dewatering and flooding. During the Current Period, we have experienced improving results from the Blue Chip and Gaylord Fishing Club projects, primarily as a result of reducing our operating expenses by shutting in various uneconomical wells. Production and lease operating expenses for operated properties excluding Arrowhead, Blue Chip, Gaylord Fishing Club, and South Knox projects were $3.53 per mcfe in the Current Period.

Pipeline and Processing Operating Expenses. Pipeline and processing operating expenses were $0.3 million in the Current Period compared to $0.2 million in the Prior Year Period. This increase was the result of incurring additional post-production costs which we were previously absorbing as operating expenses by the Company.

Field Services Expenses. Field services expenses were $0.6 million in the Current Period compared to $0.2 million in the Prior Year Period which are attributable to shifting services performed by Bach to unrelated third party customers.

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 Period decreased by $0.4 million, or 10%, from the Prior Year Period. This decrease was primarily the result of a reduction in payroll, bonus expenses and accounting 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 $0.7 million to $2.4 million in the Current Period due to lower employee payroll, bonus expense, and stock-based compensation.

We follow the full cost method of accounting under which all costs associated with property acquisition, exploration, and development activities are capitalized. We capitalized certain internal costs that can be directly identified with our acquisition, exploration, and development activities and do not include any costs related to production, general corporate overhead, or similar activities. We capitalized $0.5 million of payroll and benefit costs for the Current Period compared to $0.8 million in the Prior Year Period. This decrease was primarily related to the reduction in the number of employees associated with acquisition, exploration and development activities along with limited drilling which has reduced our ability to capitalize associated costs.

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Oil and Natural Gas Depletion, Depreciation and Amortization (“DD&A”). DD&A of oil and natural gas properties was $1.9 million and $1.5 million during the Current Period and the Prior Year Period, 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 $7.5 million being added to proved properties in the full cost pool and production growth. The average DD&A cost per mcfe also increased to $1.20 in the Current Period compared to $1.02 in the Prior Year Period 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 $0.6 million in the Current Period compared to $1.1 million in the Prior Year Period. 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 $3.2 million in the Current Period compared to $2.1 million in the Prior Year Period. 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. In addition, as part of the forbearance and amendment agreements executed during June 2008, more fully described in the liquidity section following, interest rates for the senior secured credit facility and second lien term loan increased.

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 Period or Prior Year Period. There was a tax refund of $45,246 in the Current Period compared to a refund of $53 in the Prior Year Period. 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 operations through existing cash balances and internally generated cash flows from sales of oil and natural gas production as well as strategic asset sales. We continue negotiating several term sheets with certain recognized energy lenders offering a variety of financing structures which, in concert with each other or in combination with strategic sales of assets, would offer a restructuring solution for our company. However, given the conditions of the existing credit market, we have experienced difficulties in closing these term sheets. We continue to find interested credit parties but management cannot provide assurance that these terms and conditions will provide adequate capital to restructure our existing credit facilities. 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 or service existing debt levels.

On August 11, 2008, we determined that we failed to meet certain financial and non-financial covenants required by the senior secured credit facility and the second lien term loan for the quarter ended June 30, 2008. We have requested BNP to permanently waive our failure to observe or perform the required covenants for the quarter ended June 30, 2008. We have also requested BNP to extend the Forbearance and Amendment Agreement and the Term Loan Forbearance and Amendment Agreement along with the Standstill Period for an additional period of time.

Since we have yet to reach an extended forbearance agreement with BNP and BNP has the right to demand repayment after the Standstill Period, the entire outstanding debt under the senior secured credit facility and second lien term loan has been reclassified as a current liability on the accompanying June 30, 2008 balance sheet. We continue negotiations with various institutions and existing lenders to restructure our debt. There are no assurances that we will obtain an extended forbearance agreement or be able to restructure our debt. Unless we are able to restructure our existing indebtedness, obtain a waiver, or extend the Forbearance and Amendment Agreement and the Term Loan Forbearance and Amendment Agreement along with the Standstill Period, we believe our liquidity would adversely be affected in a material manner.

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                   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 3.0% (increased range by 1.0% from 2.0% to 3.0% as a result of the forbearance agreement and amendment no. 1 to the senior secured credit facility dated June 12, 2008, more fully described in the following paragraphs) 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 June 30, 2008, interest on the borrowings had a weighted average interest rate of 5.43%. 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.

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 June 6, 2008, BNP notified us that the syndicate had redetermined our borrowing base to be $50 million. As a result, there was a potential deficiency of as much as $20 million. According to the Senior Secured Credit Facility, we would be required to repay any deficiency in three equal monthly installments within 90 days following notification, subject to, among other things, our right to request an interim redetermination of the borrowing base.

On June 12, 2008 (but as of June 2, 2008), we entered into a forbearance agreement and amendment no. 1 to the senior secured credit facility (the “Forbearance and Amendment Agreement”) with BNP and the syndication. In accordance with the Forbearance and Amendment Agreement, BNP has permanently waived any defaults or events of default resulting from the non-compliance with any covenant failures for any date of determination prior to and including March 31, 2008. BNP has also agreed to forbear and refrain from (i) accelerating any loans outstanding, (ii) exercising all rights and remedies, and (iii) taking any enforcement action under the senior secured credit facility or otherwise as a result of certain potential covenant defaults during the period from June 2, 2008, until August 15, 2008 (the “Standstill Period”), provided we comply with certain forbearance covenants (collectively, the “Forbearance Covenants”). The Forbearance Covenants are (i) we shall deliver to the syndication on or before the twentieth business day of each month, a detailed monthly financial reporting package for the previous month that shall include an account payables aging, working capital, monthly production reports and lease operating statements, (ii) we shall participate in monthly conference calls with the syndication during which a financial officer shall provide the syndication with an update on restructuring and cost reduction efforts, and (iii) no later than August 18, 2008, we will execute (or cause to be executed) additional mortgages such that, after giving effect to such additional mortgages, the syndication will have liens on not less than 90% of the PV10 of all proved oil and gas properties evaluated in the reserve report most recently delivered prior to such date. Our failure to comply with the Forbearance Covenants will terminate the Forbearance and Amendment Agreement and allow the syndication to exercise any or all of their rights and remedies under the senior secured credit facility. The Forbearance and Amendment Agreement also increased the additional margin spread from 2.0% to 3.0% when electing a LIBOR-based borrowing rate.

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.

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Interest under the second lien term loan is payable at rates based on the London Interbank Offered Rate plus 950 basis points (increased from 700 basis points as a result of the forbearance agreement and amendment no. 1 to the second lien term loan dated June 12, 2008, more fully described in the following paragraphs) 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.

              On June 12, 2008 (but as of June 2, 2008), we entered into a forbearance agreement and amendment no. 1 to the second lien term loan (the “Term Loan Forbearance and Amendment Agreement”) with BNP and the syndication. In accordance with the Term Loan Forbearance and Amendment Agreement, BNP has permanently waived any defaults or events of default resulting from the non-compliance with any covenant failures for any date of determination prior to and including March 31, 2008. BNP has also agreed to forbear and refrain from (i) accelerating any loans outstanding, (ii) exercising all rights and remedies, and (iii) taking any enforcement action under the second lien term loan or otherwise as a result of certain potential covenant defaults during the Standstill Period, provided we comply with the Forbearance Covenants, as applicable to the second lien term loan. Our failure to comply with the Forbearance Covenants will terminate the Term Loan Forbearance and Amendment Agreement and allow the syndication to exercise any or all of their rights and remedies under the second lien term loan. The Term Loan Forbearance and Amendment Agreement also increased the interest rate payable from LIBOR-based plus 700 basis points to LIBOR-based plus 950 basis points. The Term Loan Forbearance and Amendment Agreement also provided that in no event shall the LIBOR-based rate be less than 4.0%. In addition, the Term Loan Forbearance and Amendment Agreement modified the treatment of interest payments under the second lien term loan.

Our total capitalization was as follows:

	As of June 30, 2008		As of December 31, 2007
Obligations under capital lease	$	4,984	$	7,784
Notes payable		224,058		219,478
Mortgage payables		3,028,588		3,082,196
Senior secured credit facility		69,800,000		56,000,000
Second lien term loan		50,000,000		50,000,000
Total debt		123,057,630		109,309,458
Minority interest in net assets of subsidiaries		143,536		112,661
Shareholders’ equity		103,680,506		132,142,989
Total capitalization	$	226,881,672	$	241,565,108

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Cash Flows from Operating Activities

Cash provided by operating activities was unchanged at $5.4 million in the Current Period compared to the Prior Year Period. 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 $0.1 million.

Cash Flows Used in Investing Activities

Cash flows used in investing activities was $9.0 million in the Current Period compared to $32.0 million in the Prior Year Period. The following table describes our significant investing transactions that we completed in the periods set forth below:

	Six Months Ended June 30,
	2008			2007
Acquisitions of leasehold
Michigan Antrim shale	$	568,608		$	547,746
Indiana Antrim shale		3,018			367,938
New Albany shale		557,190			1,250,111
Woodford shale		456,236			2,654,829
Other		9,598			794,300
Drilling and development of oil and natural gas properties
Michigan Antrim shale		1,295,897	(a)		13,921,972
Indiana Antrim shale		11,994			649,187
New Albany shale		877,189			3,988,899
Other		793,191			908,678
Infrastructure properties
Michigan Antrim shale		31,457			6,321,732
New Albany shale		1,861,915			276,234
Other		-			10,288
Capitalized interest and general and administrative costs on exploration, development and leasehold		2,633,033			2,648,373
Acquisitions/additions for pipeline, property, and equipment		61,481			356,288
Other, net		12,206			4,759
Subtotal of capital expenditures		9,173,013			34,701,334
Sale of oil and natural gas properties		(143,542	)		(1,024,663	)
Sale and leaseback of gas compression equipment		-			(1,202,000	)
Sales of other investment and other		(9,334	)		(457,762	)
Subtotal of capital divestitures		(152,876	)		(2,684,425	)
Total	$	9,020,137		$	32,016,909

(a) Drilling and development costs in the amount of $1,228,139 relate to non-operated properties.

Cash Flows Provided by Financing Activities

Cash flows provided by financing activities were $13.5 million in the Current Period compared to $25.6 million in the Prior Year Period. Cash flows provided in the Current Period included: (1) $13.8 million of senior secured borrowing; and (2) $0.7 million of proceeds received from exercise of common stock options and warrants. Cash flows used in the Current Period included: (1) paydown of $0.1 million in mortgage and notes payable obligations; (2) payment of $0.3 million in financing fees; and (3) payment of $0.6 million on other liabilities.

Cash flows provided by financing activities in the Prior Year Period included: (1) $26.0 million of senior secured credit borrowing; and (2) $5.3 million of short-term bank borrowings. Cash flows used by financing in the Prior Year Period included: (1) net pay-down of $4.5 million within short-term bank borrowings; (2) paydown of $1.0 million in senior credit borrowings; (3) pay-down of $0.2 million in mortgage and notes payable obligations; and (4) payments of $0.2 million in financing fees.

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Recent Accounting Pronouncements

Reference is made to Note 3 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.

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 June 30, 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	$	(4,313	)
April 2007—December 2008		Collar		2,000 mmbtu	$	7.55/$ 9.00		(1,734	)
January 2008—December 2008		Swap		2,000 mmbtu	$	8.41		(1,941	)
January 2009—December 2009		Swap		7,000 mmbtu	$	8.72		(8,719	)
January 2010—March 2011		Swap		7,000 mmbtu	$	8.68		(8,383	)
April 2011—September 2011		Swap		7,000 mmbtu	$	7.62		(3,342	)
Total estimated fair value							$	(28,432	)

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 $0.1 million and $1.1 million for the three and six months ended June 30, 2008, was included as a reduction to oil and natural gas sales.

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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 would 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. However, based on the Term Loan Forbearance and Amendment Agreement, LIBOR had a floor of 4.0% established as of June 2, 2008. Fair value liability of the interest rate swap agreement at June 30, 2008, amounted to $1.5 million.

The following table sets forth our principal financing obligation and the related interest rates as of June 30, 2008:

	Expected Maturity		Average Interest Rate as of  June 30, 2008		Principal  Outstanding
Obligations under capital lease		01/10/09		8.25%	$	4,984
Notes payable		08/01/07-04/25/11		6.50% - 7.50%		224,058
Mortgage payable		10/15/09		Fixed at 6.00%		363,019
Mortgage payable		11/01/08		Fixed at 5.95%		2,665,569
Second lien term loan		02/01/11		Variable - 13.36%		50,000,000
Senior secured credit facility		01/31/10		Variable - 5.43%		69,800,000
Total debt					$	123,057,630

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 $1.2 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 June 30, 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.

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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 24 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 unregistered equity securities nor did we repurchase any of our outstanding equity securities during the quarter ended June 30, 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.
10.19(5)	Forbearance Agreement and Amendment No. 1 to Credit Agreement dated June 2, 2008, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent for the Lenders, the Lenders and the Secured Swap Providers.
10.20(5)	Forbearance Agreement and Amendment No. 1 to Second Lien Term Loan Agreement dated June 2, 2008, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent for the Lenders and the Lenders.
10.21(6)	Form of Change in Control Agreement
10.22(7)	Form of Change in Control Agreement
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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(5) Filed as an exhibit to our Form 8-K dated June 6, 2008, filed with the SEC on June 12, 2008, and incorporated herein by reference.

(6) Filed as an exhibit to our Form 8-K dated October 19, 2007, filed with the SEC on October 26, 2007, and incorporated herein by reference.

(7) Filed as an exhibit to our Form 8-K dated May 6, 2008, filed with the SEC on May 7, 2008, and incorporated herein by reference.

(Intentionally Left Blank)

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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: August 11, 2008	By:	/s/ William W. Deneau
		Name:	William W. Deneau
		Title:	Chief Executive Officer
Date: August 11, 2008	By:	/s/ Barbara E. Lawson
		Name:	Barbara E. Lawson
		Title:	Chief Financial Officer

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