Aurora Oil & Gas 10-Q 2008 Q3 Quarterly report

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2008

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

FOR THE TRANSITION PERIOD FROM ___________ TO _____________.

Commission file number: 000-25170

AURORA OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

Utah	87-0306609
(State or other Jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
4110 Copper Ridge Dr, Suite 100 Traverse City, Michigan 49684
(Address of principal executive offices)
(231) 941-0073
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

Yes ¨ No x

The number of shares of the registrant’s common stock outstanding as of November 5, 2008, was 103,432,788.

FORM 10-Q

INDEX

PART I	FINANCIAL INFORMATION	1
Item 1.	Condensed Consolidated Financial Statements	2
Condensed Consolidated Balance Sheets as of September 30, 2008 (Unaudited), and December 31, 2007 (Audited)		2
Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2008, and 2007		4
Unaudited Consolidated Statements of Shareholders’ Equity for the Nine Months Ended September 30, 2008, and 2007		5
Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2008, and 2007		6
Notes to Unaudited Condensed Consolidated Financial Statements		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47
Item 4.	Controls and Procedures	48
PART II	OTHER INFORMATION	49
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49
Item 3.	Defaults Upon Senior Securities	49
Item 4.	Submission of Matters to a Vote of Security Holders	49
Item 5.	Other Information	49
Item 6.	Exhibits	49
Signatures		52

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 and the forbearance of our lenders.

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

	September 30, 2008 (Unaudited)			December 31, 2007 (Audited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	10,102,838		$	2,425,678
Short-term investments		2,871,010			-
Accounts receivable
Oil and natural gas sales		3,102,819			5,036,416
Joint interest owners		971,525			827,343
Field service and sales		696,819			24,285
Prepaid expenses and other current assets		912,236			765,730
Short-term derivative instruments		-			2,247,990
Total current assets		18,657,247			11,327,452
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, using full cost accounting:
Proved properties		170,205,175			162,724,004
Unproved properties		43,492,938			56,937,683
Less: accumulated depletion and amortization		(17,197,057	)		(14,401,584	)
Total oil and natural gas properties, net		196,501,056			205,260,103
Other property and equipment:
Pipelines, processing facilities, and compression		11,035,670			11,027,577
Other property and equipment		5,740,811			5,450,452
Less: accumulated depreciation		(2,248,973	)		(1,554,189	)
Total other property and equipment, net		14,527,508			14,923,840
Total property and equipment, net		211,028,564			220,183,943
OTHER ASSETS:
Note receivable		12,000,000			-
Goodwill		3,399,918			19,373,264
Intangibles (net of accumulated amortization of $4,638,333 and $4,497,920, respectively)		316,668			457,080
Other investments		216,878			733,836
Debt issuance costs (net of accumulated amortization of $779,078 and $360,972, respectively)		2,153,468			1,661,603
Other		802,286			934,490
Total other assets		18,889,218			23,160,273
TOTAL ASSETS	$	248,575,029		$	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)

	September 30, 2008 (Unaudited)			December 31, 2007 (Audited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	5,514,428		$	6,490,981
Accrued exploration, development, and leasehold costs		653,965			1,341,917
Current portion of obligations under capital leases		3,258			6,288
Current portion of note payable		101,683			76,416
Current portion of mortgage payables		123,761			112,326
Senior secured credit facility		69,800,000			-
Second lien term loan		50,393,750			-
Drilling advances		201,532			168,356
Short-term derivative instruments		1,723,390			384,706
Total current liabilities		128,515,767			8,580,990
LONG-TERM LIABILITIES:
Obligations under capital leases, net of current portion		-			1,496
Asset retirement obligation		1,605,071			1,494,745
Notes payable		221,584			143,062
Mortgage payables		2,946,053			2,969,870
Senior secured credit facility		-			56,000,000
Second lien term loan		-			50,000,000
Long-term derivative instruments		-			2,248,326
Other long-term liabilities		571,041			977,529
Total long-term liabilities		5,343,749			113,835,028
Total liabilities		133,859,516			122,416,018
Minority interest in net assets of subsidiaries		475,114			112,661
COMMITMENTS, CONTINGENCIES, AND SUBSEQUENT EVENT (Note 11 and Note 13)
SHAREHOLDERS’ EQUITY
Common stock, $0.01 par value; authorized 250,000,000 shares; issued and outstanding 103,562,788 and 101,769,456 shares, respectively		1,035,628			1,017,695
Additional paid-in capital		142,636,624			140,541,460
Accumulated other comprehensive loss		(1,821,564	)		(385,043	)
Accumulated deficit		(27,610,289	)		(9,031,123	)
Total shareholders’ equity		114,240,399			132,142,989
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	248,575,029		$	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 September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
REVENUES:
Oil and natural gas sales	$	7,657,965		$	6,957,069		$	20,895,616		$	19,489,074
Pipeline transportation and marketing		215,540			181,441			533,435			468,373
Field service and sales		1,280,206			66,878			1,994,274			316,480
Interest and other		205,983			28,655			450,291			503,413
Total revenues		9,359,694			7,234,043			23,873,616			20,777,340
EXPENSES:
Production taxes		376,381			262,127			1,118,458			829,096
Production and lease operating expense		2,557,330			2,091,066			7,864,074			6,217,766
Pipeline and processing operating expense		179,977			82,986			445,418			260,788
Field services expense		977,235			58,000			1,554,940			258,096
General and administrative expense		2,770,028			1,834,718			6,569,436			6,068,419
Oil and natural gas depletion and amortization		874,426			721,585			2,782,567			2,245,045
Other assets depreciation and amortization		265,040			628,983			851,134			1,771,087
Interest expense		2,023,411			1,244,363			5,249,116			3,294,766
Goodwill impairment		15,973,346			-			15,973,346			-
Loss on debt extinguishment		-			3,448,520			-			3,448,520
Taxes (refunds), other		29,005			95,773			(16,241	)		95,720
Total expenses		26,026,179			10,468,121			42,392,248			24,489,303
LOSS BEFORE MINORITY INTEREST		(16,666,485	)		(3,234,078	)		(18,518,632	)		(3,711,963	)
MINORITY INTEREST IN INCOME OF SUBSIDIARIES		(28,385	)		(20,216	)		(60,534	)		(53,173	)
NET LOSS	$	(16,694,870	)	$	(3,254,294	)	$	(18,579,166	)	$	(3,765,136	)
NET LOSS PER COMMON SHARE—BASIC AND DILUTED	$	(0.16	)	$	(0.03	)	$	(0.18	)	$	(0.01	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING —BASIC AND DILUTED		103,282,788			101,629,673			102,988,798			101,611,357

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)

	Nine Months Ended September 30,
	2008					2007
COMMON STOCK:	Shares		Amount			Shares			Amount
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			263,322			2,633
Issuance of stock to officers and directors in lieu of compensation		630,000		6,300			-			-
Adjustment to stock ledger		-		-			(75,000	)		(750	)
Balance, ending		103,562,788		1,035,628			101,679,456			1,016,795
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				1,213,348						1,969,314
Exercise of stock options and warrants				674,616						109,866
Issuance of stock to officers and directors in lieu of compensation				207,200						-
Adjustment to stock ledger				-						(146,250	)
Balance, ending				142,636,624						140,027,678
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Balance, beginning				(385,043	)					5,220,633
Changes in fair value of derivative instruments				(4,593,056	)					1,983,812
Recognition of gain on derivative instruments				3,156,535						(2,931,211	)
Balance, ending				(1,821,564	)					4,273,234
ACCUMULATED DEFICIT:
Balance, beginning				(9,031,123	)					(4,609,290	)
Net loss				(18,579,166	)					(3,765,136	)
Balance, ending				(27,610,289	)					(8,374,426	)
TOTAL SHAREHOLDERS’ EQUITY			$	114,240,399					$	136,943,281

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)

	Nine Months Ended September 30,
CASH FLOWS FROM OPERATING ACTIVITIES:	2008			2007
Net loss	$	(18,579,166	)	$	(3,765,136	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization		3,633,701			4,016,132
Amortization of debt issuance costs		468,666			641,996
Accretion of asset retirement obligation		82,864			50,095
Loss on debt extinguishment		-			3,448,520
Deferred gain on sale of natural gas compression equipment		(99,620	)		-
Stock-based compensation		1,452,236			1,799,498
Equity loss (gain) of other investments and other		248			(323,801	)
Interest paid in kind on second lien term loan		393,750			-
Realized gain on sale of other investments		-			(418,147	)
Unrealized gain on ineffective commodity derivative		(98,173	)		-
Minority interest income of subsidiaries		60,534			53,173
Goodwill impairment		15,973,346			-
Changes in operating assets and liabilities:
Accounts receivable		1,110,185			2,870,943
Notes receivable		-			221,788
Drilling advance – liabilities		33,176			299,290
Prepaid expenses and other assets		(124,297	)		(133,609	)
Accounts payable and accrued liabilities		44,946			521,144
Net cash provided by operating activities		4,352,396			9,281,886
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and natural gas properties		(9,206,504	)		(43,079,970	)
Leasehold expenditures, net		(1,658,981	)		(9,314,309	)
Acquisition of oil and natural gas properties		-			(2,405,609	)
Sale of oil and natural gas properties		3,191,043			2,079,518
Sales and leaseback of gas compression equipment		-			1,202,000
Acquisitions/additions for pipeline, property, and equipment		(105,697	)		(1,290,037	)
Additions in other investments		(12,206	)		(78,970	)
Sales of other investments		12,334			763,731
Redesignation of cash equivalents to short-term investments		(2,871,010	)		-
Net cash used in investing activities		(10,651,021	)		(52,123,646	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term bank borrowings		100,000			16,212,822
Short-term bank payments		(100,000	)		(16,755,610	)
Advances on senior secured credit facility		13,800,000			42,000,000
Payments on senior secured credit facility		-			(6,000,000	)
Payments on mezzanine financing		-			(40,000,000	)
Advances on second lien term loan		-			50,000,000
Payments on mortgage obligations and notes payable		(147,385	)		(231,831	)
Payments of financing fees on credit facilities		(703,472	)		(1,667,909	)
Prepayment penalties on debt extinguishment		-			(1,866,580	)
Capital contributions from minority interest members		363,183			16,786
Distributions to minority interest members		(61,263	)		(49,839	)
Proceeds from exercise of options and warrants		686,249			112,499
Other		38,473			(17,774	)
Net cash provided by financing activities		13,975,785			41,752,564
Net increase (decrease) in cash and cash equivalents		7,677,160			(1,089,196	)
Cash and cash equivalents, beginning of the period		2,425,678			1,735,396
Cash and cash equivalents, end of the period	$	10,102,838		$	646,200

6

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited-continued)

	Nine Months Ended September 30,
	2008		2007
NONCASH FINANCING AND INVESTING ACTIVITIES:
Oil and natural gas properties asset retirement obligation	$	27,462	$	(40,710	)
Accrued exploration and development costs on oil and natural gas properties		606,612		3,368,953
Accrued leasehold costs		47,353		118,789
Oil and natural gas properties capitalized stock-based compensation		65,062		169,816
Oil and natural gas properties acquisition through other long-term liability		-		600,000
Conversion of accounts receivable to notes receivable		6,706		25,719
Vehicle purchase through financing		168,793		118,526
Land purchase through financing		70,000		-
Sale of oil and gas properties through note receivable		12,000,000		-
SUPPLEMENTAL INFORMATION OF INTEREST AND INCOME TAXES PAID :
Interest, net of amount capitalized of $3,391,577 and $3,083,417, respectively	$	4,176,192	$	2,217,526
Income taxes		98,108		107,700

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

7

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS

Aurora Oil & Gas Corporation (“AOG”) and its wholly owned subsidiaries (collectively, the “Company”) is an independent energy company focused on the exploration, development, and production of unconventional natural gas reserves. The Company generates most of its revenue from the production and sale of natural gas. The Company is focused on developing operating interests in unconventional drilling programs in the Michigan Antrim shale and the New Albany shale of Indiana and Kentucky. The Company’s drilling program is dependent on access to the credit markets. Due to the current economic events within the banking industry the Company is having difficulty securing the necessary credit to move forward with a development program. The Company is a Utah corporation whose common stock is listed and traded on the 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. To mitigate a portion of the exposure to adverse market changes the Company periodically entered into various derivative instruments with a major financial institution. As more fully described in Note 13 “Subsequent Events”, the Company’s natural gas derivatives were terminated on October 1, 2008. As a result, the Company is presently exposed to the fluctuation of natural gas prices.

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

Basis of Presentation

The financial information included herein is unaudited, except the balance sheet as of December 31, 2007, which has been derived from our audited consolidated financial statements as of December 31, 2007. Such information includes all adjustments (consisting solely of normal recurring adjustments), which are, in the opinion of management, necessary for a fair presentation of financial position, results of operations, and cash flows for the interim periods. The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year.

Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission. These condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in our Annual Report on Form 10-K/A for the year ended December 31, 2007.

Principles of Consolidation

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

8

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Use of Estimates

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

Reclassifications

Certain reclassifications have been made to the condensed financial statements for the three and nine months ended September 30, 2007 in order to conform to the presentation used for the three and nine months ended September 30, 2008.

Short-Term Investments

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

In mid-September, the net asset value of the Primary Fund decreased below $1 per share as a result of the Primary Fund’s valuing at zero its holdings of debt securities issued by Lehman Brothers Holdings, Inc., which filed for bankruptcy on September 15, 2008. Management has requested the redemption of the Company’s investment in the Primary Fund. Management expects distributions will occur as the Primary Fund’s assets mature or are sold. In addition, the Primary Fund has announced that it has applied to participate in the United States Department of Treasury’s Temporary Money Market Fund Guarantee Program, participation in which is subject to the approval of the Treasury Department. Even if the Primary Fund is allowed to participate in the Guarantee Program, the effect on the Company’s investment is uncertain. While management expects to receive substantially all of the Company’s current holdings in the Primary Fund, management cannot predict when this will occur or the amount that will be received. Accordingly, management has reclassified the investment from cash and cash equivalents to short-term investments as of September 30, 2008.

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.

9

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

In 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.

No revisions of estimated liabilities were made for the three months ended September 30, 2008. Revisions for the nine months ended September 30, 2008 are not considered material and primarily relate to changes in working interest on certain properties. For the three and nine months ended September 30, 2007, revisions of estimated liabilities included increases due to a reduction in estimated well plugging costs for certain non-Antrim wells totaling $0.2 million. Effective January 1, 2007, the accretion of ARO on producing wells was adjusted for a change in 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. Accordingly, revisions for the nine months ended September 30, 2007, included a decrease of $0.6 million resulting from the increase in estimated well life by 10 years to an estimated life of 50 years per well. In addition, revisions of estimated liabilities for the nine months ended September 30, 2007 included increases due to the removal of equipment salvage value totaling $0.1 million.

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

Three Months Ended September 30,	2008			2007
Beginning balance	$	1,578		$	990
Liabilities incurred		10			168
Liabilities settled		(10	)		-
Accretion expense		27			19
Revisions of estimated liabilities		-			162
Ending balance	$	1,605		$	1,339

Nine Months Ended September 30,	2008			2007
Beginning balance	$	1,495		$	1,332
Liabilities incurred		38			292
Liabilities settled		(14	)		(34	)
Accretion expense		83			50
Revisions of estimated liabilities		3			(301	)
Ending balance	$	1,605		$	1,339

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)

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 previously entered into various derivative instruments with a major financial institution. The purpose of a 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. As more fully described in Note 13 “Subsequent Events”, the Company’s natural gas derivatives were terminated on October 1, 2008. As a result, the Company is presently exposed to the fluctuation of natural gas prices.

Since the termination of the natural gas derivatives occurred on October 1, 2008, as of September 30, 2008 the Company’s natural gas derivative instruments were still active and recorded as a short-term liability on the accompanying September 30, 2008 balance sheet. The Company recognized 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 September 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	$	594
April 2007—December 2008		Collar		2,000 mmbtu	$	7.55/$ 9.00		28
January 2008 – December 2008		Swap		2,000 mmbtu	$	8.41		88
January 2009—December 2009		Swap		7,000 mmbtu	$	8.72		868
January 2010—March 2011		Swap		7,000 mmbtu	$	8.68		(781	)
April 2011 – September 2011		Swap		7,000 mmbtu	$	7.62		(975	)
Total Estimated Fair Value							$	(178	)

For the nine months ended September 30, 2008, the Company has recognized in Comprehensive Income (Loss) changes in fair value of $4.0 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):

11

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

For the Three Months Ended September 30,	2008			2007
Oil and natural gas sales	$	7,723		$	5,415
Realized (losses) gains on natural gas derivatives		(1,025	)		1,542
Realized losses on ineffectiveness of cash flow hedges		(255	)		-
Unrealized gains on ineffectiveness of cash flow hedges		1,215			-
Total	$	7,658		$	6,957

For the Nine Months Ended September 30,	2008			2007
Oil and natural gas sales	$	23,651		$	16,589
Realized (losses) gains on natural gas derivatives		(2,289	)		1,900
Realized losses on ineffectiveness of cash flow hedges		(564	)		-
Unrealized gains on ineffectiveness of cash flow hedges		98			-
Total	$	20,896		$	19,489

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. As more fully described in Note 13 “Subsequent Events” the Company’s interest rate derivative was terminated on October 1, 2008. As a result, the Company is presently exposed to fluctuations of interest rates.

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. Since the termination of the interest rate derivative occurred on October 1, 2008, as of September 30, 2008 the Company’s interest rate derivative was still active and recorded as a short-term liability on the accompanying September 30, 2008 balance sheet. The swap converted the debt’s floating three month LIBOR base to 4.86% fixed base. This swap on $50 million was to 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 8 “Debt,” LIBOR rate had a floor of 4.0% established as of June 21, 2008.

For the nine months ended September 30, 2008, the Company has recognized in Comprehensive Income (Loss) changes in fair value of $0.6 million on the interest rate swap. See “Comprehensive Income (Loss)” found in this note section. For the three and nine months ended September 30, 2008, the Company recognized $0.3 million and $0.6 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 September 30, 2008, amounted to $1.6 million.

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)

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 September 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 September 30,	2008		2007
General and administrative expenses	$	353	$	598
Production and lease operating expenses		2		-
Oil and natural gas properties		19		36
Total	$	374	$	634

For the Nine Months Ended September 30,	2008		2007
General and administrative expenses	$	1,441	$	1,799
Production and lease operating expenses		10		-
Pipeline and processing operating expenses		1		-
Oil and natural gas properties		65		170
Total	$	1,517	$	1,969

13

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 shares granted to the five non-employee directors in May 2008, more fully described in Note 9 “Shareholders’ Equity,” 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 nine months ended September 30, 2008. As more fully disclosed in Note 13 “Subsequent Events”, these awards were rescinded by agreement of the Company and those directors on October 23, 2008.

The following table provides the unrecognized compensation expense related to unvested stock options as of September 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		-		106		40		-
4th Quarter		324		102		40		-
Total	$	324	$	653	$	257	$	65	$	1,299

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 September 30,	2008			2007
Net loss	$	(16,695	)	$	(3,254	)
Other comprehensive loss:
Change in fair value of natural gas derivative instruments		25,759			3,435
Change in fair value of interest rate derivative instruments		(138	)		(351	)
Recognition of losses (gains) on derivative instruments		1,260			(1,573	)
Comprehensive income (loss)	$	10,186		$	(1,743	)

Nine Months Ended September 30,	2008			2007
Net loss	$	(18,579	)	$	(3,765	)
Other comprehensive loss:
Change in fair value of natural gas derivative instruments		(4,003	)		2,335
Change in fair value of interest rate derivative instruments		(590	)		(351	)
Recognition of losses (gains) on derivative instruments		3,157			(2,931	)
Comprehensive loss	$	(20,015	)	$	(4,712	)

14

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 September 30, 2008, and 2007, respectively, options to purchase 7,584,445 and 2,244,446 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 nine months ended September 30, 2008, and 2007, respectively, options to purchase 7,251,113 and 2,224,446 shares of common stock were not included in the computation of diluted net income (loss) per share as their effect would have been anti-dilutive.

NOTE 3. GOING CONCERN

The Company’s financial statements for the nine months ended September 30, 2008, have been prepared on a going concern basis which contemplates the realization of assets and the settlement of liabilities in the normal course of business. With the loss of production and significant deficiencies in working capital along with the increase in interest rates and termination of the Company’s natural gas and interest rate derivatives more fully described in Note 13 “Subsequent Events,” the Company’s operations and existing cash balances are not sufficient to support interest requirements on existing debt balances for longer than one year. The Company is currently in default under the senior secured credit facility and second lien term loan which are more fully described in Note 8 “Debt.” The Company’s continued existence is dependent on (1) the lenders’ willingness to refrain from accelerating or demanding repayment on current debt obligations, (2) restructuring the Company’s current debt and interest payments, (3) securing alternative financing arrangements, and/or (4) asset divestitures. Management continues discussions with existing lenders and is seeking alternative financing arrangements and opportunities for asset divestitures. Due to the recent events within the banking industry the Company is having difficulty securing alternative financing arrangements. There is no assurance the lenders will not call the debt obligation or that the Company will be able to restructure or refinance its current debt or sell assets.

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

NOTE 4. IMPAIRMENT OF GOODWILL

The Company tests goodwill for impairment annually in accordance with Statement of Financial Standards No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). SFAS 142 requires goodwill be tested at least annually using a two-step process that begins with identifying potential impairment. Potential impairment is identified if the fair value of the reporting unit to which goodwill applies is less than the recognized or book value of the related reporting entity, including such goodwill. Where the book value of a reporting entity, including related goodwill, is greater than the reporting entity’s fair value, the second step of the goodwill impairment test is performed to measure the amount of impairment loss, if any. Based on the Company’s continued loss in production, management has determined using projected discounted future operating cash flows at a 10% discount rate as a measurement of goodwill impairment is not appropriate. Accordingly, management measured goodwill impairment using quoted market prices adjusted for known synergies and other benefits arising from subsidiaries.

15

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 4. IMPAIRMENT OF GOODWILL (continued)

As of September 30, 2008, the Company determined that there was an impairment of goodwill related to the reverse acquisition of Cadence Resources Corporation (“Cadence”) executed in 2005. Accordingly, the Company recorded a full impairment of goodwill for the Cadence acquisition which resulted in a write-down of $16.0 million and has been recorded as an operating expense in the consolidated statements of operations for the three and nine months ended September 30, 2008. There were no impairments to goodwill during the nine months ended September 30, 2007. Remaining goodwill in the Company’s consolidated balance sheet relates to the Company’s acquisition of certain companies and assets forming Bach Services & Manufacturing Co., LLC (a subsidiary of the Company) executed in October 2006. For the three and nine months ended September 30 2008, and 2007 the Company did not identify any potential impairment related to Bach Services & Manufacturing Co., LLC’s goodwill.

NOTE 5. 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.” Management does not expect its adoption will have a material impact on the consolidated financial statements.

In April 2008, the FASB issued FASB Staff Positions (“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. Management does not expect the adoption of FSP No. FAS 142-3 to have a material impact on the consolidated financial statements.

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. With the termination of the Company’s derivative instruments more fully disclosed in Note 13 “Subsequent Events”, management does not expect the adoption to have a material impact on the consolidated financial statements.

16

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6. 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 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 September 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	$	178		-	$	178		-
Derivative liabilities—interest rate swap		1,646		-		1,646		-

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.

17

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7. ACQUISITIONS AND DISPOSITIONS

2008 – AOK Energy, LLC

As more fully disclosed in Note 12 “Related Party Transactions”, effective September 12, 2008, the Company sold all its membership interest in AOK Energy LLC to Presidium Energy, LC for $15 million.

2008 – New Albany Shale Exchange

On August 12, 2008, the Company exchanged 42,988 net acres located in the Lawrence, Knox and Sullivan Counties, Indiana for 40,316 net acres located in the Owen, Sullivan, Clay, Green, Lawrence, Washington, Jackson and Orange Counties, Indiana. As part of this transaction the Company increased reserves by 1,232 mcfe and increased the Company’s working interest by 15.68%.

2008 – Bauer, Boehmer, Ergang and Hill Estate Prospects

On July 31, 2008, the Company received proceeds of $35,000 in connection with the sale of all its interest in the Bauer, Boehmer, Ergang and Hill Estate prospects. The prospects are located in Grand Traverse County, Michigan and cover approximately 768 acres.

2008 – Fry #1-13 Well and Green 13/14/15 Prospects

On July 15, 2008, the Company received proceeds of $12,500 in connection with the sale of all its interest in the Fry #1-13 well and Green 13/14/15 prospects. The well and prospects are located in Mecosta County, Michigan and no acres were sold in connection with this sale.

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 – Rex Energy Exercised Option to Acquire Interest in Oil and Natural Gas Leases

On September 7, 2007, Rex Energy Corporation exercised an option to acquire a 30% working interest in various undeveloped oil and natural gas leases located in the New Albany shale for approximately $1.1 million. The interest in oil and gas leases covers approximately 70,324 (21,097 net) acres in Lawrence, Jackson, Washington and Orange Counties, Indiana.

18

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7. ACQUISITIONS AND DISPOSITIONS (continued)

2007 – GFS and Federated Oil and Gas Properties

On August 31, 2007, the Company entered into two Purchase Letter Agreements to buy GFS Energy, Inc. and Federated Oil & Gas Properties, Inc. non-operated working interests and overriding royalty interests in various developed oil and natural gas properties located in the Antrim shale for approximately $3.0 million. The properties included 93 (33 net) wells, producing approximately 500 mcfe per day, and approximately 4,700 (1,706 net) acres. This transaction had an effective date of September 1, 2007.

2007 – Knox, Indiana

On July 30, 2007, the Company purchased from Horizontal Systems, Inc. its working interest in various undeveloped oil and natural gas leases located in Knox County, Indiana for approximately $1.2 million pursuant to a Sale and Assignment of Oil and Gas Interests Agreement. The properties included 25% working interest in one well and approximately 9,642 net 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 8. 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 nine months ended September 30, 2007, was $28,098 and $34,980, respectively. Northwestern Bank continues to provide letters of credit for the Company’s drilling program (as described in Note 11 “Commitments and Contingencies”).

19

 AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8. 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 (5.0% at September 30, 2008, and 8.25% September 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 September 30, 2008. Interest expense for the three months ended September 30, 2007, was $955. Interest expense for the nine months ended September 30, 2008, and 2007, was $1,523 and $2,298, respectively.

Mortgage and Notes Payable - Bach

On September 19, 2008, Bach entered into a note payable obligation with Northwestern Bank for financing the purchase of approximately 2 acres of land located next to the building. The obligation is collateralized by the land. The land is expected to be used for expanding the facility and storing equipment previously kept at certain well sites. The note payable obligation matures on October 1, 2011. Fixed interest is charged at 5.95%. As of September 30, 2008, the total principal amount outstanding was $0.1 million. Total interest expense for the three and nine months ended September 30, 2008, was $133.

On September 12, 2008, Bach entered into a note payable obligation with Northwestern Bank for the financing of a vehicle. The note payable obligation matures on September 15, 2012. Fixed interest is charged at 6.35%. As of September 30, 2008, the total principal amount outstanding was $34,791. Total interest expense for the three and nine months ended September 30, 2008, was $101.

On July 3, 2008, Bach entered into a note payable obligation with Northwestern Bank for the financing of a dozer. The note payable obligation matures July 3, 2012. Fixed interest is charged at 5.0%. As of September 30, 2008, the total principal amount outstanding was $0.1 million. Total interest expense for the three and nine months ended September 30, 2008, was $1,087.

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 September 30, 2008, the principal amount outstanding was $0.4 million. Interest expense for the three months ended September 30, 2008, and 2007, was $5,383 and $3,966, respectively. Interest expense for the nine months ended September 30, 2008, and 2007, was $16,416 and $15,310, 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 September 30, 2008, the total principal amount outstanding was $0.2 million. Total interest expense for the three months ended September 30, 2008, and 2007, was $3,836 and $4,788, respectively. Total interest expense for the nine months ended September 30, 2008, and 2007, was $11,997 and $10,999, respectively.

20

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8. DEBT (continued)

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 nine months ended September 30, 2007, was $21 and $253, 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 September 30, 2008, the principal amount outstanding was $2.6 million. Interest expense for the three months ended September 30, 2008, and 2007, was $40,240 and $60,454, respectively. Interest expense for the nine months ended September 30, 2008, and 2007, was $122,865 and $129,790, 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 nine months ended September 30, 2007, was $273 and $2,546, respectively.

Senior Secured Credit Facility

On January 31, 2006, the Company entered into a $100 million senior secured credit facility with BNP and other lenders for drilling, development, and acquisitions, as well as other general corporate purposes. In connection with the second 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 September 30, 2008, interest on the borrowings had a weighted average interest rate of 5.2%. For the three months ended September 30, 2008, and 2007, interest and fees incurred for the senior secured credit facility were $0.9 million and $0.8 million, respectively. For the nine months ended September 30, 2008, and 2007, interest and fees incurred for the senior secured credit facility were $2.7 million and $1.8 million, respectively. All outstanding principal and accrued and unpaid interest under the senior secured facility is due and payable on January 31, 2010. The maturity date of the outstanding loan may be accelerated by the lenders upon occurrence of an event of default under the senior secured credit facility.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8. DEBT (continued)

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

On 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 subject to, among other things, the Company’s right to request an interim redetermination of the borrowing base.

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 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. As of September 30, 2008, the syndication has liens on less than 90% of all the Company’s proved oil and gas properties and the Company is therefore not in compliance with a Forbearance Covenant. On August 15, 2008 the Forbearance and Amendment Agreement expired without extension and therefore the syndication currently has the ability 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.

Since the expiration of the Standstill Period, the Company continues to engage in discussions with BNP and the syndicate to restructure the Company’s debt. As of the filing of this Form 10-Q, other than the actions taken by BNP more fully described in Note 13 “Subsequent Events”, BNP has not made any attempt to accelerate or demand payment on the senior secured credit facility or taken any other remedial or enforcement action. Management recognizes that the senior secured credit facility is due and payable upon notification from BNP, and therefore the entire outstanding debt has been classified as a current liability on the accompanying September 30, 2008 balance sheet. In addition to discussions with BNP and the syndicate, management is also seeking alternative financing arrangements and opportunities for asset divestitures. There is no assurance that BNP and the syndicate will not accelerate or demand repayment of the senior secured credit facility or that management will be successful in restructuring the Company’s debt, finding alternative financing arrangements, or selling Company assets.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8. DEBT (continued)

For the three and nine months ended September 30, 2008 the Company has incurred deferred financing fees of $0.5 million with regard to the senior secured credit facility resulting in total deferred financing fees of $1.2 million at September 30, 2008. The deferred financing fees are being amortized on a straight-line basis over the remaining terms of the debt obligation. Amortization expense was $0.1 million and $47,930 for the three months ended September 30, 2008, and 2007, respectively. Amortization expense was $0.2 million and $0.1 million for the nine months ended September 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.

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. During August 2008, the Company was notified that Laminar Direct Capital, LLC (“Laminar”) succeeded BNP as the arranger and administrative agent for the second lien term loan. 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. As of September 30, 2008, interest on borrowings had a weighted average interest rate of 13.5%. 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.

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 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. As of September 30, 2008, the syndication for the Term Loan has liens on less than 90% of all the Company’s proved oil and gas properties and the Company is therefore not in compliance with a Forbearance Covenant. On August 15, 2008 the Term Loan Forbearance and Amendment Agreement expired without extension and therefore the syndication currently has the ability 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 instituted a payment-in-kind (“PIK”) arrangement which has resulted in additional liability under the Term Loan amounting to $0.4 million for the three and nine months ended September 30, 2008.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8. DEBT (continued)

Since the expiration of the Standstill Period, the Company continues to engage in discussions with Laminar and the syndicate to restructure the Company’s debt. As of the filing of this Form 10-Q, other than the actions taken by Laminar more fully described in Note 13 “Subsequent Events,” Laminar has not made any attempt to accelerate or demand payment on the second lien term loan or taken any other remedial or enforcement action. Management recognizes that the second term lien loan is due and payable upon notification from Laminar, and therefore the entire outstanding debt has been classified as a current liability on the accompanying September 30, 2008 balance sheet. In addition to discussions with Laminar and the syndicate, management is also seeking alternative financing arrangements and opportunities for asset divestitures. There is no assurance that Laminar and the syndicate will not accelerate or demand repayment of the second term lien loan or that management will be successful in restructuring the Company’s debt, finding alternative financing arrangements, or selling Company assets.

For the three and nine months ended September 30, 2008, interest and fees incurred for the second lien term loan was $1.8 million and $4.6 million, respectively. For the three and nine months ended September 30, 2007, interest and fees incurred for the second lien term loan was $0.7 million. The Company has also incurred deferred financing fees of approximately $1.8 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 and $0.2 million for the three and nine months ended September 30, 2008, respectively. Amortization expense was $30,316 for the three and nine months ended September 30, 2007. 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 nine months ended September 30, 2007, interest and fees incurred for the mezzanine credit facility was $0.6 million and $3.0 million, respectively. Since this agreement was terminated in 2007, no interest or fees were incurred during 2008.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9. SHAREHOLDERS’ EQUITY

Common Stock

2008

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. Of the 280,000 total shares granted, 100,000 were issued during July 2008 and 180,000 were issued during August 2008. As more fully disclosed in Note 13 “Subsequent Events”, these awards were rescinded by agreement of the Company and those directors on October 23, 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.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9. SHAREHOLDERS’ EQUITY (continued)

Common Stock Warrants

The following table sets forth information related to stock warrant activity for the nine months ended September 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		0.34
Granted		-		-		-
Exercised		-		-		-
Forfeitures and other adjustments		-		-		-
Outstanding at the end of the period		1,952	$	1.74		0.34

NOTE 10. COMMON STOCK OPTIONS

As of September 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 nine months ended September 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		(508	)
Options outstanding at end of period		5,203

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	%

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10. 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 nine months ended September 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		(508	)		2.44
Options outstanding at end of period		5,633		$	1.78	$	-
Exercisable at end of period		2,277		$	2.27	$	-
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. Since the exercise price of all stock options are less than the current market value, no intrinsic value exists for options exercised during the nine months ended September 30, 2008.

The weighted average remaining life by exercise price as of September 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		2.5		733		2.5
$0.75		2.750		9.7		-		-
$1.75 - $2.55		385		4.7		363		4.5
$2.90 - $3.62		1,308		2.3		856		2.1
$4.45 - $4.70		457		6.3		325		5.9
$0.38 - $4.70		5,633		6.4		2,277		3.0

NOTE 11. 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 September 30, 2008.

Letters of Credit

For each salt water disposal well drilled in the State of Michigan, the Company is required to issue a letter of credit to the Michigan Supervisor of Wells. The Supervisor of Wells may draw on the letter of credit if the Company fails to comply with the regulatory requirements relating to the locating, drilling, completing, producing, reworking, plugging, filling of pits, and clean up of the well site. The letter of

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 11. COMMITMENTS AND CONTINGENCIES (continued)

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 September 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 nine months ended September 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 nine months ended September 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. The Letter of Intent was terminated on October 1, 2008 more fully described in Note 13 “Subsequent Events”.

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. In 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.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 11. COMMITMENTS AND CONTINGENCIES (continued)

As a result of the Company’s Purchase and Sale Agreement more fully described in Note 12 “Related Party Transactions,” on September 23, 2008, the joint venture partner dismissed all claims associated with this complaint.

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.

South Knox Loss

The Company operates various wells located in the South Knox project. During August 2008, the facility located in the South Knox project experienced a fire which incurred approximately $0.4 million in damages. Insurance claims have been submitted and the Company anticipates the full claim with the exception of $36,000 will be reimbursed by the insurance company.

NOTE 12. RELATED PARTY TRANSACTIONS

Presidium Energy, LC

AOK Energy, LLC Purchase and Sale Agreement

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

Effective July 21, 2008, the Company amended the Purchase and Sale of Limited Liability Company Memberships with Presidium (the “First Amendment”) to extend Presidium’s exclusive right to purchase all of the outstanding member interests in AOK until September 15, 2008. In exchange for the extension, Presidium agreed to make a $2 million non-refundable payment to the Company.

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

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 12. RELATED PARTY TRANSACTIONS (continued)

Under the terms of the Promissory Note, Presidium is required to make monthly interest only payments calculated at the lesser of the maximum rate allowed by law or 9.0%. As security for repayment of the Promissory Note Presidium granted a first priority security interest in all of AOK interests and delivered mortgages on all oil and gas leases Presidium holds or will acquire in the Oak Tree Project. In the event Presidium plans to drill a well in the Oak Tree Project, a principal payment on the Promissory Note equal to the amount of $400 per net acre of leases to be included in the drilling unit must be submitted to the Company in order for the Company to subordinate any mortgages held on leases that fall within the drilling unit. Presidium shall be entitled to have outstanding mortgage subordinations for no more than five undrilled well sites at any one time. The entire outstanding principal balance along with all accrued interest is due September 10, 2010. For the three and nine months ended September 30, 2008 the Company accrued $48,000 of interest receivable related to the Promissory Note.

Consulting Agreement and Other

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 nine months ended September 30, 2008, the Company billed Presidium $37,181 and $60,278, respectively, for services rendered.

In the normal course of business the Company engages in certain operational transactions with Presidium. For the three and nine months ended September 30, 2008 the Company sold inventory to Presidium in the amount of $0.1 million and billed Presidium for lease bonus extensions in the amount of $0.1 million.

Acadian Energy, LLC

Operating Agreements

Subsequent to the Company executing a Letter of Intent with Acadian as more fully described in Note 11 “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.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 12. RELATED PARTY TRANSACTIONS (continued)

For the three and nine months ended September 30, 2008, the Company incurred expenses in the amount of $0.1 million and $0.3 million, respectively, under the operating agreements with Acadian. Due to the termination of the Letter of Intent agreement with Acadian more fully described in Note 13 “Subsequent Events”, amounts incurred on behalf of Acadian in the amount of $0.3 million has been recorded as a receivable at September 30, 2008.

Simple Financial Solutions, Inc.

Consulting Agreements

Effective January 22, 2008, Barbara E. Lawson was named Chief Financial Officer of the Company. Simple Financial Solutions, Inc., which is owned and operated by Ms. Lawson’s spouse, provides consulting services on a continuous basis to the Company including Bach Services and Manufacturing Co., LLC a Company subsidiary. For the three and nine months ended September 30, 2008, Simple Financial Solutions, Inc. billed the Company $27,930 and $104,367, 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 nine months ended September 30, 2008, the Company paid $62,770, which included a retainer in the amount of $25,000, and $82,770, respectively, for services received from Simple Financial Solutions, Inc. pursuant to this HPPC agreement.

Disposition of Membership Interest

Effective June 28, 2008, Lawson & Kidd, LLC purchased a 2.5% membership interest in Hudson Pipeline & Processing Co., LLC (“HPPC”), a subsidiary of the Company, for $0.1 million. Lawson & Kidd, LLC is solely owned by Barbara E. Lawson who is the Company’s Chief Financial Officer and Ms. Lawson’s spouse. Lawson & Kidd, LLC’s interest will increase to 5% upon HPPC receiving income equal to 125% of total costs spent on construction of the pipelines owned and operated by HPPC. For the three and nine months ended September 30, 2008, the Company received $0.1 million in capital call contributions from Lawson and Kidd, LLC and paid to Lawson & Kidd, LLC total distributions in the amount of $10,321.

Other

Consulting Agreements

Effective August 15, 2008, the Company entered into a consulting agreement with Richard M. Deneau to provide advice and services in connection with management’s negotiations with the Company’s existing bankers and the creation and maintenance of new banking relationships. Mr. Deneau is the brother of the Company’s Chief Executive Officer and has served as an affiliated director of the Company since 2005. For the three and nine months ended September 30, 2008, the Company paid $22,695 for consulting services received from Mr. Deneau.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 12. 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 September 30, 2008, there is no production associated with this working interest and development costs were approximately $13 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 13. SUBSEQUENT EVENTS

Termination of Derivative Instruments

On October 1, 2008, the Company received a notice of early termination from BNP with respect to the Company’s natural gas and interest rate swap derivatives (the “Early Termination Notice”) in accordance with the 1992 International Swap Dealers Association, Inc. (“ISDA”) master agreement dated August 20, 2007 between the Company and BNP. The Early Termination Notice references Sections 6(a) and 6(b) of the ISDA master agreement which gives BNP the right to terminate following an event of default. The settlement amount in connection with the Early Termination notice amounted to approximately $1.6 million for the interest rate swap derivative and $0.6 million for the natural gas derivatives. The total settlement amount due in the approximate amount of $2.2 million was payable on or before October 2, 2008. As of September 30, 2008 the Company has recorded $1.7 million of the $2.2 settlement amount as a current liability. On October 1, 2008 the liability increased by $0.5 million and the entire $2.2 million was classified as a liability included with the senior secured credit facility. As a result of the natural gas derivative contracts termination, the Company is presently exposed to the fluctuation of natural gas prices.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 13. SUBSEQUENT EVENTS (continued)

Senior Secured Credit Facility

On October 3, 2008 the Company received a notice of default from BNP with respect to the senior secured credit facility (the “Notice of Default”). The Notice of Default states that an event of default occurred under (1) Section 10.01(a) of the senior secured credit facility due to the Company’s failure to pay the first of three principal borrowing base deficiency payments in the approximate amount of $6.6 million, (2) Section 10.01(g) of the senior secured credit facility due to the swap termination amount in connection with the Early Termination Notice exceeding $500,000, (3) Section 10.01(f) of the senior secured credit facility due to the Company’s failure to pay the settlement amount of approximately $2.2 million by the due date of October 2, 2008 in connection with the Early Termination Notice, and (4) Sections 8.14, 8.18 and 9.01 of the senior secured credit facility and second lien term loan (cross default) due to the Company’s failure to comply with certain financial and non-financial covenants.

The Notice of Default informed the Company, as of October 1, 2008 that the interest rate under the senior secured credit facility shall bear interest at the default rate thereby increasing the Company’s current interest rate under the senior secured credit facility by 2% to approximately 8.0%.

Second Lien Term Loan

On October 6, 2008 the Company received a notice of default from Laminar with respect to the second lien term loan (the “Term Loan Notice of Default”). The Term Loan Notice of Default states that an event of default occurred under (1) Section 10.01(g) of the second lien term loan due to the swap termination amount in connection with the Early Termination Notice exceeding $500,000, (2) Section 10.01(f) of the second lien term loan due to the Company’s failure to pay the settlement amount of approximately $2.2 million by the due date of October 2, 2008 in connection with the Early Termination Notice, (3) Sections 8.14, 8.18 and 9.01 of the second lien term loan and the senior secured credit facility (cross default) due to the Company’s failure to comply with certain financial and non-financial covenants, and (4) Section 10.01(f) and (g) of the second lien term loan due to the Company’s failure to pay the first of three principal borrowing base deficiency payments in the approximate amount of $6.6 million under Section 10.01(a) of the senior secured credit facility (cross default). Laminar and the syndicate under the second lien term loan cannot take any enforcement or similar actions against the Company or its property for at least 180 days pursuant to the terms of the Intercreditor Agreement, dated August 20, 2007 between the second lien term loan syndicate and the senior secured credit facility syndicate.

The Term Loan Notice of Default also informed the Company, as of October 1, 2008, that the interest rate under the second lien term loan shall bear interest at the default rate thereby increasing the Company’s current interest rate under the Term Loan by 2% to approximately 15.5%.

Other

The Company has decided not to proceed with the acquisition of Acadian. As a result, Acadian acquisition costs initially capitalized in the amount of $0.2 million were recorded as a general and administrative expense as of September 30, 2008. In addition, all amounts paid on behalf of Acadian by the Company pursuant to the operating agreements more fully described in Note 12 “Related Party Transactions” have been recorded as a receivable at September 30, 2008.

Effective October 23, 2008, 280,000 shares of common stock granted to each of the non-employee directors during May 2008 under the 2006 Stock Incentive Plan were rescinded by agreement of the Company and those directors.

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

You should read the following discussion in conjunction with management’s discussion and analysis contained in our 2007 Annual Report on Form 10-K/A and subsequent reports on Forms 10-Q and 8-K, as well as the condensed consolidated financial statements and notes hereto included in this quarterly report on Form 10-Q. The following discussion contains forward-looking statements that involve risks, uncertainties, and assumptions, such as statements of our plans, objectives, expectations, and intentions. Our actual results may differ materially from those discussed in these forward-looking statements because of the risks and uncertainties inherent in future events.

Overview

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

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

Highlights

As of September 30, 2008, our leasehold acres were 1,167,405 (655,070 net) which represent an 8% decrease over our December 31, 2007, net acres. This decrease primarily resulted from the sale of our Oak Tree Project in September 2008 which accounted for all of our acreage within the Woodford shale play located in Oklahoma. Our remaining leasehold acres are included in the following plays: 287,296 (134,278 net) leasehold acres in the Michigan Antrim shale play, 15,837 (15,837 net) leasehold acres in the Indiana Antrim shale play, 779,210 (440,861 net) acres in the New Albany shale play, and 85,062 (64,094 net) acres in the other play areas.

With regard to our drilling activities, we drilled or participated in 20 (4 net) wells for the nine months ended September 30, 2008, with a 75% success rate. As of September 30, 2008, we had 622 (277 net) producing wells, 19 (10 net) wells awaiting hook-up, 32 (9 net) wells undergoing resource assessment, and 51 (37 net) wells temporarily abandoned. We are currently operating 234 (214 net) wells or 32% of our gross wells and 64% of our net wells.

Of the 214 net wells we operate, 166 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 awaiting hook-up in the New Albany; 4 net wells are undergoing resource assessment in the other plays; and 36 net wells are temporarily abandoned.

Oil and natural gas production for the nine months ended September 30, 2008, was 2,324,339 mcfe, a 1% decrease from the 2,335,198 mcfe produced for the nine months ended September 30, 2007. For the nine months ended September 30, 2008, production continues to be hampered by wells undergoing resource assessment and dewatering in the Antrim along with damages caused by a fire in our South Knox project. 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 70 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 re-fracturing. This project is expected to continue through the end of 2008 with an anticipated completion date in early 2009.

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Effective September 12, 2008, we closed on an agreement for the sale to Presidium Energy, LC (“Presidium”) of all our membership interest in a wholly owned subsidiary, AOK Energy, LLC (“AOK”). We participated in a joint venture project known as the “Oak Tree Project” through AOK. Presidium is wholly owned and operated by John V. Miller, who served as our Vice President from November 1, 2005 until he resigned on February 29, 2008. Total sales price was $15 million, of which we received $3 million in cash and entered into a note receivable in the amount of $12 million. Under the terms of the note receivable, Presidium is required to make monthly interest only payments calculated at 9.0%. The entire outstanding principal balance along with all accrued interest is due September 10, 2010. In connection with the sale, we also received a 3% overriding royalty interest in certain oil and gas leases located in various counties in Oklahoma.

(Intentionally Left Blank)

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Operating Statistics

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2008			2007		2008			2007
Net wells drilled
Antrim shale		1			17		2			29
New Albany shale (“NAS”)		-			5		-			9
Other		-			2		1			10
Dry		-			2		1			6
Total		1			26		4			54
Total net wells
Antrim—producing		260			283		260			283
Antrim—awaiting hookup		3			10		3			10
NAS—producing		1			4		1			4
NAS—awaiting hookup		6			3		6			3
Other—producing		16			13		16			13
Other—awaiting hookup		1			2		1			2
Total		287			315		287			315
Production
Natural gas (mcf)		699,032			798,540		2,205,192			2,209,360
Crude oil (bbls)		6,373			7,201		19,858			20,973
Natural gas equivalent (mcfe)		737,271			841,746		2,324,339			2,335,198
Average daily production
Natural gas (mcf)		7,598			8,680		8,048			8,093
Crude oil (bbls)		69			78		72			77
Natural gas equivalent (mcfe)		8,014			9,149		8,483			8,555
Average sales price (excluding all gains (losses) on derivatives)
Natural gas ($ per mcf)	$	10.02		$	6.11	$	9.72		$	6.91
Crude oil ($ per bbls)	$	112.82		$	74.71	$	111.19		$	63.08
Natural gas equivalent ($ per mcfe)	$	10.62		$	6.43	$	10.22		$	7.10
Average sales price (including all gains (losses) from derivatives)
Natural gas ($ per mcf)	$	9.93		$	8.04	$	8.47		$	8.22
Crude oil ($ per bbls)	$	112.82		$	74.71	$	111.19		$	63.08
Natural gas equivalent ($ per mcfe)	$	10.39		$	8.26	$	8.99		$	8.35
Production revenue ($ in thousands)
Natural gas	$	7,004		$	4,877	$	21,443		$	15,266
Natural gas derivatives—realized (losses) gains		(1,280	)		1,542		(2,853	)		2,900
Natural gas derivatives—unrealized gains		1,215			-		98			-
Crude oil		719			538		2,208			1,323
Total	$	7,658		$	6,957	$	20,896		$	19,489

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008			2007
Average expenses ($ per mcfe)
Production taxes	$	0.51	$	0.31	$	0.48		$	0.36
Post-production expenses	$	1.00	$	0.53	$	0.87		$	0.53
Lease operating expenses	$	2.47	$	1.95	$	2.52		$	2.13
General and administrative expense	$	3.76	$	2.18	$	2.83		$	2.60
General and administrative expense excluding stock-based compensation	$	3.29	$	1.47	$	2.21		$	1.83
Oil and natural gas depletion and amortization expenses	$	1.19	$	0.86	$	1.20		$	0.96
Other assets depreciation and amortization	$	0.40	$	0.75	$	0.37		$	0.76
Interest expenses	$	2.74	$	1.48	$	2.26		$	1.41
Taxes	$	0.04	$	0.11	$	(0.01	)	$	0.04
Number of employees including Bach		65		88		65			88

Results of Operations

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

General. For the Current Quarter, we had a net loss of $16.7 million, or $(0.16) diluted common share, on total revenues of $9.4 million. This compares to a net loss of $3.3 million, or $(0.03) per diluted common share, on total revenue of $7.2 million for the Prior Year Quarter. The $13.5 million increase in net loss is primarily attributable to goodwill write-off in the amount of $16.0 million. The write-off was offset by an increase in revenue in the amount of $2.2 million which is primarily attributable to increases in natural gas prices along with increases in field services revenues.

Oil and Natural Gas Sales. During the Current Quarter, oil and natural gas sales were $7.7 million compared to $7.0 million in the Prior Year Quarter. We produced 737,271 mcfe at a weighted average price of $10.39 compared to 841,746 mcfe at a weighted average price of $8.26. The increase in oil and gas sales was primarily the result of increases in sales price. We had 277 net wells producing as of September 30, 2008, as compared to 300 net wells producing as of September 30, 2007. The decrease in producing net wells is attributable to our effort of reducing operating expenses by shutting in various uneconomical wells. The weighted average price included $1.3 million or $1.74 per mcfe of realized losses from the gas derivative contract for the Current Quarter, and $1.5 million or $1.90 per mcfe of realized gains from the gas derivative contract for the Prior Year Quarter. For the Current Quarter, we also recognized $1.2 million or $1.65 per mcfe of unrealized gains from hedge ineffectiveness.

Production from the Antrim shale play represented approximately 88% of our oil and natural gas revenue for the Current Quarter. The following table summarizes our oil and natural gas revenue by play/trend in the periods set forth below:

Play/Trend	Three Months Ended September 30, 2008				Three Months Ended September 30, 2007
	(mcfe)		Amount		(mcfe)		Amount
Antrim		676,762	$	6,706,868		780,834	$	6,309,185
New Albany		20,954		218,915		14,351		90,498
Other		39,555		732,182		46,561		557,386
Total		737,271	$	7,657,965		841,746	$	6,957,069

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Production from the Prior Year Quarter compared to the Current Quarter decreased by 12%. Lower than expected production resulted from Warner Plant outages, damage to our South Knox facility caused by fire, 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 $0.2 million in the Current Quarter and Prior Year Quarter. This amount represents billings to royalty owners which are not expected to fluctuate significantly from quarter to quarter.

Field Service and Sales. Field service and sales revenues were $1.3 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 $0.2 million in the Current Quarter compared to $28,655 in the Prior Year Quarter. This increase is primarily attributed to billings to Presidium for interest on a note receivable attributable to our Oak Tree Project sale and consulting services performed which amounted to $0.1 million.

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 primarily attributed to us submitting one additional estimated payment of $0.1 million or $0.14 per mcfe in the Current Quarter to comply with state taxing requirements. On a unit of production basis, production taxes were $0.51 per mcfe in the Current Quarter compared to $0.31 per mcfe in the Prior Year Quarter representing an increase of production taxes by 44% in the Current Quarter from the Prior Year Quarter. This increase is primarily attributable to the increase in natural gas prices which determines the amount of production taxes charged for Michigan properties.

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 $2.6 million in the Current Quarter compared to $2.1 million in the Prior Year Quarter. On a per unit of production basis, production and lease operating expenses were $3.47 per mcfe in the Current Quarter compared to $2.48 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 charges amounting to $0.6 million or $0.81 per mcfe related to compression analysis and repair along with workover charges related to our well enhancement program.

On a component basis, post-production expenses were $0.7 million, or $1.00 per mcfe, in the Current Quarter compared to $0.5 million, or $0.53 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. Lease operating expenses were $1.9 million, or $2.58 per mcfe, in the Current Quarter compared to $1.6 million, or $1.95 per mcfe, in the Prior Year Quarter. Increase in lease operating expenses were primarily related to one-time 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 $3.80 per mcfe in the Current Quarter while non-operated production and lease operating expenses were $2.92 per mcfe in the Current Quarter. Our operated Arrowhead, Black Bear East, Hudson West, and South Knox projects are negatively impacting our operating cost controls and efficiency due to dewatering in the Antrim play, and flooding and fire damages in our South Knox project. Production and lease operating expenses for operated properties excluding Arrowhead, Black Bear East, Hudson West and South Knox projects were $3.17 per mcfe in the Current Quarter.

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. We did not reclassify Prior Year Quarter amounts due to insignificance.

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Field Services Expenses. Field services expenses were $1.0 million in the Current Quarter compared to $0.1 million 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 increased by $0.9 million, or 51%, from the Prior Year Quarter. This increase was primarily the result of additional legal and consulting services and charge offs in connection with (1) refinancing efforts amounting to $0.4 million, (2) write-off of capitalized costs incurred investigating strategic alternatives amounting to $0.2 million, (3) write-off of acquisition costs associated with the Acadian letter of intent in the amount of $0.2 million as a result of our decision not to proceed with the acquisition, and (4) general legal costs incurred for corporate matters in the amount of $0.2 million. This increase was offset by a decrease in payroll and related costs by $0.1 million to $1.2 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 $0.1 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 $0.7 million during the Current Quarter and the Prior Year Quarter, respectively. DD&A is a function of capitalized costs in the full cost pool and related underlying reserves in the periods presented. This increase is the result of $0.9 million being added to proved properties in the full cost pool. The average DD&A cost per mcfe also increased to $1.19 in the Current Quarter compared to $0.86 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 $0.3 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 $2.0 million in the Current Quarter compared to $1.2 million in the Prior Year Quarter. This increase is due to the higher utilization of debt to develop 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 resulting in an additional $0.6 million of interest expense for the Current Quarter.

Taxes, Other.Other taxes primarily include state franchise 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. We are still subject to state income taxes, state business taxes and state franchise taxes. Tax expense was $29,005 in the Current Quarter compared to $0.1 million in the Prior Year Quarter.

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Nine Months Ended September 30, 2008, compared with Nine Months Ended September 30, 2007

General. For the Current Period, we had a net loss of $18.6 million, or $(0.18) per diluted common share, on total revenues of $23.9 million. This compares to a net loss of $3.8 million, or $(0.01) per diluted common share, on total revenue of $20.8 million for the Prior Year Period. The $14.9 million increase in net loss is primarily attributable to goodwill write-off in the amount of $16.0 million. The write-off was offset by an increase in revenue in the amount of $1.4 million primarily attributable to increases in natural gas prices along with increases in field services revenues.

Oil and Natural Gas Sales. During the Current Period, oil and natural gas sales were $20.9 million compared to $19.5 million in the Prior Year Period. We produced 2,324,339 mcfe at a weighted average price of $8.99 compared to 2,335,198 mcfe at a weighted average price of $8.35. This increase in oil and gas sales was the result of increases in sales price. We had 277 net wells producing as of September 30, 2008, as compared to 300 net wells producing as of September 30, 2007. The decrease in producing net wells is attributable to our effort to reduce operating expenses by shutting in various uneconomical wells. The weighted average price included $2.9 million or $1.23 per mcfe of realized losses from the gas derivative contract for the Current Period, and $2.9 million or $1.24 per mcfe of realized gains from the gas derivative contract for the Prior Year Period. For the nine months ended September 30, 2008, we also recognized $0.1 million or $0.04 per mcfe of unrealized gains from hedge ineffectiveness.

Production from the Antrim shale play represented approximately 86% 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:

Play/Trend	Nine Months Ended September 30, 2008				Nine Months Ended September 30, 2007
	(mcfe)		Amount		(mcfe)		Amount
Antrim		2,121,973	$	17,867,453		2,165,342	$	17,869,384
New Albany		81,764		806,758		37,724		264,259
Other		120,602		2,221,405		132,132		1,355,431
Total		2,324,339	$	20,895,616		2,335,198	$	19,489,074

Production from the Prior Year Period compared to the Current Period decreased by less than 1%. Lower than expected production resulted from Warner Plant outages, damage to our South Knox facility caused by a fire and flooding, 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 lower than expected production.

Pipeline Transportation and Processing. Pipeline transportation and processing revenues were $0.5 million in the Current Period and Prior Year Period. This amount represents billings to royalty owners which are not expected to fluctuate significantly from year-to-year.

Field Service and Sales. Field service and sales revenues were $2.0 million in the Current Period compared to $0.3 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 $0.5 million in the Current Period and Prior Year Period.

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Production Taxes. Production taxes were $1.1 million in the Current Period compared to $0.8 million in the Prior Year Period. This increase is attributed to the increase in natural gas prices which determines the amount of production taxes charged for Michigan properties and us submitting one additional estimated payment of $0.1 million or $0.04 per mcfe in the Current Period to comply with state taxing requirements. On a unit of production basis, production taxes were $0.48 per mcfe in the Current Period compared to $0.36 per mcfe in the Prior Year Period representing an increase of production taxes by 35% 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 $7.9 million in the Current Period compared to $6.2 million in the Prior Year Period. On a per unit of production basis, production and lease operating expenses were $3.39 per mcfe in the Current Period compared to $2.66 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 charges amounting to $1.1 million or $0.47 per mcfe related to compression analysis and repair along with workover charges related to our well enhancement program.

On a component basis, post-production expenses were $2.0 million, or $0.87 per mcfe, in the Current Period compared to $1.2 million, or $0.53 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. Lease operating expenses were $5.9 million, or $2.52 per mcfe, in the Current Period compared to $5.0 million, or $2.13 per mcfe, in the Prior Year Period. Increases in lease operating expenses were primarily related to one-time 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 $3.67 per mcfe in the Current Period while non-operated production and lease operating expenses were $2.87 per mcfe in the Current Period. Our operated Arrowhead, Black Bear East, Hudson West, and South Knox projects are negatively impacting our operating cost controls and efficiency due to dewatering, and flooding and fire damages in our South Knox project. 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, Black Bear East, Hudson West, and South Knox projects were $3.00 per mcfe in the Current Period.

Pipeline and Processing Operating Expenses. Pipeline and processing operating expenses were $0.4 million in the Current Period compared to $0.3 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. We did not reclassify Prior Year Period amounts due to insignificance.

Field Services Expenses. Field services expenses were $1.6 million in the Current Period compared to $0.3 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 increased by $0.5 million, or 8%, from the Prior Year Period. This increase was primarily the result of additional legal and consulting services and charge offs in connection with (1) refinancing efforts amounting to $0.4 million, (2) write-off of capitalized costs incurred investigating strategic alternatives amounting to $0.2 million, (3) write-off of acquisition costs associated with the Acadian letter of intent in the amount of $0.2 million as a result of our decision not to proceed with the acquisition, and (4) general legal costs incurred for corporate matters in the amount of $0.2 million. This increase was offset by a decrease in payroll and related costs by $0.2 million to $3.9 million in the Current Period due to lower employee payroll, bonus expense, and stock-based compensation along with a reduction in professional fees primarily related to reduced audit and Sarbanes Oxley fees in the amount of $0.3 million.

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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 $0.7 million of payroll and benefit costs for the Current Period compared to $1.1 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.

Oil and Natural Gas Depletion, Depreciation and Amortization (“DD&A”). DD&A of oil and natural gas properties was $2.8 million and $2.2 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 $8.4 million being added to proved properties in the full cost pool. The average DD&A cost per mcfe also increased to $1.20 in the Current Period compared to $0.96 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 $0.9 million in the Current Period compared to $1.8 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 $5.2 million in the Current Period compared to $3.3 million in the Prior Year Period. This increase is due to the higher utilization of debt to develop 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 resulting in an additional $0.8 million of interest expense for the Current Period.

Taxes, Other.Other taxes include state franchise taxes, state income taxes and state business taxes. We have significant net operating loss carryforwards, thus no federal income tax expense has been recognized for either the Current Period or Prior Year Period. There was a tax refund of $16,241 in the Current Period compared to tax expense of $0.1 million in the Prior Year Period. This decrease primarily represents a 2006 State of Louisiana income tax refund received during 2008.

Liquidity and Capital Resources

The Company’s financial statements for the nine months ended September 30, 2008, have been prepared on a going concern basis which contemplates the realization of assets and the settlement of liabilities in the normal course of business. With the loss of production and significant deficiencies in working capital along with an increase in interest rates and the termination of our natural gas and interest rate derivatives more fully described in the following paragraphs, our operations and existing cash balances are not sufficient to support interest requirements on existing debt balances for longer than one year. We are currently in default under the senior secured credit facility and second lien term loan more fully described in the following paragraphs. We recognize our continued existence is dependent on (1) lenders’ willingness to refrain from accelerating or demanding repayment on current debt obligations, (2) restructuring of our current debt, (3) securing alternative financing arrangements, and/or (4) asset divestitures. We continue discussions with existing lenders and are seeking alternative financing arrangements and opportunities for asset divestitures. Due to the recent events within the banking industry we are having difficulty securing alternative financing arrangements. There is no assurance the lenders will not call the debt obligation or that we will be able to restructure or refinance our current debt or sell assets in an amount sufficient to remedy our loan defaults.

On October 1, 2008, we received a notice of early termination from BNP with respect to our natural gas and interest rate swap derivatives (the “Early Termination Notice”) in accordance with the 1992 International Swap Dealers Association, Inc. (“ISDA”) master agreement dated August 20, 2007, between us and BNP. The Early Termination Notice references Sections 6(a) and 6(b) of the ISDA master agreement which gives BNP the right to terminate following an event of default. The settlement amount in connection with the Early Termination Notice amounted to approximately $1.6 million for the interest rate swap derivative and $0.6 million for the natural gas derivatives. The total settlement amount due in the approximate amount of $2.2 million was payable on or before October 2, 2008. As of the filing of this Form 10-Q we have not paid the $2.2 million liability and instead have included the amount in our debt balance. As a result of the natural gas derivative contracts termination, we are presently exposed to the fluctuation of natural gas prices.

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Senior Secured Credit Facility

Our senior secured credit facility is a $100 million senior secured credit facility with BNP. In connection with the second lien term loan, we also agreed to the amendment and restatement of our senior secured credit facility with BNP and other lenders, pursuant to which the borrowing base under the senior secured credit facility was increased from the 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 September 30, 2008, interest on the borrowings had a weighted average interest rate of 5.2%. 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 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. As of September 30, 2008, the syndication has liens on less than 90% of all our proved oil and gas properties and we are therefore not in compliance with a Forbearance Covenant. On August 15, 2008, the Forbearance and Amendment Agreement expired without extension, and therefore the syndication currently has the ability 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.

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On October 3, 2008, we received a notice of default from BNP with respect to the senior secured credit facility (the “Notice of Default”). The Notice of Default states that an event of default occurred under (1) Section 10.01(a) of the senior secured credit facility due to our failure to pay the first of three principal borrowing base deficiency payments in the approximate amount of $6.6 million, (2) Section 10.01(g) of the senior secured credit facility due to the swap termination amount in connection with the Early Termination Notice exceeding $500,000, (3) Section 10.01(f) of the senior secured credit facility due to our failure to pay the settlement amount of approximately $2.2 million by the due date of October 2, 2008 in connection with the Early Termination Notice, and (4) Sections 8.14, 8.18 and 9.01 of the senior secured credit facility and second lien term loan (cross default) due to our failure to comply with certain financial and non-financial covenants.

The Notice of Default informed us, as of October 1, 2008, that the interest rate under the senior secured credit facility shall bear interest at the default rate thereby increasing our current interest rate under the senior secured credit facility by 2% to approximately 8.0%.

Since the expiration of the Standstill Period, we continue to engage in discussions with BNP and the syndicate to restructure our debt. As of the filing of this Form 10-Q, other than the actions taken by BNP described previously, BNP has not made any attempt to accelerate or demand payment on the senior secured credit facility or taken any other remedial or enforcement action. We recognize that the senior secured credit facility is due and payable upon notification from BNP, and therefore the entire outstanding debt has been classified as a current liability on the September 30 2008, balance sheet. In addition to discussions with BNP and the syndicate, we are also seeking alternative financing arrangements and opportunities for asset divestitures. There is no assurance that BNP and the syndicate will not accelerate or demand repayment of the senior secured credit facility or that we will be successful in restructuring our debt, finding alternative financing arrangements, or selling company assets in an amount sufficient to remedy our loan defaults.

Second Term Lien Loan

On August 20, 2007, we entered into a second lien term loan agreement with BNP, as the arranger and administrative agent, and several other lenders forming a syndicate. During August 2008 we were notified that Laminar Direct Capital, LLC (“Laminar”) succeeded BNP as the arranger and administrative agent for the second term lien loan. The initial term loan is $50 million for a 5-year term which may increase up to $70 million under certain conditions over the life of the loan facility. The proceeds of the second lien term loan were used to payoff our existing mezzanine financing with TCW and for general corporate purposes.

Interest under the second lien term loan is payable at rates based on the London Interbank Offered Rate plus 950 basis points (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 may 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.

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. As of September 30, 2008, the syndication for the second lien term loan has liens on less than 90% of all our proved oil and gas properties and we are therefore not in compliance with a Forbearance Covenant. On August 15, 2008 the Term Loan Forbearance and Amendment Agreement expired without extension and therefore the syndication currently has the ability 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.

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On October 6, 2008 we received a notice of default from Laminar with respect to the second lien term loan (the “Term Loan Notice of Default”). The Term Loan Notice of Default states that an event of default occurred under (1) Section 10.01(g) of the second lien term loan due to the swap termination amount in connection with the Early Termination Notice exceeding $500,000, (2) Section 10.01(f) of the second lien term loan due to our failure to pay the settlement amount of approximately $2.2 million by the due date of October 2, 2008 in connection with the Early Termination Notice, (3) Sections 8.14, 8.18 and 9.01 of the second lien term loan and the senior secured credit facility (cross default) due to our failure to comply with certain financial and non-financial covenants, and (4) Section 10.01(f) and (g) of the second lien term loan due to our failure to pay the first of three principal borrowing base deficiency payments in the approximate amount of $6.6 million under Section 10.01(a) of the senior secured credit facility (cross default). Laminar and the syndicate under the second lien term loan cannot take any enforcement or similar actions against us or our property for at least 180 days pursuant to the terms of the Intercreditor Agreement, dated August 20, 2007 between the second lien term loan syndicate and the senior secured credit facility syndicate.

The Term Loan Notice of Default also informed us, as of October 1, 2008, that the interest rate under the second lien term loan shall bear interest at the default rate thereby increasing our current interest rate under the Term Loan by 2% to approximately 15.5%.

Since the expiration of the Standstill Period, we continue to engage in discussions with Laminar and the syndicate to restructure our debt. As of the filing of this Form 10-Q, other than the actions taken by Laminar described previously, Laminar has not made any attempt to accelerate or demand payment on the second lien term loan or taken any other remedial or enforcement action. We recognize that the second term lien loan is due and payable upon notification from Laminar, and therefore the entire outstanding debt has been classified as a current liability on the September 30, 2008 balance sheet. In addition to discussions with Laminar and the syndicate, we are also seeking alternative financing arrangements and opportunities for asset divestitures. There is no assurance that Laminar and the syndicate will not accelerate or demand repayment of the second term lien loan or that we will be successful in restructuring our debt, finding alternative financing arrangements, or selling company assets in an amount sufficient to remedy our loan defaults.

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Cash Flows from Operating Activities

Cash provided by operating activities decreased $4.9 million or 53% to $4.4 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 decreased by $0.9 million as a result of complete amortization of certain intangibles in January 2008, write-off of debt issuance costs related to TCW mezzanine debt refinanced during August 2007, and less stock awards granted during 2008. Non-cash charge of goodwill impairment increased by $16.0 million due to the write-off of goodwill associated with Cadence acquisition. Changes in current operating assets and liabilities decreased cash flow from operations by $2.7 million which is primarily related to a significant amount of collections from joint venture partners during 2007 as opposed to 2008 due to our significant reduction in drilling efforts for 2008.

Cash Flows Used in Investing Activities

Cash flows used in investing activities was $10.7 million in the Current Period compared to $52.1 million in the Prior Year Period. The following table describes our significant investing transactions that we completed in the periods set forth below:

	Nine Months Ended September 30,
	2008		2007
Acquisitions of leasehold
Michigan Antrim shale	$	556,094	$	1,206,400
Indiana Antrim shale		3,018		464,190
New Albany shale		625,664		3,074.492
Woodford shale		456,236		4,451,072
Other		17,969		118,155
Drilling and development of oil and natural gas properties
Michigan Antrim shale		1,449,827		18,983,846
Indiana Antrim shale		11,994		1,309,324
New Albany shale		1,031,119		7,682,040
Other		827,249		1,484,745
Infrastructure properties
Michigan Antrim shale		51,807		9,347,451
New Albany shale		1,861,915		277,971
Other		-		10,439
Capitalized interest and general and administrative costs on exploration, development and leasehold		3,972,593		3,984,154
Acquisitions of oil and natural gas properties		-		2,405,609
Acquisitions/additions for pipeline, property, and equipment		105,697		1,290,037
Other, net		12,206		78,970
Redesignation of cash equivalents to short-term investments		2,871,010		-
Subtotal of capital expenditures		13,854,398		56,168,895
Sale of oil and natural gas properties		3,191,043		2,079,518
Sale and leaseback of gas compression equipment		-		1,202,000
Sales of other investment and other		12,334		763,731
Subtotal of capital divestitures		3,203,377		4,045,249
Total	$	10,651,021	$	52,123,646

Cash Flows Provided by Financing Activities

Cash flows provided by financing activities were $14.0 million in the Current Period compared to $41.8 million in the Prior Year Period. Cash flows provided in the Current Period included: (1) $13.8 million of senior secured borrowing; (2) $0.4 million of capital contributions from minority interest members; (3) $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 $0.2 million in mortgage and notes payable obligations; and (2) payment of $0.7 million in financing fees.

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Cash flows provided by financing activities in the Prior Year Period included: (1) $42.0 million of senior secured credit borrowing; (2) $50.0 million of second lien term loan borrowing; (3) $16.2 million of short-term bank borrowings; and (4) $0.1 million in proceeds from exercise of options and warrants. Cash flows used by financing in the Prior Year Period included: (1) net pay-down of $16.8 million within short-term bank borrowings; (2) pay down of $40.0 million in mezzanine financings; (3) pay down of $6.0 million in senior credit borrowings; (4) pay-down of $0.3 million in mortgage and notes payable obligations; (5) payments of $1.7 million in financing fees; and (6) payment of $1.9 million in prepayment penalties.

Recent Accounting Pronouncements

Reference is made to Note 5 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 11 “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 previously entered into various derivative instruments with BNP. On October 1, 2008, we received a letter of termination for all our natural gas derivative instruments from BNP. 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. Since BNP has terminated all of our natural gas derivatives, we are presently exposed to the fluctuation of natural gas prices. Based on current production levels, a $0.50 increase or decrease in natural gas prices would have the effect of causing $0.4 million addition or reduction to our monthly production revenue.

Interest Rate Risk

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

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

	Expected Maturity		Average Interest Rate as of September 30, 2008			Principal Outstanding
Obligations under capital lease		01/10/09		8.25	%	$	3,258
Notes payable		08/01/07-04/25/11		6.50% - 7.50	%		323,267
Mortgage payable		10/15/09		Fixed at 6.00	%		359,752
Mortgage payable		11/01/08		Fixed at 5.95	%		2,640,062
Mortgage payable		10/01/11		Fixed at 6.00	%		70,000
Second lien term loan		02/01/11		Default at 15.50%	(a)		50,393,750
Senior secured credit facility		01/31/10		Default at 7.00%	(a)		69,800,000
Total debt						$	123,590,089

(a) Current default rate as of November 5, 2008.

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 September 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.

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 11 on page 29 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 September 30, 2008.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

Our annual meeting of the shareholders was held on August 29, 2008. At the meeting, each of the Company’s nominees for Board of Directors, as listed in the proxy statement, was elected with the number of votes set forth below.

Name	For	Withheld
William W. Deneau	72,866,320	1,947,963
Richard M. Deneau	72,815,570	1,998,713
John E. McDevitt	72,795,184	2,019,099
Gary J. Myles	72,865,560	1,948,723
Wayne G. Schaeffer	72,865,185	1,949,098
Kevin D. Stulp	72,864,185	1,950,098
Earl V. Young	69,719,941	5,094,342

At the meeting, the Board’s appointment of Weaver and Tidwell, L.L.P. as our independent registered accounting firm for the year ending December 31, 2008, was ratified by the shareholders, with 73,698,713 shares cast in favor of the motion, 735,694 shares against, and 379,877 shares abstaining.

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.)

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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.
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

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*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.

(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: November 7, 2008	By:	/s/ William W. Deneau
		Name: William W. Deneau
		Title: Chief Executive Officer
Date: November 7, 2008	By:	/s/ Barbara E. Lawson
		Name: Barbara E. Lawson
		Title: Chief Financial Officer

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