Aurora Oil & Gas 10-Q 2007 Q3 Quarterly report

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2007

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

FOR THE TRANSITION PERIOD FROM ___________ TO _____________.

Commission file number: 000-25170

AURORA OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

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

4110 Copper Ridge Dr, Suite 100

Traverse City, Michigan 49684

(Address of principal executive offices)

(231) 941-0073

(Registrant’s telephone number, including area code)

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

Yes x  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.

Large accelerated filer o  Accelerated filer o  Non-accelerated filer x

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

Yes o  No x

The number of shares of the registrant’s common stock outstanding as of October 31, 2007, was 101,679,456.

FORM 10-Q

INDEX

PART I	FINANCIAL INFORMATION	1
Item 1.	Condensed Consolidated Financial Statements	2
Condensed Consolidated Balance Sheets as of September 30, 2007 (Unaudited), and December 31, 2006 (Audited)		2
Unaudited Statements of Operations for the Three and Nine Months Ended September 30, 2007, and 2006		4
Unaudited Statements of Shareholders’ Equity for the Nine Months Ended September 30, 2007, and 2006		5
Unaudited Statements of Cash Flows for the Nine Months Ended September 30, 2007, and 2006		6
Notes to Unaudited Condensed Consolidated Financial Statements		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 4.	Controls and Procedures	35
PART II	OTHER INFORMATION	36
Item 1.	Legal Proceedings	36
Item 1A.	Risk Factors	36
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 3.	Defaults Upon Senior Securities	36
Item 4.	Submission of Matters to a Vote of Security Holders	36
Item 5.	Other Information	36
Item 6.	Exhibits	36
Signatures		38

i

PART I

Cautionary Note Regarding Forward-Looking Statements

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

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

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

· uncertainties about the estimates of reserves;

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

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

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

· domestic demand for oil and natural gas;

· drilling and operating risks;

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

· changes in our drilling plans and related budgets; and

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

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

Certain Definitions

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

1

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30, 2007 (Unaudited)			December 31, 2006 (Audited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	646,200		$	1,735,396
Accounts receivable
Oil and natural gas sales		3,867,365			4,082,231
Joint interest owners		767,331			3,079,715
Notes receivable		-			341,698
Prepaid expenses and other current assets		739,836			251,093
Short-term derivative instruments		2,946,921			3,552,060
Total current assets		8,967,653			13,042,193
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, using full cost accounting:
Proved properties		159,748,649			121,178,499
Unproved properties		55,528,241			42,024,648
Properties held for sale		-			8,896,568
Less: accumulated depletion and amortization		(12,873,483	)		(10,628,438	)
Total oil and natural gas properties, net		202,403,407			161,471,277
Pipelines, processing facilities, and compression		7,182,592			6,125,909
Other property and equipment		5,433,973			5,093,777
Less: accumulated depreciation		(1,348,879	)		(753,789	)
Total property and equipment, net		213,671,093			171,937,174
OTHER ASSETS:
Long-term derivative instruments		1,708,394			1,668,573
Goodwill		19,373,264			19,373,264
Intangibles (net of accumulated amortization of $4,110,003 and $2,946,250, respectively)		844,997			2,008,750
Other investments		925,893			985,706
Debt issuance costs (net of accumulated amortization of $241,895 and $892,535, respectively)		1,757,219			2,363,898
Other		972,531			1,007,634
Total other assets		25,582,298			27,407,825
TOTAL ASSETS	$	248,221,044		$	212,387,192

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, 2007 (Unaudited)			December 31, 2006 (Audited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	6,371,094		$	5,623,591
Accrued exploration, development, and leasehold costs		3,043,549			11,587,850
Short-term bank borrowings		-			542,788
Current portion of obligations under capital leases		6,697			8,868
Current portion of note payable		73,191			161,774
Current portion of mortgage payable		98,323			95,828
Current portion of asset retirement obligation		27,801			-
Drilling advances		318,673			19,383
Short-term derivative instruments		56,985			-
Total current liabilities		9,996,313			18,040,082
LONG-TERM LIABILITIES:
Obligations under capital leases, net of current portion		2,721			8,228
Asset retirement obligation		1,311,199			1,331,893
Notes payable		162,704			118,547
Mortgage payable		3,008,096			3,079,470
Senior secured credit facility		46,000,000			10,000,000
Second lien term loan		50,000,000			-
Mezzanine financing		-			40,000,000
Long-term derivative instruments		325,096			-
Other long-term liabilities		373,641			-
Total long-term liabilities		101,183,457			54,538,138
Total liabilities		111,179,770			72,578,220
Minority interest in net assets of subsidiaries		97,993			77,873
COMMITMENTS AND CONTINGENCIES (Note 9)
SHAREHOLDERS’ EQUITY
Common stock, $0.01 par value; authorized 250,000,000 shares; issued and outstanding 101,679,456 shares in 2007 and 101,412,966 shares in 2006		1,016,795			1,014,130
Additional paid-in capital		140,027,678			138,105,626
Accumulated other comprehensive income		4,273,234			5,220,633
Accumulated deficit		(8,374,426	)		(4,609,290	)
Total shareholders’ equity		136,943,281			139,731,099
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	248,221,044		$	212,387,192

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
	2007			2006			2007			2006
REVENUES:
Oil and natural gas sales	$	6,957,069		$	5,175,635		$	19,489,074		$	16,116,855
Pipeline transportation and processing		181,441			137,626			468,373			379,926
Field service and sales		66,878			-			316,480			-
Interest and other		28,655			12,803			503,413			194,434
Total revenues		7,234,043			5,326,064			20,777,340			16,691,215
EXPENSES:
Production taxes		262,127			210,435			829,096			656,261
Production and lease operating expenses		2,091,066			1,373,180			6,217,766			4,226,553
Pipeline and processing operating expenses		82,986			70,042			260,788			207,527
Field services expense		58,000			-			258,096			-
General and administrative expenses		1,834,718			2,046,497			6,068,419			5,289,210
Oil and natural gas depletion and amortization		721,585			896,920			2,245,045			2,907,303
Other assets depreciation and amortization		628,983			509,091			1,771,087			1,522,874
Interest expense		1,244,363			2,279,760			3,294,766			5,843,914
Loss on debt extinguishment		3,448,520			-			3,448,520			-
Taxes, other		95,773			9,928			95,720			39,289
Total expenses		10,468,121			7,395,853			24,489,303			20,692,931
LOSS BEFORE MINORITY INTEREST		(3,234,078	)		(2,069,789	)		(3,711,963	)		(4,001,716	)
MINORITY INTEREST IN INCOME OF SUBSIDIARIES		(20,216	)		(16,445	)		(53,173	)		(34,364	)
NET LOSS	$	(3,254,294	)	$	(2,086,234	)	$	(3,765,136	)	$	(4,036,080	)
NET LOSS PER COMMON SHARE—BASIC and DILUTED	$	(0.03	)	$	(0.03	)	$	(0.04	)	$	(0.05	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING—BASIC and DILUTED		101,629,673			82,042,049			101,611,357			78,043,518

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,
	2007						2006
	Shares			Amount			Shares		Amount
COMMON STOCK:
Balance, beginning		101,412,966		$	1,014,130			61,536,261	$	615,363
Cashless exercise of stock options and warrants		78,158			782			3,280,105		32,801
Conversion of redeemable convertible preferred stock to common stock		-			-			34,984		349
Exercise of stock options and warrants		263,332			2,633			15,673,457		156,735
Issuance of stock to officers and directors in lieu of compensation		-			-			90,000		900
Issuance of stock to related parties in lieu of commission relating to exercise of warrants		-			-			1,469,860		14,699
Adjustment to stock ledger		(75,000	)		(750	)		-		-
Balance, ending		101,679,456			1,016,795			82,084,667		820,847
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning					138,105,626					58,670,698
Cashless exercise of stock options and warrants					(782	)				(32,801	)
Conversion of redeemable convertible preferred stock to common stock					-					59,576
Costs of equity offerings					(10,096	)				-
Stock-based compensation					1,969,314					1,909,871
Exercise of stock options and warrants					109,866					18,030,714
Issuance of stock to officers and directors in lieu of compensation					-					348,300
Issuance of stock to related party in lieu of commission relating to exercise of warrants					-					(14,699	)
Adjustment to stock ledger					(146,250	)				-
Balance, ending					140,027,678					78,971,659
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Balance, beginning					5,220,633					-
Changes in fair value of derivative instruments					1,983,812					6,991,488
Recognition of gain on derivative instruments					(2,931,211	)				(1,794,650	)
Balance, ending					4,273,234					5,196,838
ACCUMULATED DEFICIT:
Balance, beginning					(4,609,290	)				(2,660,134	)
Dividends accrued on redeemable convertible preferred stock					-					(4,509	)
Net loss					(3,765,136	)				(4,036,080	)
Balance, end					(8,374,426	)				(6,700,723	)
TOTAL SHAREHOLDERS’ EQUITY				$	136,943,281				$	78,288,621

 

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,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(3,765,136	)	$	(4,036,080	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization		4,016,132			4,430,177
Amortization of debt issuance costs		641,996			598,293
Accretion of asset retirement obligation		50,095			53,708
Loss on debt extinguishment		3,448,520			-
Stock-based compensation		1,799,498			1,349,177
Equity loss of other investments and other		(323,801	)		245,924
Realized gain on sale of other investments		(418,147	)		-
Minority interest income of subsidiaries		53,173			34,364
Changes in operating assets and liabilities, net of effects of merger:
Accounts receivable – oil and natural gas sales		214,866			(158,885	)
Accounts receivable – joint interest owners		2,656,077			170,533
Drilling advance – liabilities		299,290			361,914
Notes receivable		221,788			20,720
Prepaid expenses and other assets		(133,609	)		(64,986	)
Accounts payable and accrued liabilities		521,144			(146,689	)
Net cash provided by operating activities		9,281,886			2,858,170
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and natural gas properties		(43,079,970	)		(28,731,647	)
Leasehold expenditures, net		(9,314,309	)		(23,995,320	)
Acquisition of oil and natural gas properties		(2,405,609	)		(24,004,616	)
Sale of oil and natural gas properties		2,079,518			11,492,817
Sale and leaseback of gas compression equipment		1,202,000			-
Acquisitions/additions of pipeline, property, and equipment		(1,290,037	)		(3,985,358	)
Additions in other investments		(78,970	)		(577,088	)
Sales of other investments		763,731			165,082
Net cash used in investing activities		(52,123,646	)		(69,636,130	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term bank borrowings		16,212,822			4,430,000
Short-term bank payments		(16,755,610	)		(7,030,000	)
Advances on senior secured credit facility		42,000,000			45,000,000
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		(231,831	)		(55,878	)
Payments of financing fees on credit facilities		(1,667,909	)		(2,386,613	)
Prepayment penalties on debt extinguishment		(1,866,580	)		-
Capital contributions from minority interest members		16,786			-
Distributions to minority interest members		(49,839	)		-
Proceeds from exercise of options and warrants		112,499			18,187,449
Dividends paid on preferred stock		-			(12,823	)
Other		(17,774	)		(335,508	)
Net cash provided by financing activities		41,752,564			57,796,627
Net decrease in cash and cash equivalents		(1,089,196	)		(8,981,333	)
Cash and cash equivalents, beginning of the period		1,735,396			11,980,638
Cash and cash equivalents, end of the period	$	646,200		$	2,999,305

6

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited-continued)

Nine Months Ended September 30,
2007	2006

NONCASH FINANCING AND INVESTING ACTIVITIES:
Oil and natural gas properties asset retirement obligation	$	(40,710	)	$	936,966
Accrued exploration and development costs on oil and natural gas properties		2,924,760			3,368,953
Accrued leasehold costs		118,789			103,152
Pipeline acquisition, transfer of investment to pipeline assets		-			1,100,973
Oil and natural gas properties capitalized stock-based compensation		169,816			560,694
Oil and natural gas properties acquisition through other long-term liability		600,000			-
Conversion of redeemable convertible preferred stock to common stock		-			59,925
Conversion of accounts receivable to long-term notes receivable		25,719			171,074
Vehicle purchase through financing		118,526			-
SUPPLEMENTAL INFORMATION OF INTEREST AND INCOME TAXES PAID:
Interest, net of amount capitalized of $3,083,417 and $677,682, respectively	$	2,217,526		$	4,741,182
Income taxes		107,700			5,563

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

Effective May 11, 2006, Cadence Resources Corporation (“Cadence”) and its wholly owned subsidiaries (collectively, the “Company”) amended its articles of incorporation to change its name to Aurora Oil & Gas Corporation (“AOG”). The Company is engaged in the exploration, acquisition, development, production, and sale of natural gas and crude oil. The Company generates most of its revenue from the production and sale of natural gas. The Company is currently focused on acquiring and developing operating interests in unconventional drilling programs in the Michigan Antrim shale, the New Albany shale of Indiana and Kentucky and the Woodford shale in Oklahoma.

The Company uses different strategies for natural gas sales depending on the location of the field and the local markets. In most cases, the Company connects to nearby high pressure transmission pipelines and utilizes a gas marketing firm for the sale of production. Effective June 1, 2007, the Company entered into a firm sales contract with Integrys Energy Services, Inc. (formerly WPS) for 5,000 mmbtu per day at MichCon city-gate for the period June 1, 2007, through December 31, 2008. Integrys Energy Services, Inc. is the Company’s primary marketing partner for the majority of Michigan operated properties. In addition, the Company has five other base contracts established primarily for future natural gas sales in Indiana and Michigan. The Company sets the firm delivery volume obligation under these contracts on either a monthly or a daily basis with the amount of the obligation varying from month to month or day to day. As new wells come online and production volume increases, new production will be sold under the base contracts on a spot market pricing structure.

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, and access to capital and on the quantities of natural gas and oil reserves that can be economically produced.

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

Basis of Presentation

The financial information included herein is unaudited, except the balance sheet as of December 31, 2006, which has been derived from our audited consolidated financial statements as of December 31, 2006. 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-KSB for the year ended December 31, 2006.

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)

Reclassifications

Certain reclassifications have been made to the condensed consolidated financial statements for the three and nine months ended September 30, 2006, in order to conform to the December 31, 2006, and September 30, 2007 presentation. These reclassifications had no effect on net loss or net cash flows as previously reported.

Principles of Consolidation

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

Use of Estimates

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

Asset Retirement Obligation

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

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

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)

Effective January 1, 2007, the accretion of the ARO on producing wells was adjusted for a change in the estimated life of the wells based on a reserve study prepared by an independent reserve engineering firm. The estimated life of the wells was increased by 10 years to an estimated life of 50 years per well. The accretion expense is included in interest expense and the depreciation expense is included in depreciation, depletion, and amortization in the consolidated statements of operations.

The following table sets forth a reconciliation of the Company’s ARO liability for the periods indicated:

Three Months Ended September 30,	2007		2006
Beginning balance	$	989,885	$	1,013,329
Liabilities incurred		168,162		106,763
Liabilities settled		-		(123,809	)
Accretion expense		18,983		16,722
Revisions of estimated liabilities		161,970		(22,301	)
Ending balance	$	1,339,000	$	990,704

Nine Months Ended September 30,	2007			2006
Beginning balance	$	1,331,893		$	812,634
Liabilities incurred		292,023			369,789
Liabilities settled		(34,293	)		(123,809	)
Accretion expense		50,095			53,708
Revisions of estimated liabilities		(300,718	)		(121,618	)
Ending balance	$	1,339,000		$	990,704

Natural Gas Derivative Instruments

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

The Company recognizes all derivative instruments as assets or liabilities in the balance sheet at fair value. The accounting treatment for changes in fair value, as specified in SFAS No. 133 “Accounting for Derivative Investments and Hedging Activities,” is dependent upon whether or not a derivative instrument is designated as a hedge. For derivatives designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in Accumulated Other Comprehensive Income on the accompanying balance sheet until the hedged item is recognized in earnings as natural gas revenue. If the hedge has an ineffective portion, that particular portion of the gain or loss would be immediately reported in earnings. The following natural gas contracts were in place as of September 30, 2007, and qualified as cash flow hedges:

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)

Period	Type of Contract		Natural Gas Volume per Day		Price per mmbtu		Fair Value Asset (Liability)
April 2007—December 2008		Swap		5,000 mmbtu		$ 9.00	$	2,657,646
April 2007—December 2008		Collar		2,000 mmbtu		$ 7.55/$ 9.00		171,880
January 2008 – December 2008		Swap		2,000 mmbtu		$ 8.41		275,486
January 2009—December 2009		Swap		7,000 mmbtu		$ 8.72		704,500
January 2010—March 2011		Swap		7,000 mmbtu		$ 8.68		914,838
April 2011 – September 2011		Swap		7,000 mmbtu		$ 7.62		(69,035	)
Total Estimated Fair Value							$	4,655,315

For the nine months ended September 30, 2007, the Company has recognized in Comprehensive Income changes in fair value of $2,334,862 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 three months ended September 30, 2007, and 2006, the Company recognized $1,541,930 and $1,002,300, respectively, in net gains from hedging activities included in oil and natural gas revenues. For the nine months ended September 30, 2007, and 2006, the Company recognized $2,900,180 and $1,794,650, respectively, in net gains from hedging activities included in oil and natural gas revenues.

Interest Rate Derivative Instruments

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

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

For the nine months ended September 30, 2007, the Company has recognized in Comprehensive Income (Loss) changes in fair value of $(351,050) on the interest rate swap. See “Comprehensive Income (Loss)” found in this note section. For the three and nine months ended September 30, 2007, the Company recognized $31,031 in interest savings related to the hedge activity which is recorded as an adjustment to interest expense.

Financial Instruments

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

11

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)

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. See Note 8 “Common Stock Options” which fully describes the Company’s stock-based compensation plans.

The following stock-based compensation was recorded for the periods indicated:

For the Three Months Ended September 30,	2007		2006
General and administrative expenses	$	597,742	$	957,028
Oil and natural gas properties		36,049		195,401
Total	$	633,791	$	1,152,429

For the Nine Months Ended September 30,	2007		2006
General and administrative expenses	$	1,799,498	$	1,349,177
Oil and natural gas properties		169,816		560,694
Total	$	1,969,314	$	1,909,871

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:

Three Months Ended September 30,	2007			2006
Net loss	$	(3,254,294	)	$	(2,086,234	)
Other comprehensive income:
Change in fair value of natural gas derivative instruments		3,434,811			5,237,123
Change in fair value of interest rate derivative instruments		(351,050	)		-
Comprehensive Income (Loss)	$	(170,533	)	$	3,150,889

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)

Nine Months Ended September 30,	2007			2006
Net loss	$	(3,765,136	)	$	(4,036,080	)
Other comprehensive income:
Change in fair value of natural gas derivative instruments		2,334,862			6,991,488
Change in fair value of interest rate derivative instruments		(351,050	)		-
Comprehensive Income (Loss)	$	(1,781,324	)	$	2,955,408

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 restricted stock grants, stock options, warrants, and redeemable convertible preferred stock. All dilutive securities were excluded in the computation of diluted loss per share for all periods indicated because their effect of assumed exercises or conversions was anti-dilutive and, accordingly, basic and dilutive weighted average shares are the same.

NOTE 3. RECENT ACCOUNTING PRONOUNCEMENTS

On February 15, 2007, the FASB issued SFAS No. 159, “Fair Value Option for Financial Assets and Financial Liabilities”—including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. The FASB believes the statement will improve financial reporting by providing companies the opportunity to mitigate volatility in reported earnings by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Use of the statement will expand the use of fair value measurements for accounting for financial instruments. The Company does not believe SFAS No. 159 will have a material impact on its consolidated financial statements.

NOTE 4. ACQUISITIONS AND DISPOSITIONS

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.

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.

13

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 4. ACQUISITIONS AND DISPOSITIONS (continued)

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.

2007 – Other Investments

From time to time, the Company has acquired and disposed of legacy Cadence stock investments and non-core working interests. For the nine months ended September 30, 2007, the Company recognized minor stock investments valued at approximately $250,000 and disposed of non-core working interests of approximately $310,000.

NOTE 5. OIL AND NATURAL GAS PROPERTIES HELD FOR SALE

During the second quarter of 2006, the Company identified $21.4 million of oil and natural gas properties as held for sale due to their high probability of being sold within a 12 month period. Through September 30, 2007, the Company completed $5.1 million in planned oil and natural gas properties sales consisting of four oil and natural gas properties located in Kansas, Louisiana, Ohio, and New Mexico. (See Note 4 “Acquisitions and Dispositions” for 2007 activity.) Under the full cost method, sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The Company will routinely focus attention on its oil and natural gas properties to ensure that its continued holdings are aligned with the Company’s long-term strategic plan. Management has removed properties held for sale from the balance sheet given the investigation of strategic alternatives currently being explored.

14

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6. DEBT

Short-Term Bank Borrowings

The Company has 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. The interest rate under the revolving line of credit is Wall Street prime (7.75% at September 30, 2007, and 8.25% at September 30, 2006) with interest payable monthly in arrears. Principal is payable at the expiration of the revolving line of credit agreement. Northwestern Bank also provides letters of credit for the Company’s drilling program (as described in Note 9 “Commitments and Contingencies”). These letters of credit may be extended or may be replaced upon their expiration dates by letters of credit under the Company’s senior secured credit facility. Interest expense on the Northwestern Bank revolving line for the three months ended September 30, 2007, and 2006, was $28,098 and $70,280, respectively. Interest expense on the Northwestern Bank revolving line for the nine months ended September 30, 2007, and 2006, was $34,980 and $248,734, respectively.

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

On October 6, 2006, Bach entered into a $175,100 revolving line of credit agreement with Northwestern Bank for general company purposes. Effective April 16, 2007, Northwestern Bank increased the borrowing capacity under the revolving line of credit to $0.5 million. This line of credit 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 (7.75% at September 30, 2007) with interest payable monthly in arrears. Principal is payable at the expiration of the revolving line of credit agreement. Northwestern Bank has extended the expiration date to October 1, 2008. Interest expense for the three and nine months ended September 30, 2007, was $955 and $2,298, respectively.

Mortgage and Notes Payable - Bach

As of September 30, 2007, Bach’s outstanding loans were as follows with interest expense for the periods indicated:

										Interest Expense
Description of Loan	Date of Loan		Maturity Date		Interest Rate			Principal Amount Outstanding		Three Months Ended September 30, 2007		Nine Months Ended September 30, 2007
Mortgage payable on building		10/06/06		10/15/09		6.00	%	$	372,531	$	3,966	$	15,310
Notes payable
Vehicles		10/06/06		10/01/10		7.50	%		71,947		1,452		4,657
Equipment		10/06/06		09/01/07		5.50	%		-		21		253
Vehicles		12/18/06		12/20/09		7.25	%		54,028		1,023		3,460
Vehicles		04/23/07		04/25/11		7.00	%		85,801		2,239		2,808
Vehicles		09/13/07		09/15/10		6.95	%		24,119		74		74
Total notes payable								$	235,895	$	4,809	$	11,252

15

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6. DEBT (continued)

Mortgage Payable

On October 4, 2005, the Company entered into a mortgage loan from Northwestern Bank in the amount of $2,925,000 for the purchase of an office condominium and associated interior improvements. The security for this mortgage is the office condominium real estate. The payment schedule is monthly interest only for the first 3 months starting on November 1, 2005, and, beginning on February 1, 2006, principal and interest in 32 monthly payments of $21,969 with one principal and interest payment of $2,733,994 on October 1, 2008. The interest rate is 6.5% per year. The maturity date is October 1, 2008. As of September 30, 2007, the principal amount outstanding was $2,733,888. Interest expense for the three months ended September 30, 2007, and 2006, was $60,454 and $46,956, respectively. Interest expense for the nine months ended September 30, 2007, and 2006, was $129,790 and $146,690, 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. A monthly payment of $15,807 was required beginning November 30, 2006, through August 1, 2007. The interest rate was 7.01% per year. Interest expense for the three and nine months ended September 30, 2007, was $273 and $2,546, respectively.

Second Lien Term Loan

On August 20, 2007, the Company entered into a second lien term loan agreement with BNP Paribas (“BNP”), as the arranger and administrative agent, and several other lenders forming a syndicate. The initial term loan is $50 million for a 5-year term (expires 8/20/12) which may increase up to $70 million under certain conditions over the life of the loan facility. The proceeds of the 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 loan is payable at rates based on the London Interbank Offered Rate (“LIBOR”) plus 700 basis points with a step-down of 25 basis points once the Company’s ratio of total indebtedness to earnings before interest, taxes, depreciation, depletion, amortization, and other non-cash charges is lower than or equal to a ratio of 4.0 to 1.0 on a trailing four quarters basis. The Company has the ability to prepay the loan during the first year at a price equal to 103% of par, during the second year at a price equal to 102% of par, and thereafter at a price equal to 100% of par.

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

In both the loan and senior secured credit facility, the Company agreed to an affirmative covenant regarding production exit rates with the first net production target being 9.5 MMcfe per day as of June 30, 2007, which the Company achieved. The second target production exit target is 10.5 MMcfe per day as of September 30, 2007 (which has been achieved), and the third production exit target is 12.0 MMcfe per day as December 31, 2007, and as of the last day of each quarter thereafter. In addition, the Company was required to purchase financial hedges at prices and aggregate notional volumes satisfactory to BNP, as administrative agent. This requirement has been satisfied.

16

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6. DEBT (continued)

For the three and nine months ended September 30, 2007, interest and fees incurred for the loan was $711,143. The Company has also incurred deferred financing fees of approximately $1.3 million with regard to the loan. The deferred financing fees are being amortized on a straight-line basis over the remaining terms of the loan obligation. Amortization expense for the loan is estimated to be $264,000 per year through 2011. 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. The following represents the expenditures paid to TCW: (i) $40 million payment of principal; (ii) $0.7 million payment of interest expense from June 27, 2007, through August 20, 2007; (iii) $0.36 million payment of interest make-whole provision from August 21, 2007, through September 27, 2007; (iv) $1.25 million payment of prepayment premium; and (v) $0.2 million payment for a make-whole provision on principal greater than $30 million.

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

For the three months ended September 30, 2007, and 2006, interest and fees incurred for the mezzanine credit facility was $638,471 and $1,175,417, respectively. For the nine months ended September 30, 2007, and 2006, interest and fees incurred for the mezzanine credit facility was $2,989,305 and $3,526,528, respectively. In addition, the Company completed a write-off $1.6 million of unamortized debt issuance cost associated with the mezzanine financing.

Senior Secured Credit Facility

On January 31, 2006, the Company entered into a $100 million senior secured credit facility with BNP and other lenders for drilling, development, and acquisitions, as well as other general corporate purposes. In connection with the second lien term loan discussed above, the Company also agreed to the amendment and restatement of the senior secured credit facility, pursuant to which the borrowing base under the senior secured credit facility was increased from the 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 semiannual 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.

17

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6. DEBT (continued)

This facility provides for borrowings tied to BNP’s prime rate (or, if higher, the federal funds effective rate plus 0.5%) or LIBOR-based rate plus 1.25% to 2.0% depending on the borrowing base utilization, as selected by the Company. The borrowing base utilization is the percentage of the borrowing base that is drawn under the senior secured credit facility from time to time. As the borrowing base utilization increases, the LIBOR-based interest rates increase under this facility. As of September 30, 2007, interest on the borrowings had a weighted average interest rate of 6.93%. For the three months ended September 30, 2007, and 2006, interest and fees incurred for the senior secured credit facility were $794,298 and $785,738, respectively. For the nine months ended September 30, 2007, and 2006, interest and fees incurred for the senior secured credit facility were $1,773,533 and $1,892,134, respectively. All outstanding principal and accrued and unpaid interest under the senior secured facility is due and payable on January 31, 2010. The maturity date of the outstanding loan may be accelerated by the lenders upon occurrence of an event of default under the senior secured credit facility.

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

The Company has incurred deferred financing fees of approximately $680,350 with regard to the senior secured credit facility. The deferred financing fees are being amortized on a straight-line basis over the remaining terms of the debt obligation. Amortization expense for the senior secured credit facility is estimated to be $202,000 per year through 2009. Amortization expense was $47,930 and $215,148 for the three months ended September 30, 2007, and 2006, respectively. Amortization expense was $114,031 and $598,293 for the nine months ended September 30, 2007, and 2006, respectively. In addition, the Company incurs various annual fees associated with unused commitment and agency fees. These annual fees are recorded to interest expense.

The Company capitalizes interest on debt related to expenditures made in connection with exploration and development projects that are not subject to the full cost amortization pool. Interest is capitalized only for the period that exploration activities are in progress. Interest is capitalized using a weighted average interest rate based on the outstanding borrowing and cost of equity of the Company. Capitalized interest was $1,225,728 and $30,705 for the three months ended September 30, 2007, and 2006, respectively. Capitalized interest was $3,083,417 and $677,682 for the nine months ended September 30, 2007, and 2006, respectively.

NOTE 7. SHAREHOLDERS’ EQUITY

Common Stock

From February 2007 through September 2007, 170,000 common stock options were exercised by various Company employees under the existing stock option plans at exercise prices ranging from $0.375 to $1.25 per share. The Company received $77,500 in conjunction with these exercises.

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.

18

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7. SHAREHOLDERS’ EQUITY (continued)

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 conjunction with these exercises.

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

Common Stock Warrants

The following table sets forth information related to stock warrant activity for the period indicated:

Nine Months Ended September 30, 2007	Number of Shares Underlying Warrants			Weighted Average Exercise Price		Weighted Average Contract Life in Years
Outstanding at the beginning of the period	2,079,500		$	1.71		1.98
Granted	-			-		-
Exercised	(78,158	)		(1.25	)	0.24
Forfeitures and other adjustments	(49,342	)		(1.25	)	0.24
Outstanding at the end of the period	1,952,000		$	1.74		1.34

NOTE 8. COMMON STOCK OPTIONS

As of September 30, 2007, the Company maintains four stock option plans that are fully described in Note 8 “Common Stock Options” in the Company’s Annual Report on Form 10-KSB for the year-ended December 31, 2006. 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 period indicated:

Nine Months Ended September 30, 2007	Number of Shares Underlying Options
Options outstanding at beginning of period	3,432,496
Options granted	185,000
Options exercised	(263,332	)
Options forfeited and other adjustments	(261,334	)
Options outstanding at end of period	3,092,830

19

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8. COMMON STOCK OPTIONS (continued)

The weighted average assumptions used in the Black-Scholes option-pricing model used to determine fair value of the option granted in the nine months ended September 30, 2007, were as follows:

Risk-free interest rate	4.67	%
Expected years until exercise	3.25-6.0
Expected stock volatility	71.41	%
Dividend yield	0	%

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. The following table sets forth activity with respect to all stock options awarded for the period indicated:

Nine Months Ended September 30, 2007		Number of Shares Underlying Options			Weighted Average Exercise Price		Aggregate  Intrinsic Value(a)
Options outstanding at beginning of period		4,862,776		$	2.23
Options granted		185,000			3.35
Options exercised		(263,332	)		0.43
Forfeitures and other adjustments		(261,334	)		4.68
Options outstanding at end of period		4,523,110		$	2.24	$	1,713,547
Exercisable at end of period		3,018,775		$	1.52	$	1,713,547
Weighted average fair value of options granted during period	$	1.20

(a)The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option. The intrinsic value of the options exercised during the nine months ended September 30, 2007, was approximately $267,000.

The following table provides the unrecognized compensation expense related to unvested stock options as of September 30, 2007. The expense is expected to be recognized over the following 3-year period.

Period to be Recognized		2007		2008		2009		2010		Total Unrecognized Compensation Expense
1st Quarter	$	-	$	441,781	$	37,255	$	1,146
2nd Quarter		-		371,364		16,532		-
3rd Quarter		-		125,070		6,284		-
4th Quarter		561,185		103,561		2,956		-
Total	$	561,185	$	1,041,776	$	63,027	$	1,146	$ 1,667,134

20

NOTE 8. COMMON STOCK OPTIONS (continued)

The weighted average remaining life by exercise price as of September 30, 2007, is summarized below:

Range of Exercise Prices		Outstanding Shares		Weighted Average Life		Exercisable Shares		Weighted Average Life
	$0.25 - $0.38		536,664		3.0		536,664		3.0
	$0.50 - $0.75		1,400,000		1.4		1,400,000		1.4
	$1.25 - $1.75		342,000		5.5		342,000		5.5
	$2.23 - $3.55		461,280		6.3		130,280		1.8
	$3.62		1,140,000		3.3		300,000		3.1
	$4.45 - $4.70		543,166		7.4		209,831		6.4
	$5.19 - $5.54		100,000		3.5		100,000		3.5
	$0.25 - $5.54		4,523,110		3.6		3,018,775		2.7

NOTE 9. COMMITMENTS AND CONTINGENCIES

Environmental Risk

Due to the nature of the oil and natural gas business, the Company is exposed to possible environmental risks. The Company manages its exposure to environmental liabilities for both properties it owns as well as properties to be acquired. The Company has historically not experienced any significant environmental liability and is not aware of any potential material environmental issues or claims at September 30, 2007.

Letters of Credit

For each salt water disposal well drilled in the State of Michigan, the Company is required to issue a letter of credit to the Michigan Supervisor of Wells. The Supervisor of Wells may draw on the letter of credit if the Company fails to comply with the regulatory requirements relating to the locating, drilling, completing, producing, reworking, plugging, filling of pits, and clean up of the well site. The letter of credit or a substitute financial instrument is required to be in place until the salt water disposal well is plugged and abandoned. For drilling natural gas wells, the Company is required to issue a blanket letter of credit to the Michigan Supervisor of Wells. This blanket letter of credit allows the Company to drill an unlimited number of natural gas wells. The 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, 2007, letters of credit in the amount of $1.2 million were outstanding to the Michigan Supervisor of Wells.

Employment Agreement

Effective June 19, 2006, the Company hired Ronald E. Huff to serve as Chief Financial Officer of the Company. The Company has entered into 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 remains employed by the Company through June 18, 2008, which requires the Company to record approximately $2.1 million in stock-based compensation expense over the contract period. If his employment with the Company is terminated prior to this date without just cause or if the Company undergoes a change in control, he will nonetheless be awarded the full 500,000 shares. If his employment is terminated prior to June 18, 2008, due to death or disability, he will receive a prorated stock award. Mr. Huff forfeited the option to purchase 200,000 shares that he was previously awarded for his service as a director of the Company. Mr. Huff remains a director of the Company.

21

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9. COMMITMENTS AND CONTINGENCIES (continued)

Equipment Sale - Leaseback Agreement

Effective June 21, 2007, the Company entered into an agreement with Fifth Third Bank to sell and leaseback three natural gas compressors, which were accounted for as an operating lease. The net carrying value of the natural gas compressors sold was $1,202,000. Because the net carrying value of the natural gas compressors was equal to the sales price, there was no gain or loss recognized on the sale. The lease agreement has a base lease term of 84 months with a monthly rental fee of $13,610 beginning July 1, 2007.

Fry Well Loss

The Company participated with Savoy Energy, L.P. (“Savoy”) in a exploratory well known as the Fry 1-13 located in Mecosta County, Michigan. In late December 2006, the well experienced a blow-out event which incurred approximately $5.6 million associated with controlling the well and other related costs. The Company had a 13.33% cost interest (10% working interest) in this well to casing point and paid approximately $762,000 to cover its portion of the loss to Savoy. The Company’s insurance covered approximately 34% or $266,666 of the well control costs.

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. These alternatives, among other things, may include revisions to the Company’s strategic plan, asset divestitures, operating partnerships, identifying additional capital sources, or a sale, merger, or other business combination of 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 Board of Directors recognizes that certain key officers and employees will have increased responsibilities and duties during the evaluation of strategic alternatives and will contribute significantly to the process. The aggregate retention bonus consists of four payments over an 8-month period beginning in late October 2007 through late April 2008. The key officers and employees must remain continuously employed with the Company as well as remain in good standing on the scheduled payment dates. As of October 24, 2007, certain officers of the Company that accepted this arrangement are as follows: (i) Ronald Huff (President and Chief Financial Officer); (ii) John C. Hunter (Vice President); (iii) John V. Miller (Vice President); and (iv) Lorraine M. King (Former Chief Financial Officer). As of September 30, 2007, the Company has recorded $237,500 for estimated retention bonuses in 2007.

22

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10. RELATED PARTY TRANSACTION

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, 2007, there is no production associated with this working interest and development costs were approximately $12.0 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 in June 2007.

23

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 2006 Annual Report on Form 10-KSB, as well as the condensed consolidated financial statements and notes hereto included in this quarterly report on Form 10-Q. The following discussion contains forward-looking statements that involve risks, uncertainties, and assumptions, such as statements of our plans, objectives, expectations, and intentions. Our actual results may differ materially from those discussed in these forward-looking statements because of the risks and uncertainties inherent in future events.

Overview

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

We commenced operations in 1969 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. 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 Resources Corporation amended its articles of incorporation to change the parent company name to Aurora Oil & Gas Corporation.

Our revenue, profitability and future rate of growth are substantially dependent on our ability to find, develop, and acquire gas reserves that are economically recoverable based 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 our financial position, results of operations, cash flows, access to capital and on the quantities of natural gas and oil that can be economically produced.

Highlights

For the nine months ended September 30, 2007, we continued to shift our focus from acquisition of properties to an early stage developer of unconventional shale development projects. As of September 30, 2007, our leasehold acres (both developed and undeveloped) were 1,277,364 (709,613 net) which represent a 3% increase over our December 31, 2006 net acres. These leasehold acres are included in the following plays: 295,193 (153,424 net) leasehold acres in the Michigan Antrim Shale play, 14,803 (14,803 net) leasehold acres in the Indiana Antrim Shale play, 843,883 (445,261 net) acres in the New Albany shale play, 35,898 (31,950 net) acres in the Woodford shale play, and 87,587 (64,175 net) acres in the Other play areas. In early September, Rex Energy Corporation exercised an option to acquire a 30% working interest in oil and natural gas leases covering approximately 70,324 (21,097 net) acres in the New Albany shale play which is reflected as reduction in the New Albany shale acreage.

With regard to our strategy to generate growth through drilling, we drilled or participated in 92 (54 net) wells for the nine months ended September 30, 2007, with a 92% success rate. As of September 30, 2007, we had 639 (300 net) producing wells, 33 (15 net) wells awaiting hook-up, 51 (38 net) wells undergoing resource assessment and 15 (4 net) wells temporarily abandoned. We also continued our strategy to have greater control over our projects by operating 257 (239 net) wells, thus, operating 33% of our gross wells and 67% of our net wells.

Of the 239 net wells operated by the Company, 190 net wells are producing in the Antrim; 7 net wells are awaiting hook-up primarily in the Antrim; 24 net wells are undergoing resource assessment in the Antrim, 3 net wells are producing in the New Albany; 2 net wells are awaiting hook-up in the New Albany; 7 net wells are undergoing resource assessment in the New Albany; 4 net wells are undergoing resource assessment in the Other plays; and 2 net wells are temporarily abandoned.

24

Oil and natural gas production for the nine months ended September 30, 2007, was 2,335,198 mcfe, a 17% increase over the 1,981,833 mcfe produced in the nine months ended September 30, 2006. For the nine months ended September 30, 2007, production continues to be hampered by wells undergoing resource assessment and dewatering.

On August 20, 2007, the Company entered into a second lien term loan agreement with BNP, as the arranger and administrative agent, and several other lenders forming a syndication. The 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 loan were used to pay off the Company’s existing mezzanine financing with TCW and for general corporate purposes. In connection with the loan, the Company also agreed to the amendment and restatement of its 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.

On September 10, 2007, the Company announced that it has established an acreage position of over 30,000 net acres in the Woodford Shale natural gas play of Oklahoma. The identified target area is focused in central Oklahoma, which is experiencing a significant increase in leasing and drilling activity. It is positioned among geological provinces with active Woodford Shale development, with average depths over 5,000 feet and organic shale thickness up to 300 feet. The Company has expended approximately $6.5 million for an 89% working interest in over 35,000 gross acres in the play. The early leasing activities have allowed the Company to establish this competitive position in the targeted play area. Leasing activities are continuing. The Company has targeted 2008 for a pilot program of 5 test wells in its project area. Since the Company’s current capital expenditure budget has been dedicated to further development of the Antrim and New Albany shales, the Company has been in discussions with potential financing and joint venture partners to facilitate aggressive development of this acreage. No financing for this development has been procured as of the date of this filing.

On September 19, 2007, the Company announced that it has retained Johnson Rice & Company, L.L.C. to assist the Board of Directors with investigating strategic alternatives for the Company. These alternatives, among other things, may include revisions to the Company’s strategic plan, asset divestitures, operating partnerships, identifying additional capital sources, or a sale, merger, or other business combination of the Company. The Company intends to disclose developments regarding the exploration of alternatives only if and when the Board of Directors has approved a specific course of action. There is no assurance that this process will result in any changes to the Company’s current strategic direction. There is no specific timeframe to complete the review and there are no constraints on options to be explored.

25

Operating Statistics

The following table sets forth certain key operating statistics for the three and nine months ended September 30, 2007 (the “Current Quarter” and the “Current Period”), and the three and nine months ended September 30, 2006 (the “Prior Year Quarter” and the “Prior Year Period”):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
Net wells drilled
Antrim shale		17		13		29		42
New Albany shale (“NAS”)		5		1		9		4
Other		2		3		10		3
Dry		2		2		6		5
Total		26		19		54		54
Total net wells
Antrim—producing		283		181		283		181
Antrim—awaiting hookup		10		17		10		17
NAS—producing		4		1		4		1
NAS—awaiting hookup		3		4		3		4
Other—producing		13		11		13		11
Other—awaiting hookup		2		5		2		5
Total		315		219		315		219
Production
Natural gas (mcf)		798,540		653,944		2,209,360		1,878,495
Crude oil (bbls)		7,201		5,334		20,973		17,223
Natural gas equivalent		841,746		685,948		2,335,198		1,981,833
Average daily production
Natural gas (mcf)		8,680		7,108		8,093		6,880
Crude oil (bbls)		78		58		77		63
Natural gas equivalent		9,149		7,456		8,555		7,258
Average sales price includes effects of realized hedging
Natural gas (mcf)	$	8.04	$	7.36	$	8.22	$	7.99
Crude oil (bbls)	$	74.69	$	67.90	$	63.07	$	64.06
Natural gas equivalent	$	8.27	$	7.55	$	8.35	$	8.13
Production revenue
Natural gas	$	6,419,221	$	4,813,443	$	18,166,234	$	15,013,553
Crude oil		537,848		362,192		1,322,840		1,103,302
Total	$	6,957,069	$	5,175,635	$	19,489,074	$	16,116,855
Average expenses ($ per mcfe)
Production taxes	$	0.31	$	0.31	$	0.36	$	0.33
Post-production expenses	$	0.53	$	0.42	$	0.53	$	0.47
Lease operating expenses	$	1.95	$	1.58	$	2.13	$	1.67
General and administrative expense	$	2.18	$	2.98	$	2.60	$	2.67
General and administrative expense excluding stock-based compensation	$	1.47	$	1.59	$	1.83	$	1.99
Oil and natural gas depreciation, depletion and amortization expenses	$	0.86	$	1.31	$	0.96	$	1.47
Other assets depreciation and amortization	$	0.75	$	0.74	$	0.76	$	0.77
Interest expenses	$	1.48	$	3.32	$	1.41	$	2.95
Taxes	$	0.11	$	0.01	$	0.04	$	0.02
Number of employees including Bach		88		53		88		53

26

Results of Operations

Three Months Ended September 30, 2007, compared with Three Months Ended September 30, 2006

General. For the Current Quarter, the Company had a net loss of $3.3 million, or $(0.03) per diluted common share, on total revenues of $7.2 million. This compares to a net loss of $2.1 million, or $(0.03) per diluted common share, on total revenue of $5.3 million for the Prior Year Quarter. The $1.9 million increase in revenue represents our initial steps as an early stage developer of oil and natural gas properties as well as a gain recognized in the natural gas hedging activities. In addition, the net loss of $3.3 million in the Current Quarter included $3.4 million one time charge on debt extinguishment.

Oil and Natural Gas Sales. During the Current Quarter, oil and natural gas sales were $7.0 million compared to $5.2 million in the Prior Year Quarter. The Company produced 841,746 mcfe at a weighted average price of $8.27 compared to 685,948 mcfe at a weighted average price of $7.55. This increase in production was due to new wells placed on-line. We had 300 net wells producing as of September 30, 2007, as compared to 193 net wells producing as of September 30, 2006. The weighted average price included $1.5 million and $1.0 million of realized gains from the gas derivative contract for Current Quarter and Prior Year Quarter, respectively. Production from the Antrim shale play represented approximately 91% of our oil and natural gas revenue for the Current Quarter.

The following table summarizes our oil and natural gas revenue by play/trend in the periods set forth below:

	Three Months Ended September 30, 2007				Three Months Ended September 30, 2006
Play/Trend	(mcfe)		Amount		(mcfe)		Amount
Antrim		780,834	$	6,309,185		619,677	$	4,632,415
New Albany		14,361		90,498		7,391		47,212
Other		46,551		557,386		58,880		496,008
Total		841,746	$	6,957,069		685,948	$	5,175,635

 

Other Revenues. Other revenues increased by $0.1 million, or 84% to $0.3 million in the Current Quarter from $0.2 million in the Prior Year Quarter. This increase is attributed the Bach acquisition in October 2006 which provides oil and natural gas field services.

Production Taxes. Production taxes were $0.3 million in the Current Quarter compared to $0.2 million in the Prior Year Quarter. This increase is attributed to new wells being added and production growth of existing wells. On a unit of production basis, production taxes were $0.31 per mcfe in the Current Quarter compared to $0.31 per mcfe in the Prior Year Quarter.

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

Production and lease operating expenses were $2.1 million in the Current Quarter compared to $1.4 million in the Prior Year Quarter. On a per unit of production basis, production and lease operating expenses were $2.48 per mcfe in the Current Quarter compared to $2.00 per mcfe in the Prior Year Quarter. The increase in the Current Quarter was primarily attributable to higher energy costs, higher property taxes, pumping costs, and higher repair and maintenance associated with meters, generators, compressors and pumps. On a component basis, post-production expenses were $0.5 million, or $0.53 per mcfe, in the Current Quarter compared to $0.3 million, or $0.42 per mcfe, in the Prior Year Quarter, and lease operating expenses were $1.6 million, or $1.95 per mcfe, in the Current Quarter compared to $1.1 million, or $1.58 per mcfe, in the Prior Year Quarter.

Production and lease operating expenses for operated properties were $2.31 per mcfe in the Current Quarter while non-operated production and lease operating expenses were $2.93 per mcfe in the Current Quarter. Our operated Arrowhead, Blue Chip, and Gaylord Fishing Club projects continue to negatively impact our operating cost controls and efficiency due to dewatering. Production and lease operating expenses for operated properties excluding Arrowhead, Blue Chip, and Gaylord Fishing Club projects were $2.11 per mcfe in the Current Period.

27

Pipeline Operating Expenses and Field Services Expenses. Pipeline operating expenses were $0.1 million in the Current Quarter compared to $0.1 million in the Prior Year Quarter. Field services expenses were $58,000 in the Current Quarter compared to no expense in the Prior Year Quarter which are attributable to the Bach acquisition in October 2006.

General and Administrative Expenses. Our general and administrative expenses include officer and employee compensation, travel, audit, tax and legal fees, office supplies, utilities, insurance, consulting fees, and office related expense. General and administrative expenses in the Current Quarter decreased by $0.2 million, or 12%, from the Prior Year Quarter.

Payroll and related costs decreased by $0.1 million to $1.5 million in the Current Quarter due to lower director and employee stock based compensation of $0.3 million which was offset by a 2007 retention bonus accrual of $0.2 million. Legal, accounting, and other consulting services were relatively flat at $0.3 million in the Current Quarter compared to $0.3 million in the Prior Year Quarter.

The Company follows 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 $0.3 million of payroll and benefit costs for the Current Quarter compared to $0.4 million in the Prior Year Quarter.

Oil and Natural Gas Depletion, Depreciation and Amortization (“DD&A”). DD&A of oil and natural gas properties was $0.7 million and $0.9 million during the Current Quarter and the Prior Year Quarter, respectively. DD&A is a function of capitalized costs in the full cost pool and related underlying reserves in the periods presented. This decrease is the result of a change in estimate of DD&A from proven developed reserves to total proven reserves and the underlying reserves increasing by 89 bcfe as of December 31, 2006. The average DD&A cost per mcfe was $0.86 and $1.31 in the Current Quarter and the Prior Year Quarter, respectively.

Other Assets Depreciation and Amortization (“D&A”). D&A of other assets was $0.6 million in the Current Quarter compared to $0.5 million in the Prior Year Quarter. This increase was primarily the result of additions in other assets.

Interest Expense. Interest expense was $1.2 million in the Current Quarter compared to $2.3 million in the Prior Year Quarter. This decrease is the result of a change in estimating capitalized interest. During the fourth quarter 2006, the Company modified its approach to estimating capitalized interest by recognizing that debt need not be specific debt incurred on a specific asset.

Loss on Debt Extinguishment. The Company recorded $3.4 million as a loss on debt extinguishment due to the termination of the mezzanine debt. Under the termination provisions, the Company was required to pay certain fees and prepayment charges associated with early termination. The following represents the expenses incurred: (i) $0.35 million payment of interest make-whole provision from August 21, 2007, through September 27, 2007; (ii) $1.25 million payment of prepayment premium; (iii) $0.2 million payment for a make-whole provision on principal greater than $30 million; and (iv) $1.6 million write-off of unamortized debt issuance cost.

Taxes, Other.Other taxes primarily include state franchise taxes and personal property taxes. The Company has significant net operating loss carryforwards, thus no federal income tax expense has been recognized for either the Current Quarter or Prior Year Quarter. Tax expense was $95,773 in the Current Quarter compared to $9,928 in the Prior Year Quarter. This increase primarily represents the Company’s 2007 9-month accrual on state income taxes, single business taxes and state franchise taxes.

28

Nine Months Ended September 30, 2007, compared with Nine Months Ended September 30, 2006

General. For the Current Period, the Company had a net loss of $3.8 million, or $(0.04) per diluted common share, on total revenues of $20.8 million. This compares to a net loss of $4.0 million, or $(0.05) per diluted common share, on total revenue of $16.7 million for the Prior Year Period. The $4.1 million increase in revenue represents the following: (i) our initial steps as an early stage developer of oil and natural gas properties; (ii) revenue from 2006 Bach acquisition; and (iii) a gain recognized in the sale of mining claims. In addition, the net loss of $3.8 million in the Current Period included $3.4 million one time charge on debt extinguishment.

Oil and Natural Gas Sales. During the Current Period, oil and natural gas sales were $19.5 million compared to $16.1 million in the Prior Year Period. The Company produced 2,335,198 mcfe at a weighted average price of $8.35 compared to 1,981,833 mcfe at a weighted average price of $8.13. This increase in production was due to new wells placed on-line and production growth of existing wells. We had 300 net wells producing as of September 30, 2007, as compared to 193 net wells producing as of September 30, 2006. The weighted average price included $2.9 million and $1.8 million of realized gains from gas derivative contracts for the Current Period and Prior Year Period, respectively. Production from the Antrim shale play represented approximately 92% 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: 

	Nine Months Ended September 30, 2007				Nine Months Ended September 30, 2006
Play/Trend		(mcfe)		Amount		(mcfe)		Amount
Antrim		2,165,342	$	17,869,384		1,733,820	$	13,878,206
New Albany		37,724		264,259		16,522		116,313
Other		132,132		1,355,431		231,491		2,122,336
Total		2,335,198	$	19,489,074		1,981,833	$	16,116,855

Other Revenues. Other revenues increased by $0.7 million, or 124% to $1.3 million in the Current Period from $0.6 million in the Prior Year Period. This increase is attributed to the sale of mining claims ($0.4 million) and to the Bach acquisition ($0.3 million) in October 2006 which provides oil and natural gas field services.

Production Taxes. Production taxes were $0.8 million in the Current Period compared to $0.7 million in the Prior Year Period. This increase is attributed to new wells being added and production growth of existing wells. On a unit of production basis, production taxes were $0.36 per mcfe in the Current Period compared to $0.33 per mcfe in 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, including marketing and transportation, and expenses to operate the wells and equipment on producing leases.

Production and lease operating expenses were $6.2 million in the Current Period compared to $4.2 million in the Prior Year Period. On a per unit of production basis, production and lease operating expenses were $2.66 per mcfe in the Current Period compared to $2.14 per mcfe in the Prior Year Period. The increase in the Current Period was primarily attributable to higher energy costs, higher property taxes, higher pumping costs, repair and maintenance associated with meters, compressors and pumps, and outside labor. On a component basis, post-production expenses were $1.2 million, or $0.53 per mcfe, in the Current Period compared to $0.9 million, or $0.47 per mcfe, in the Prior Year Period, and lease operating expenses were $5.0 million, or $2.13 per mcfe, in the Current Period compared to $3.3 million, or $1.67 per mcfe, in the Prior Year Period.

Production and lease operating expenses for operated properties were $2.48 per mcfe in the Current Period while non-operated production and lease operating expenses were $3.17 per mcfe in the Current Period. Our operated Arrowhead, Blue Chip, and Gaylord Fishing Club projects continue to negatively impact our operating cost controls and efficiency due to dewatering. Production and lease operating expenses for operated properties excluding Arrowhead, Blue Chip, and Gaylord Fishing Club projects were $2.21 per mcfe in the Current Period.

29

Pipeline Operating Expenses and Field Services Expenses. Pipeline operating expenses were $0.3 million in the Current Period compared to $0.1 million in the Prior Year Period. Field services expenses were $0.2 million in the Current Period compared to no expense in the Prior Year Period which are attributable to the Bach acquisition in October 2006.

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 $0.8 million, or 15%, from the Prior Year Period. This increase is the result of executing our growth strategy. This has resulted in substantial increases in employees and related cost.

Payroll and related costs increased by $1.8 million to $4.7 million in the Current Period due to higher staffing ($0.9 million), stock-based compensation ($0.6 million), 2007 retention bonus ($0.2 million), and health care ($0.1 million). Legal, accounting, and other consulting services were reduced by $0.6 million to $1.0 million in the Current Period compared to $1.6 million in the Prior Year Period. Insurance had a slight increase of $50,000 due to coverage associated with Bach while there were offsets of $0.4 million from the disposal of legacy Cadence stock investments and correction of the stock ledger associated with prior Cadence transaction.

The Company follows 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 $1.1 million of payroll and benefit costs for the Current Period compared to $1.0 million in the Prior Year Period.

Oil and Natural Gas Depletion, Depreciation and Amortization (“DD&A”). DD&A of oil and natural gas properties was $2.2 million and $2.9 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 decrease is the result of a change in estimate of DD&A from proven developed reserves to total proven reserves and the underlying reserves increasing by 89 bcfe as of December 31, 2006. The average DD&A cost per mcfe was $0.96 and $1.47 in the Current Period and the Prior Year Period, respectively.

Other Assets Depreciation and Amortization (“D&A”). D&A of other assets was $1.8 million in the Current Period, compared to $1.5 million in the Prior Year Period. This increase was primarily the result of additions in other assets.

Interest Expense. Interest expense was $3.3 million in the Current Period compared to $5.8 million in the Prior Year Period. This decrease is primarily the result of a change in estimating capitalized interest. During the fourth quarter 2006, the Company modified its approach to estimating capitalized interest by recognizing that debt need not be specific debt incurred on a specific asset.

Loss on Debt Extinguishment. The Company recorded $3.4 million as a loss on debt extinguishment due to the termination of the mezzanine debt. Under the termination provisions, the Company was required to pay certain fees and prepayment charges associated with early termination. The following represents the expenses incurred: (i) $0.35 million payment of interest make-whole provision from August 21, 2007, through September 27, 2007; (ii) $1.25 million payment of prepayment premium; (iii) $0.2 million payment for a make-whole provision on principal greater than $30 million; and (iv) $1.6 million write-off of unamortized debt issuance cost.

Taxes, Other.Tax expense was $95,720 in the Current Period compared to $39,289 in the Prior Year Period. This increase primarily represents the Company’s 2007 9-month accrual on state income taxes, single business taxes and state franchise taxes. The Company has significant net operating loss carryforwards, thus no federal income tax expense has been recognized.

30

Liquidity and Capital Resources

We expect to fund our growth using a combination of existing and anticipated debt capacity, sale of non-core assets, existing cash balances, and internally generated cash flows from sales of natural gas production. Our revised 2007 capital budget for drilling and related well work and infrastructure is estimated to be approximately $52.9 million with anticipated participation in 162 (111 net) wells. Future cash flows are subject to a number of variables, including the level of production, natural gas prices and successful drilling efforts. We may be required to adjust our capital expenditures if additional debt financing is not obtained and we are not able to complete sales of non-core assets. We have recently retained Johnson Rice & Company, L.L.C. to investigate strategic alternatives for the Company. The alternatives, among other things, may include revisions to the Company's strategic plan, asset divestitures, operating partnerships, identifying additional capital sources, or a sale, merger, or other business combination of the Company. We anticipate reducing our drilling activities and postponing significant asset divestitures, but we intend to maintain current operations pending the outcome of the strategic alternatives evaluation presented by Johnson Rice & Company, L.L.C. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures.

On August 20, 2007, we entered into a second lien term loan agreement with BNP, as the arranger and administrative agent, and several other lenders forming a syndicate. The initial term loan is $50 million for a 5-year term which may increase up to $70 million under certain conditions over the life of the loan facility. The proceeds of the loan were used to payoff the Company’s existing mezzanine financing with TCW and for general corporate purposes.

Interest under the loan is payable at rates based on the London Interbank Offered Rate plus 700 basis points with a step-down of 25 basis points once the Company’s 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. The Company has the ability to prepay the loan during the first year at a price equal to 103% of par, during the second year at a price equal to 102% of par, and thereafter at a price equal to 100% of par.

The loan contains, among other things, a number of financial and non-financial covenants relating to restricted payments (as defined), loans or advances to others, additional indebtedness, incurrence of liens, geographic limitations on operations to the United States, and maintenance of certain financial and operating ratios, including (i) maintenance of a maximum of indebtedness to earnings before interest, income taxes, depreciation, depletion and amortization and non-cash expenses, and (ii) maintenance of minimum reserve value to indebtedness. Any event of default under the senior secured credit facility that accelerates the maturity of any indebtedness thereunder is also an event of default under the second lien term loan. As of September 30, 2007, we were in compliance with all of the applicable covenants.

In both the loan and senior secured credit facility, the Company agreed to an affirmative covenant regarding production exit rates with the first net production target being 9.5 MMcfe per day as of June 30, 2007, which the Company achieved. The second target production exit target is 10.5 MMcfe per day as of September 30, 2007 (which has been achieved), and the third production exit target is 12.0 MMcfe per day as December 31, 2007, and as of the last day of each quarter thereafter. In addition, the Company was required to purchase financial hedges at prices and aggregate notional volumes satisfactory to BNP, as administrative agent which requirement has been satisfied.

Our senior secured credit facility is a $100 million senior secured credit facility with BNP. In connection with the second lien term loan, the Company also agreed to the amendment and restatement of its 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 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 semiannual 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.

31

This facility provides for borrowings tied to BNP’s prime rate (or, if higher, the federal funds effective rate plus 0.5%) or LIBOR-based rate plus 1.25% to 2.0% depending on the borrowing base utilization, as selected by the Company. The borrowing base utilization is the percentage of the borrowing base that is drawn under the senior secured credit facility from time to time. As the borrowing base utilization increases, the LIBOR-based interest rates increase under this facility. As of September 30, 2007, interest on the borrowings had a weighted average interest rate of 6.93%. 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. As of September 30, 2007, we were in compliance with all of the applicable covenants.

Our short-term line of credit is a $5 million revolving line of credit with Northwestern Bank for general corporate purposes. As of September 30, 2007, our total borrowing capacity available under this facility was $3.6 million. The interest rate is the prime rate with interest payable monthly in arrears. Principal is payable at the expiration of the line of credit, October 15, 2007. The Company has elected not to request an extension of this revolving line of credit beyond the expiration date and has paid the remaining loan balance as of September 25, 2007.

Our total capitalization was as follows:

	As of September 30, 2007		As of December 31, 2006
Short-term bank borrowings	$	-	$	542,788
Obligations under capital lease		9,418		17,096
Notes payable		235,895		280,321
Mortgage payables		3,106,419		3,175,298
Mezzanine financing		-		40,000,000
Second lien term loan		46,000,000		-
Senior secured credit facility		50,000,000		10,000,000
Total debt		99,351,732		54,015,503
Shareholders’ equity		136,943,281		139,731,099
Total capitalization	$	236,295,013	$	193,746,602

Cash Flows from Operating Activities

Cash provided by operating activities increased $6.4 million or 225% to $9.3 million in the Current Period, compared to cash provided by operating activities of $2.9 million in the Prior Year Period. This $6.4 million increase in net cash provided by operating activities was due to increase in production revenues with reductions operating expenses are well as increases in other income. See “Results of Operations” for discussion of changes in revenues and expenses. Non-cash charges such as depreciation, depletion and amortization and stock-based compensation remained relative flat except for the non-cash charge on debt extinguishment. Changes in current operating assets and liabilities decreased cash flow from operations by $3.8 million.

32

Cash Flows Used in Investing Activities

Cash flows used in investing activities was $52.1 million in the Current Period, compared to $69.6 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,
	2007		2006
Acquisitions of leasehold
Michigan Antrim shale	$	1,206,400	$	5,720,106
Indiana Antrim shale		464,190		-
New Albany shale		3,074,492		15,219,720
Woodford shale		4,451,072		939,132
Other		118,155		1,315,526
Drilling and development of oil and natural gas properties
Michigan Antrim shale		18,983,846		14,761,577
Indiana Antrim shale		1,309,324		-
New Albany shale		7,682,040		960,245
Other		1,484,745		3,710,395
Infrastructure properties
Michigan Antrim shale		9,347,451		7,818,474
New Albany shale		277,971		499,198
Other		10,439		17,164
Capitalized interest and general and administrative costs on exploration, development and leasehold		3,984,154		1,765,430
Acquisitions of oil and natural gas properties		2,405,609		24,004,616
Acquisitions/additions for pipeline, property, and equipment		1,290,037		3,985,358
Other, net		78,970		577,088
Subtotal of capital expenditures		56,168,895		81,294,029
Sale of oil and natural gas properties		2,079,518		11,492,817
Sale and leaseback of gas compression equipment		1,202,000		-
Sales of other investment and other		763,731		165,082
Subtotal of capital divestitures		4,045,249		11,657,899
Total	$	52,123,646	$	69,636,130

Cash Flows Provided by Financing Activities

Cash flows provided by financing activities were $41.8 million in the Current Period compared to $57.8 million in the Prior Year Period. Cash flows provided in the Current 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 in the Current Period included: (1) pay-down of $16.8 within short-term bank borrowings; (2) pay-down of $40.0 million in mezzanine financings; (3) pay-down of $6.0 million in senior secured credit borrowings; (4) pay-down of $0.3 million in mortgage obligations and other; (5) payment of $1.7 million in financing fees; and (6) payment of $1.9 million in prepayment penalties.

Cash flows provided by financing activities in the Prior Year Period included: (1) $45.0 million of senior secured credit borrowing; (2) $18.2 million of net proceeds received from exercise of common stock options and warrants; and (3) $4.4 million in short-term borrowings. Cash flows used by financing in the Prior Year Period included: (1) net pay-down of $7.0 million within short-term bank borrowings; (2) payments of $2.4 million in financing fees; and (3) pay-down of $0.4 million within mortgage obligations and other.

33

Recent Accounting Pronouncements

Reference is made to Note 3 to the Financial Statements included elsewhere in this filing for a description of certain recently issued accounting pronouncements. We do not expect any of such recently issued accounting pronouncements to have a material effect on our consolidated financial position or results of operations.

Critical Accounting Policies

We consider accounting policies related to use of estimates, oil and natural gas properties, oil and natural gas reserves, stock-based compensation, and income taxes to be critical policies. These accounting policies are summarized in the audited consolidated financial statements and notes included in our Annual Report on Form 10-KSB for the year ended December 31, 2006.

Off Balance Sheet Arrangements

We have no special purpose entities, financing partnerships, guarantees, or off-balance sheet arrangements other than the $1.2 million of outstanding letter of credits discussed in Note 9 “Commitments and Contingencies.”

ITEM 3. QUANTITIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

The Company’s results of operations and operating cash flows are impacted by the fluctuations in the market prices of natural gas. To mitigate a portion of the exposure to adverse market changes, the Company will periodically enter into various derivative instruments with a major financial institution. The purpose of the derivative instrument is to provide a measure of stability to the Company’s cash flow in meeting financial obligations while operating in a volatile natural gas market environment. The derivative instrument reduces the Company’s exposure on the hedged production volumes to decreases in commodity prices and limits the benefit the Company might otherwise receive from any increases in commodity prices on the hedged production volumes. The following natural gas contracts were in place as of September 30, 2007:

Period	Type of Contract		Natural Gas Volume per Day		Price per mmbtu		Fair Value Asset (Liability)
April 2007—December 2008		Swap		5,000 mmbtu		$ 9.00	$	2,657,646
April 2007—December 2008		Collar		2,000 mmbtu		$ 7.55/$ 9.00		171,880
January 2008—December 2008		Swap		2,000 mmbtu		$ 8.41		275,486
January 2009—December 2009		Swap		7,000 mmbtu		$ 8.72		704,500
January 2010—March 2011		Swap		7,000 mmbtu		$ 8.68		914,838
April 2011—September 2011		Swap		7,000 mmbtu		$ 7.62		(69,035	)
Total estimated fair value							$	4,655,315

Interest Rate Risk

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

34

The following table sets forth the Company’s principal financing obligation and the related interest rates as of September 30, 2007:

	Expected Maturity		Average Interest Rate as of September 30, 2007		Principal Outstanding
Short-term bank borrowings		Revolving		Variable – 7.75%	$	-
Obligations under capital lease		01/10/09		8.25%		9,418
Notes payable		08/01/07-04/25/11		5.50% - 7.50%		235,895
Mortgage payable		10/15/09		Fixed at 6.00%		372,531
Mortgage payable		10/01/08		Fixed at 6.50%		2,733,888
Second lien term loan		08/20/12		Variable plus 700 - 11.86%		50,000,000
Senior secured credit facility		01/31/10		Variable – 7.125%		46,000,000
Total debt					$	99,351,732

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, 2007, 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. Our management continues to review our internal controls and procedures and the effectiveness of those controls. In the fourth quarter of 2006, the Company formally initiated the process of documenting internal controls over financial reporting in an effort to be in compliance with the evaluation and reporting requirements of the Sarbanes-Oxley Act of 2002 Section 404 by December 31, 2007.

35

PART II

ITEM 1. LEGAL PROCEEDINGS

Our management is unaware of any threatened or pending material legal claims or procedures of a non-routine nature.

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-KSB for the year ended December 31, 2006. This information should be considered carefully, together with other information in this report and other reports and materials we file with the Securities and Exchange Commission.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES

We did not sell any of our unregisterd equity securities nor did we repurchase any of our outstanding equity securities during the quarter ended September 30, 2007.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

3.1(1)	Restated Articles of Incorporation of Aurora Oil & Gas Corporation.
3.2	By-Laws of Aurora Oil & Gas Corporation. (filed as an Exhibit 3.2 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)
10.1	Securities Purchase Agreement between Cadence Resources Corporation and the investors signatory thereto, dated April 2, 2004 (filed as Exhibit 99.3 to our Current Report on Form 8-K filed with the SEC on April 5, 2004, and incorporated herein by reference.)
10.2	Securities Purchase Agreement between Cadence Resources Corporation and the investors signatory thereto, dated January 31, 2005 (filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on February 2, 2005, and incorporated herein by reference.)
10.3(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.
10.4	Note Purchase Agreement between Aurora Antrim North, L.L.C. et al. and TCW Asset Management Company, dated August 12, 2004 (filed as an Exhibit to our Form S-4 registration statement filed with the SEC on May 13, 2005, and incorporated herein by reference.)
10.5	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 Annual 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.)
10.6(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.

36

10.7	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.)
10.8	Intercreditor and Subordination Agreement among, BNP Paribas, et al., TCW Asset Management Company, and Aurora Antrim North, L.L.C., dated January 31, 2006 (Replaced with Exhibit 10.26)
10.9(2)	Promissory Note from Aurora Energy, Ltd. to Northwestern Bank dated January 31, 2006.
10.10(2)	Confirmation from BNP Paribas to Aurora Antrim North, L.L.C., dated February 22, 2006 relating to gas sale commitment.
10.11	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.)
10.12(1)	Employment Agreement with Ronald E. Huff dated June 19, 2006.
10.13(1)	Letter Agreement with Bach Enterprises dated July 10, 2006. This Agreement is confidential and has been filed separately with the SEC.
10.14(1)	First Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated July 14, 2006.
10.15(1)	The Denthorn Trust Commercial Guaranty of obligations to Northwestern Bank.
10.16(1)	William W. Deneau Commercial Guaranty of obligations to Northwestern Bank.
10.17(1)	The Denthorn Trust Commercial Pledge Agreement to Northwestern Bank.
10.18(3)	LLC Membership Interest Purchase Agreement dated October 6, 2006 relating to Kingsley Development Company, L.L.C.
10.19(3)	Asset Purchase Agreement with Bach Enterprises, Inc., et al., dated October 6, 2006.
10.20(3)	Promissory Note from Aurora Energy, Ltd. to Northwestern Bank dated October 15, 2006.
10.21(3)	Form of indemnification letter agreement between Aurora Oil & Gas Corporation and Rubicon Master Fund.
10.22(3)	Patricia A. Deneau Trust Commercial Guaranty of obligations to Northwestern Bank.
10.23(3)	Patricia A. Deneau Trust Commercial Pledge Agreement to Northwestern Bank.
10.24	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 Annual 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.)
10.25	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.)
10.26	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.)
10.27	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.)
*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.

(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.

37

SIGNATURES

In accordance with Section 13 or 15(d) 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 thereto duly authorized.

	AURORA OIL & GAS CORPORATION
Date: November 14, 2007	By:	/s/ William W. Deneau
		Name: William W. Deneau
		Title: Chief Executive Officer
Date: November 14, 2007	By:	/s/ Ronald E. Huff
		Name: Ronald E. Huff
		Title: President and Chief Financial Officer

38