Aurora Oil & Gas 10-Q 2007 Q2 Quarterly report

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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 xNo 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  x  Non-accelerated filer o

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

Yes  x No  o

The number of shares of the registrant’s common stock outstanding as of July 31, 2007, was 101,589,456.

FORM 10-Q

INDEX

PART I	FINANCIAL INFORMATION	1
Item 1.	Condensed Consolidated Financial Statements	2
	Condensed Consolidated Balance Sheets as of June 30, 2007 (Unaudited), and December 31, 2006 (Audited)	2
	Unaudited Statements of Operations for the Three and Six Months Ended June 30, 2007, and 2006	4
	Unaudited Statements of Shareholders’ Equity for the Six Months Ended June 30, 2007, and 2006	5
	Unaudited Statements of Cash Flows for the Six Months Ended June 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	21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 4.	Controls and Procedures	31
PART II	OTHER INFORMATION	32
Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 3.	Defaults Upon Senior Securities	32
Item 4.	Submission of Matters to a Vote of Security Holders	32
Item 5.	Other Information	32
Item 6.	Exhibits	32
Signatures		34

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
	June 30, 2007 (Unaudited)			December 31, 2006 (Audited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	720,498		$	1,735,396
Accounts receivable
Oil and natural gas sales		4,982,887			4,082,231
Joint interest owners		1,004,172			2,811,278
Notes receivable		-			341,698
Prepaid expenses and other current assets		817,825			251,093
Short-term derivative instruments		2,201,716			3,552,060
Total current assets		9,727,098			12,773,756
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, using full cost accounting:
Proved properties		142,200,610			121,178,499
Unproved properties		54,200,686			43,269,317
Properties held for sale		-			8,896,568
Less: accumulated depletion and amortization		(12,151,898	)		(10,628,438	)
Total oil and natural gas properties, net		184,249,398			162,715,946
Pipelines		5,019,906			4,881,240
Other property and equipment		5,400,816			5,093,777
Less: accumulated depreciation		(1,114,508	)		(753,789	)
Total property and equipment, net		193,555,612			171,937,174
OTHER ASSETS:
Long-term derivative instruments		560,718			1,668,573
Goodwill		19,373,264			19,373,264
Intangibles (net of accumulated amortization of $3,722,085 and $2,946,250, respectively)		1,232,915			2,008,750
Other investments		901,268			985,706
Debt issuance costs (net of accumulated amortization of $1,329,051 and $892,535, respectively)		2,054,648			2,363,898
Other		994,035			1,007,634
Total other assets		25,116,848			27,407,825
TOTAL ASSETS	$	228,399,558		$	212,118,755

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

2

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (continued)
	June 30, 2007 (Unaudited)			December 31, 2006 (Audited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	5,635,186		$	5,355,154
Accrued exploration, development, and leasehold costs		3,294,213			11,587,850
Short-term bank borrowings		1,418,615			542,788
Current portion of obligations under capital leases		6,561			8,868
Current portion of note payable—other		100,768			161,774
Current portion of mortgage payable		100,008			95,828
Drilling advances		565,891			19,383
Total current liabilities		11,121,242			17,771,645
LONG-TERM LIABILITIES:
Obligations under capital leases, net of current portion		4,984			8,228
Asset retirement obligation		989,885			1,331,893
Notes payable		163,402			118,547
Mortgage payable		3,028,733			3,079,470
Senior secured credit facility		35,000,000			10,000,000
Mezzanine financing		40,000,000			40,000,000
Total long-term liabilities		79,187,004			54,538,138
Total liabilities		90,649,415			72,309,783
Minority interest in net assets of subsidiaries		85,828			77,873
COMMITMENTS, CONTINGENCIES AND SUBSEQUENT EVENT (Note 9 and Note 11 )
SHAREHOLDERS’ EQUITY
Common stock, $0.01 par value; authorized 250,000,000 shares; issued and outstanding 101,589,456 shares and 101,412,966 shares, respectively		1,015,895			1,014,130
Additional paid-in capital		139,347,287			138,105,626
Accumulated other comprehensive income		2,762,434			5,220,633
Accumulated deficit		(5,120,132	)		(4,609,290	)
Total shareholders’ equity		138,005,484			139,731,099
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	228,399,558		$	212,118,755

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

3

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
	Three Months Ended June 30						Six Months Ended June 30
	2007			2006			2007			2006
REVENUES:
Oil and natural gas sales	$	6,602,429		$	5,524,354		$	12,532,005		$	10,941,220
Pipeline transportation and marketing		157,664			130,533			286,932			242,299
Field service and sales		60,084			-			249,602			-
Interest and other		461,245			70,580			474,758			181,631
Total revenues		7,281,422			5,725,467			13,543,297			11,365,150
EXPENSES:
Production taxes		303,871			231,666			566,969			445,825
Production and lease operating expense		2,200,807			1,313,485			4,126,700			2,853,374
Pipeline operating expense		64,382			72,204			177,802			137,484
Field services expense		45,824			-			200,096			-
General and administrative expense		1,973,358			1,676,019			4,233,701			3,242,713
Oil and natural gas depletion and amortization		776,595			1,068,417			1,523,460			2,010,383
Other assets depreciation and amortization		573,498			546,032			1,142,104			1,013,783
Interest expense		1,068,871			1,970,019			2,050,403			3,564,154
Taxes (refunds), other		25,129			27,694			(53	)		29,361
Total expenses		7,032,335			6,905,536			14,021,182			13,297,077
INCOME (LOSS) BEFORE MINORITY INTEREST		249,087			(1,180,069	)		(477,885	)		(1,931,927	)
MINORITY INTEREST IN INCOME OF SUBSIDIARIES		(19,610	)		(5,119	)		(32,957	)		(17,919	)
NET INCOME (LOSS)	$	229,477		$	(1,185,188	)	$	(510,842	)	$	(1,949,846	)
NET INCOME (LOSS) PER COMMON SHARE —BASIC	$	0.00		$	(0.01	)	$	(0.01	)	$	(0.03	)
—DILUTED	$	0.00
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING —BASIC		101,650,665			81,693,808			101,602,875			70,265,281
—DILUTED		103,735,539

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

4

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (Unaudited)
	Six Months Ended June 30,
	2007						2006
COMMON STOCK:	Shares			Amount			Shares		Amount
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		-			-			23,334		233
Exercise of stock options and warrants		173,332			1,733			15,565,457		155,655
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		101,589,456			1,015,895			81,965,017		819,651
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					-					39,768
Costs of equity offerings					(10,096	)				-
Stock-based compensation					1,335,523					757,442
Exercise of stock options and warrants					63,266					17,988,794
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					139,347,287					77,757,502
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Balance, beginning					5,220,633					-
Changes in fair value of derivative instruments					(1,099,949	)				1,754,365
Recognition of gain on derivative instruments					(1,358,250	)				(792,350	)
Balance, ending					2,762,434					962,015
ACCUMULATED DEFICIT:
Balance, beginning					(4,609,290	)				(2,660,134	)
Dividends accrued on redeemable convertible preferred stock					-					(4,295	)
Net loss					(510,842	)				(1,949,846	)
Balance, end					(5,120,132	)				(4,614,275	)
TOTAL SHAREHOLDERS’ EQUITY				$	138,005,484				$	74,924,893

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

5

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
	Six Months Ended June 30,
CASH FLOWS FROM OPERATING ACTIVITIES:	2007			2006
Net loss	$	(510,842	)	$	(1,949,846	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization		2,665,564			3,024,166
Amortization of debt issuance costs		446,790			383,422
Accretion of asset retirement obligation		31,112			36,989
Stock-based compensation		1,201,756			392,149
Equity loss of other investments and other		(67,418	)		172,610
Realized gain on sale of other investments		(418,147	)		-
Minority interest income of subsidiaries		32,957			17,919
Changes in operating assets and liabilities, net of effects of merger:
Accounts receivable - oil and natural gas sales		(900,656	)		219,790
Accounts receivable - joint interest owners		2,150,169			(1,721,176	)
Drilling advance - liabilities		546,508			622,537
Notes receivable		221,788			17,000
Prepaid expenses and other assets		(267,838	)		(75,597	)
Accounts payable and accrued liabilities		280,032			2,467,539
Net cash provided by operating activities		5,411,775			3,607,502
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and natural gas properties		(28,725,363	)		(20,429,090	)
Leasehold expenditures, net		(5,614,924	)		(19,841,843	)
Acquisition of oil and natural gas properties		-			(23,967,283	)
Sale of oil and natural gas properties		1,024,663			6,990,681
Sale and leaseback of gas compression equipment		1,202,000			-
Acquisitions/additions of pipeline, property, and equipment		(356,288	)		(3,787,922	)
Additions in other investments		(4,759	)		(475,000	)
Sales of other investments		457,762			-
Other		-			13,096
Net cash used in investing activities		(32,016,909	)		(61,497,361	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term bank borrowings		5,335,000			830,000
Short-term bank payments		(4,459,173	)		(7,030,000	)
Advances on senior secured credit facility		26,000,000			40,000,000
Payments on senior secured credit facility		(1,000,000	)		-
Payments on mortgage obligations and notes payable		(157,115	)		(32,080	)
Payments of financing fees on credit facilities		(152,826	)		(2,386,613	)
Capital contributions from minority interest members		24,837			-
Distributions to minority interest members		(49,839	)		-
Proceeds from exercise of options and warrants		64,999			18,144,449
Other		(15,647	)		(21,582	)
Net cash provided by financing activities		25,590,236			49,504,174
Net decrease in cash and cash equivalents		(1,014,898	)		(8,385,685	)
Cash and cash equivalents, beginning of the period		1,735,396			11,980,638
Cash and cash equivalents, end of the period	$	720,498		$	3,594,953

6

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited-continued)

Six Months Ended June 30,
2007	2006

NONCASH FINANCING AND INVESTING ACTIVITIES:
Oil and natural gas properties asset retirement obligation	$	(370,842	)	$	976,340
Accrued exploration and development costs on oil and natural gas properties		2,945,868			1,716,283
Accrued leasehold costs		348,345			427,859
Pipeline acquisition, transfer of investment to pipeline assets		-			1,100,973
Oil and natural gas properties capitalized stock-based compensation		133,767			365,293
Conversion of redeemable convertible preferred stock to common stock		-			40,001
Conversion of accounts receivable to long-term notes receivable		26,349			60,000
Vehicle purchase through financing		94,407			-
Common stock received in connection with the sale of mining claims		56,885			-
SUPPLEMENTAL INFORMATION OF INTEREST AND INCOME TAXES PAID:
Interest, net of amount capitalized of $1,857,689 and $646,977, respectively	$	1,352,151		$	2,783,248
Income taxes		107,700			5,463

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 and the New Albany shale of Indiana and Kentucky.

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 amounts as reported in the 2006 financial statements have been reclassified to conform with the 2007 presentation.

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

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 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.

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.

9

URORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Three Months Ended June 30,	2007		2006
Beginning balance	$	766,670	$	827,871
Liabilities incurred		56,523		263,026
Liabilities settled		-		-
Accretion expense		12,217		21,749
Revisions of estimated liabilities		154,475		(99,317	)
Ending balance	$	989,885	$	1,013,329

Six Months Ended June 30,	2007			2006
Beginning balance	$	1,331,893		$	812,634
Liabilities incurred		123,861			263,026
Liabilities settled		(34,293	)		-
Accretion expense		31,112			36,986
Revisions of estimated liabilities		(462,688	)		(99,317	)
Ending balance	$	989,885		$	1,013,329

Derivative Instruments

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

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

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	$	2,481,798
April 2007—December 2008		Collar		2,000 mmbtu	$	7.55/$ 9.00		129,597
January 2009—December 2009		Swap		7,000 mmbtu	$	8.72		72,968
January 2010—March 2011		Swap		7,000 mmbtu	$	8.68		78,071
Total Estimated Fair Value							$	2,762,434

10

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the six months ended June 30, 2007, the Company has recognized in Comprehensive Income changes in fair value of $(1,099,949) 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 six months ended June 30, 2007, and 2006, the Company recognized $1,358,250 and $792,350, respectively, in net gains from hedging activities included in oil and natural gas revenues. For the three months ended June 30, 2007, and 2006, the Company recognized $573,250 and $792,350, respectively, in net gains from hedging activities included in oil and natural gas revenues.

In July 2007, the Company entered into the following fixed swap contracts: 1) 2,000 mmbtu per day with a fixed price of $8.41 per mmbtu for the period from January 1, 2008 through December 31, 2008; and 2) 7,000 mmbtu per day with a fixed price of $7.62 per mmbtu for the period from April 1, 2011 through September 30, 2011.

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.

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 June 30,	2007		2006
General and administrative expenses	$	607,712	$	234,757
Oil and natural gas properties		66,431		152,219
Total	$	674,143	$	386,976

For the Six Months Ended June 30,	2007		2006
General and administrative expenses	$	1,201,756	$	392,149
Oil and natural gas properties		133,767		365,293
Total	$	1,335,523	$	757,442

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 June 30,	2007		2006
Net income (loss)	$	229,477	$	(1,185,188	)
Other comprehensive income:
Change in fair value of derivative instruments		1,927,644		1,754,365
Comprehensive Income	$	2,157,121	$	569,177

Six Months Ended June 30,	2007			2006
Net loss	$	(510,842	)	$	(1,949,846	)
Other comprehensive income:
Change in fair value of derivative instruments		(1,099,949	)		1,754,365
Comprehensive Loss	$	(1,610,791	)	$	(195,481	)

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. For the three months ended June 30, 2007, the effect of stock options representing 2,395,780 common shares were excluded from the calculation of diluted earnings per share as their inclusion would have been antidilutive because the exercise price of the options was greater than the average market price of the common stock during the period. All dilutive securities were excluded in the computation of diluted loss per share for all other periods 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 - 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.

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2007 - Kansas Project

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

NOTE 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 June 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 expects to develop definitive disposal plan in the upcoming months and has currently removed properties held for sale from the balance sheet.

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. As of June 30, 2007, our total borrowing capacity available under this facility was $3.6 million. To secure this line of credit, two trusts controlled by an executive officer pledged certain shares of the Company’s common stock under his control. The interest rate under the revolving line of credit is Wall Street prime (8.25% at June 30, 2007, and 2006, respectively) 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 15, 2007. Northwestern Bank also provides letters of credit for the drilling program (as described in Note 9 “Commitments and Contingencies”). Interest expense on the Northwestern Bank revolving line for the three months ended June 30, 2007, and 2006, was $6,015 and $106,626, respectively. Interest expense on the Northwestern Bank revolving line for the six months ended June 30, 2007, and 2006, was $6,882 and $178,454, 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 (8.25% at June 30, 2007) with interest payable monthly in arrears. Principal is payable at the expiration of the revolving line of credit agreement. The expiration date is October 1, 2007. Interest expense for the three and six months ended June 30, 2007, was $180 and $1,343, respectively.

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Mortgage and Notes Payable - Bach

As of June 30, 2007, Bach’s outstanding loans were as follows with interest expense for the three and six months ended June 30, 2007:

										Interest Expense
Description of Loan	Date of Loan		Maturity Date		Interest Rate			Principal Amount Outstanding		Three Months Ended June 30, 2007		Six Months Ended June 30, 2007
Mortgage payable on building		10/06/06		10/15/09		6.00	%	$	374,587	$	5,414	$	11,344
Notes payable
Vehicles		10/06/06		10/01/10		7.50	%		79,240		1,553		3,205
Equipment		10/06/06		09/01/07		5.50	%		3,093		85		232
Vehicles		12/18/06		12/20/09		7.25	%		59,492		1,168		2,437
Vehicles		04/23/07		04/25/11		7.00	%		91,003		569		569
Total notes payable								$	232,828	$	3,375	$	6,443

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 June 30, 2007, the principal amount outstanding was $2,754,154. Interest expense for the three months ended June 30, 2007, and 2006, was $33,089 and $52,465, respectively. Interest expense for the six months ended June 30, 2007, and 2006, was $69,336 and $99,734, 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 is required beginning November 30, 2006, through August 1, 2007. The interest rate is 7.01% per year. As of June 30, 2007, the principal amount outstanding was $31,342. Interest expense for the three and six months ended June 30, 2007, was $1,091 and $2,273, respectively.

Mezzanine Financing

The Company has a 5-year $50 million mezzanine credit facility with Trust Company of the West (“TCW”) for the Michigan Antrim drilling program. The borrower is Aurora Antrim North (“North”), a wholly owned subsidiary of the Company. Upon closing of the BNP Paribas (“BNP”) senior secured credit facility discussed below, TCW now holds a second lien position in the Michigan Antrim natural gas properties. The interest rate is fixed at 11.5% per year, compounded quarterly, and payable in arrears. Beginning September 28, 2006, and quarterly thereafter, the required principal payment is 75% (100% if coverage deficiency or default occurs) of adjusted net cash flow determined by deducting specific expenses, including capital expenditures from “gross cash revenue.” The Company estimates that no principal payments on the mezzanine financing will be required until maturity because of the level of anticipated capital expenditures. The maturity date is September 30, 2009 with a commitment expiration date of August 12, 2007. The borrowing base is impacted by, among other factors, the fair value of the Company’s natural gas reserves that are pledged to TCW. Changes in the fair value of the natural gas reserves are caused by changes in prices for natural gas, operating expenses, and the results of drilling activity. A significant decline in the fair value of these reserves could reduce the borrowing base, and the Company may not be able to meet certain facility covenants.

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The mezzanine credit facility contains, among other things, certain covenants relating to restricted payments (as defined), loans or advances to others, additional indebtedness, and incurrence of liens and provides for the maintenance of certain financial and operating ratios, including current ratio and specified coverage ratios (collateral coverage and proved developed producing reserves coverage ratios).

As part of the mezzanine credit facility, the Company provided an affiliate of TCW an overriding royalty interest in certain properties 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 is 4%, subject to certain adjustments.

For the three months ended June 30, 2007, and 2006, interest and fees incurred for the mezzanine credit facility was $1,175,417 and $1,150,139, respectively. For the six months ended June 30, 2007, and 2006, interest and fees incurred for the mezzanine credit facility was $2,350,834 and $2,351,111, respectively.

Senior Secured Credit Facility

On January 31, 2006, the Company entered into a senior secured credit facility with BNP for drilling, development, and acquisitions, as well as other general corporate purposes. The borrower is North with a current borrowing base of $50 million. As proved reserves are added, this borrowing base may increase to $100 million with TCW consent. A required semiannual reserve report may result in an increase or decrease in credit availability. The security for this facility is a first lien position in certain Michigan Antrim assets; a guarantee from Aurora; and a guarantee from the Company secured by a pledge of its stock in Aurora. This facility matures the earlier of January 31, 2010, or 91 days prior to the maturity of the mezzanine credit facility, unless the Company elects to terminate the commitment earlier pursuant to the terms of the senior secured credit facility.

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 June 30, 2007, interest on the borrowings had a weighted average interest rate of 7.125%. For the three months ended June 30, 2007, and 2006, interest and fees incurred for the senior secured credit facility was $591,010 and $714,167, respectively. For the six months ended June 30, 2007, and 2006, interest and fees incurred for the senior secured credit facility was $979,235 and $1,106,397, respectively.

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, a prohibition on the Company’s ability to prepay the mezzanine credit facility, geographic limitations on operations to the United States, and maintenance of certain financial and operating ratios, including current ratio and specified coverage ratios (collateral coverage and proved developed producing reserves coverage ratios). Effective December 21, 2006, the senior secured credit facility was amended to eliminate the interest coverage ratio covenant for the fiscal quarter ending December 31, 2006, and to modify the 2007 fiscal quarters’ interest coverage ratio covenants.

On June 22, 2007, the senior secured credit facility was amended to modify the interest coverage ratio covenant for all remaining fiscal quarters in 2007. The interest coverage ratio will not, as of the last day of any 2007 fiscal quarter, permit the ratio of EBITDAX to Interest Expense for such period to be (i) less than 2.0 to 1.0 for the quarters ending June 30, 2007 and September 30, 2007 and (ii) less than 2.25 to 1.0 for fiscal quarter ending December 31, 2007. In addition, any swap agreements entered into by the parties may contain contingent requirements, agreements or covenants for North to post collateral or margin to secure its obligations under such swap agreement to cover market exposures.

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The Company has engaged BNP to arrange and syndicate a second lien term loan facility. The proposed loan facility provides for a 5-year term loan in an initial amount up to $50 million which may increase up to $70 million over the life of the loan facility. The proceeds of the loan will be used to refinance the Company’s existing mezzanine financing with TCW and for general corporate purposes. BNP has identified several lenders willing to participate in this syndication subsequent to the completion of due diligence and lenders internal credit approvals. If this syndication is completed, the borrowing base under the existing BNP senior secured credit facility will increase from the current authorized borrowing base of $50 million to $70 million. There is no assurance that this proposed loan facility will be completed as currently contemplated.

The Company has incurred deferred financing fees of approximately $406,000 from BNP and approximately $2,850,000 from TCW. The deferred financing fees are being amortized on a straight-line basis over the remaining terms of each debt obligation. Amortization expense is estimated to be $0.8 million per year through 2009. Amortization expense was $228,556 and $168,170 for the three months ended June 30, 2007, and 2006, respectively. Amortization expense was $446,790 and $383,146 for the six months ended June 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 $987,879 and $246,203 for the three months ended June 30, 2007, and 2006, respectively. Capitalized interest was $1,857,689 and $646,977 for the six months ended June 30, 2007, and 2006, respectively.

NOTE 7. SHAREHOLDERS’ EQUITY

Common Stock

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

In February, March, and May 2007, 80,000 common stock options were exercised by various Company employees under the existing stock option plans at an exercise price of $0.375 per share. The Company received $30,000 in conjunction with these exercises.

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 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.

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Common Stock Warrants

The following table provides information related to stock warrant activity for the six months ended June 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			1.59

NOTE 8. COMMON STOCK OPTIONS

As of June 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 provides activity for the stock option plans referenced above for the six months ended June 30, 2007:

	Number of Shares Underlying Options
Options outstanding at beginning of period		3,432,496
Options granted		185,000
Options exercised		(173,332	)
Options forfeited and other adjustments		(80,000	)
Options outstanding at end of period		3,364,164

The weighted average assumptions used in the Black-Scholes option-pricing model used to determine fair value 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 provides activity with respect to all stock options awarded for the six months ended June 30, 2007:

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	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		(173,332	)		0.38
Forfeitures and other adjustments		(80,000	)		5.03
Options outstanding at end of period		4,794,444		$	2.30	$	3,339,505
Exercisable at end of period		3,139,775		$	1.55	$	3,339,505
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 six months ended June 30, 2007, was approximately $304,000.

The following table provides the unrecognized compensation expense related to unvested stock options as of June 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	$	-	$	428,053	$	31,996	$	1,146
2nd Quarter		-		360,689		14,664		-
3rd Quarter		587,474		117,728		5,194		-
4th Quarter		547,100		97,844		2,893		-
Total	$	1,134,574	$	1,004,314	$	54,747	$	1,146	$	2,194,781

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

Range of Exercise Prices	Outstanding Shares		Weighted Average Life		Exercisable Shares		Weighted Average Life
$0.25 - $0.38		576,664		3.7		576,664		3.7
$0.50 - $0.75		1,440,000		1.6		1,440,000		1.6
$1.25 - $1.75		352,000		7.2		352,000		7.2
$2.23 - $3.55		498,280		6.8		120,280		2.4
$3.62		1,140,000		3.5		300,000		3.4
$4.45 - $4.70		627,500		8.3		190,831		7.9
$5.19 - $5.54		160,000		3.3		160,000		3.3
$0.25 - $5.54		4,794,444		4.2		3,139,775		3.3

NOTE 9. COMMITMENTS AND CONTINGENCIES

Environmental Risk

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

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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 June 30, 2007, letters of credit in the amount of $1,056,100 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.

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 is a participant with Savoy Energy, L.P. (“Savoy”) in a well known as the Fry 1-13 located in Mecosta County, Michigan. In late December 2006, the well experienced a blow-out event. Savoy currently is estimating costs of approximately $5.6 million for expenses associated with controlling the well and other related costs. The Company has a 13.33% cost interest (10% working interest) in this well to casing point and has paid approximately $762,000 to cover its portion of the loss.

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 June 30, 2007, there is no production associated with this working interest and development costs were approximately $12.0 million.

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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.

NOTE 11. SUBSEQUENT EVENT

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.

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ITEM 2. MANAGEMENT’s discussion and analysis of financial condition and results of operations

You should read the following discussion in conjunction with management’s discussion and analysis contained in our 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 and New Albany shale of Southern Indiana and Western Kentucky.

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 six months ended June 30, 2007, we continued to shift our focus from acquisition of properties to an early stage developer of unconventional shale development projects. As of June 30, 2007, our leasehold acres (both developed and undeveloped) were 1,312,331 (718,699 net) which represent a 8% increase over our December 31, 2006 net acres. Of the 95,552 (28,808 net) leasehold acres increase, 1,874 net acres were acquired in the Antrim shale play, 14,708 net acres were acquired in the New Albany shale play, 35,417 net acres were acquired in the Other plays, and 23,191 net acres were sold in the Other plays.

With regard to our strategy to generate growth through drilling, we drilled or participated in 58 (28 net) wells for the six months ended June 30, 2007, with a 91% success rate. Our Antrim drilling program was restricted for the first three months due to frost laws not allowing movement of drilling rigs. As of June 30, 2007, we had 504 (241 net) producing wells, 63 (35 net) wells awaiting hook-up, 31 (20 net) wells requiring resource assessment and 18 (8 net) wells temporary abandoned. We also continued our strategy to have greater control over our projects by operating 240 (223 net) wells, thus, operating 39% of our gross wells and 74% of our net wells. Of the 223 net wells operated by the Company, 173 net wells are producing in the Antrim; 28 net wells are awaiting hook-up primarily in the Antrim; 16 net wells requiring resource assessment primarily in the New Albany shale and Other; and 6 net wells are temporary abandoned in the Antrim.

Oil and natural gas production for the six months ended June 30, 2007, was 1,493,454 mcfe, a 15% increase over the 1,295,879 mcfe produced in the six months ended June 30, 2006. For the six months ended June 30, 2007, production continues to be hampered by delays bringing wells into production, and dewatering. The Company has seen its Michigan operated production significantly stabilize adding a 10% increase in existing Michigan operated production during the second quarter of 2007 as well as adding 5% net increase due to new wells being placed on-line.

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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 of June 1, 2007 through December 31, 2008. Integrys Energy Services, Inc. will be the Company’s primary marketing partner for all of Michigan operated properties. The Company expects this partnering to provide extensive market and pipeline knowledge, strong credit worthiness as well as back office support.

In order to reduce exposure to fluctuations in the price of natural gas, the Company has recently increased its natural gas hedge position by entering into the following financial swap contracts: (1) 2,000 mmbtu per day at a fixed price of $8.41 for the period from January 1, 2008 through December 31, 2008; (2) 7,000 mmbtu per day at a fixed price of $8.72 for the period from January 1, 2009 through December 31, 2009; (3) 7,000 mmbtu per day at a fixed price of $8.68 for the period from January 1, 2010 through March 31, 2011; and (4) 7,000 mmbtu per day at a fixed price of $7.62 for the period from April 1, 2011 through September 30, 2011. These additional derivative instruments provide the Company with a weighted average floor price of $8.53 per mmbtu on this first 7,000 mmbtu per day through September 30, 2011.

In connection with recent management changes, the Company is focusing attention on its oil and natural gas properties to ensure that its continued holdings and capital budgets are aligned with the Company’s long-term strategic plan. Our 2007 capital budget for drilling and related well work and infrastructure has been revised from an estimated $73.7 million with participation in 291 (182 net) wells to an estimated $52.9 million with participation in 162 (111 net) wells. The following table summarizes our revised 2007 drilling and related well work budget for our key exploration and development areas:

	Actual January 2007 - June 2007 (a)						Budget July 2007 - December 2007 (a)
Play/Trend	Gross Wells Drilled		Net Wells Drilled		Net Capital Expenditure Budget		Gross Wells Projected to be Drilled		Net Wells Projected to be Drilled		Net Capital Expenditure Budget
Antrim		29		12.94	$	7,150,000		49		41.29	$	20,253,000
New Albany		16		4.05		2,869,000		28		17.23		15,881,000
Other		12		10.93		2,425,000		28		24.85		4,304,000
Total		57		27.92	$	12,444,000		105		83.37	$	40,438,000
Operated		21		19.20	$	7,706,000		77		72.43	$	35,656,000
Non-operated		36		8.72		4,738,000		28		10.94		4,782,000
Total		57		27.92	$	12,444,000		105		83.37	$	40,438,000

Note: (a) Does not include costs for leasehold interest of $2.7 million for 2007 YTD actuals and $1.7 million for the second half 2007 budget

The Company has engaged BNP to arrange and syndicate a second lien term loan facility. The proposed loan facility provides for a 5-year term loan in an initial amount up to $50 million which may increase up to $70 million over the life of the loan facility. The proceeds of the loan will be used to refinance the Company’s existing mezzanine financing with TCW and for general corporate purposes. BNP has identified several lenders willing to participate in this syndication subsequent to the completion of due diligence and lenders internal credit approvals. If this syndication is completed, the borrowing base under the existing BNP senior secured credit facility will increase from the current authorized borrowing base of $50 million to $70 million. There is no assurance that this proposed loan facility will be completed as currently contemplated.

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Operating Statistics

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2007		2006		2007		2006
Net wells drilled
Antrim shale		4		19		12		28
New Albany shale (“NAS”)		4		2		4		4
Other		4		1		8		1
Dry		-		-		4		2
Total		12		22		28		35
Total net wells
Antrim—producing		227		154		227		154
Antrim—awaiting hookup		33		31		33		31
NAS—producing		1		-		1		-
NAS—awaiting hookup		1		3		1		3
Other—producing		13		15		13		15
Other—awaiting hookup		1		4		1		4
Total		276		207		276		207
Production
Natural gas (mcf)		720,385		630,206		1,410,820		1,224,551
Crude oil (bbls)		6,773		5,286		13,772		11,888
Natural gas equivalent		761,023		661,922		1,493,453		1,295,879
Average daily production
Natural gas (mcf)		7,916		6,925		7,795		6,765
Crude oil (bbls)		74		58		76		66
Natural gas equivalent		8,363		7,274		8,251		7,161
Average sales price includes effects of realized hedging
Natural gas (mcf)	$	8.60	$	8.18	$	8.33	$	8.33
Crude oil (bbls)	$	60.37	$	69.93	$	57.00	$	62.34
Natural gas equivalent	$	8.68	$	8.35	$	8.39	$	8.44
Production revenue
Natural gas	$	6,193,575	$	5,154,728	$	11,747,014	$	10,200,110
Crude oil		408,854		369,626		784,991	$	741,110
Total	$	6,602,429	$	5,524,354	$	12,532,005	$	10,941,220
Average expenses ($ per mcfe)
Production taxes	$	0.40	$	0.35	$	0.38	$	0.34
Post-production expenses	$	0.67	$	0.63	$	0.54	$	0.49
Lease operating expenses	$	2.22	$	1.36	$	2.23	$	1.71
General and administrative expense	$	2.59	$	2.53	$	2.83	$	2.50
General and administrative expense excluding stock-based compensation	$	1.79	$	1.95	$	2.03	$	1.92
Oil and natural gas depreciation, depletion and amortization expenses	$	1.02	$	1.61	$	1.02	$	1.55
Other assets depreciation and amortization	$	0.75	$	0.82	$	0.76	$	0.78
Interest expenses	$	1.40	$	2.98	$	1.37	$	2.75
Taxes	$	0.03	$	0.04	$	-	$	0.02
Number of employees including Bach		88		52		88		52

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Results of Operations

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

General. For the Current Quarter, the Company had a net income of $0.2 million, or $0.00 per diluted common share, on total revenues of $7.3 million. This compares to a net loss of $1.2 million, or $(0.01) per diluted common share, on total revenue of $5.7 million for the Prior Year Quarter. The $1.6 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 sale of mining claims.

Oil and Natural Gas Sales. During the Current Quarter, oil and natural gas sales were $6.6 million compared to $5.5 million in the Prior Year Quarter. The Company produced 761,023 mcfe at a weighted average price of $8.68 compared to 661,922 mcfe at a weighted average price of $8.35. This increase in production was due to new wells placed on-line and gains in stabilizing production. We had 241 net wells producing as of June 30, 2007, as compared to 169 net wells producing as of June 30, 2006. The weighted average price included $0.6 million and $0.8 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 92% of our oil and natural gas revenue for the Current Quarter.

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

	Three Months Ended June 30, 2007			Three Months Ended June 30, 2006
Play/Trend	(mcfe)		Amount	(mcfe)		Amount
Antrim	709,155	$	6,104,828	580,723	$	4,891,814
New Albany	12,548		98,944	6,647		49,108
Other	39,320		398,657	74,552		583,432
Total	761,023	$	6,602,429	661,922	$	5,524,354

Other Revenues. Other revenues increased by $0.5 million, or 237% to $0.7 million in the Current Quarter from $0.2 million in the Prior Year Quarter. This increase is attributed to the sale of mining claims ($0.4 million) and 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 $0.40 per mcfe in the Current Quarter compared to $0.35 per mcfe in the Prior Year Quarter.

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

Production and lease operating expenses were $2.2 million in the Current Quarter compared to $1.3 million in the Prior Year Quarter. On a per unit of production basis, production and lease operating expenses were $2.89 per mcfe in the Current Quarter compared to $1.99 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 $0.67 per mcfe, in the Current Quarter compared to $0.4 million, or $0.63 per mcfe, in the Prior Year Quarter, and lease operating expenses were $1.7 million, or $2.22 per mcfe, in the Current Quarter compared to $0.9 million, or $1.36 per mcfe, in the Prior Year Quarter.

Production and lease operating expenses for operated properties were $2.76 per mcfe in the Current Quarter while non-operated production and lease operating expenses were $3.30 per mcfe in the Current Quarter. Our operated Arrowhead project continues to negatively impact our operating cost controls and efficiency. Production and lease operating expenses for operated properties excluding Arrowhead were $2.48 per mmcfe in the Current Period.

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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 $45,824 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 increased by $0.3 million, or 17%, from the Prior Quarter. This increase is the result of executing our growth strategy. Our staffing requirements increased 13% to 59 employees for the Current Quarter compared to 52 employees in the Prior Year Quarter which excludes 29 employees from the Bach acquisition in October 2006.

Payroll and related costs increased by $0.8 million to $1.6 million in the Current Quarter due to higher stock-based compensation ($0.4 million), bonuses ($0.2 million) and staffing additions ($0.2 million). Legal, accounting, and other consulting services were reduced by $0.5 million to $0.4 million in the Current Quarter compared to $0.8 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 $0.5 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 $0.8 million and $1.1 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 $1.02 and $1.61 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 $1.1 million in the Current Quarter compared to $2.0 million in the Prior Year Quarter. This decrease is the result of a change in estimating capitalized interest and reduction in borrowing under the senior secured credit facility. 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.

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 $25,129 in the Current Quarter compared to $27,694 in the Prior Year Quarter.

Six Months Ended June 30, 2007, compared with Six Months Ended June 30, 2006

General. For the Current Period, the Company had a net loss of $0.5 million, or $(0.01) per diluted common share, on total revenues of $13.5 million. This compares to a net loss of $1.9 million, or $(0.03) per diluted common share, on total revenue of $11.4 million for the Prior Year Period. The $2.2 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 sale of mining claims.

25

Oil and Natural Gas Sales. During the Current Period, oil and natural gas sales were $12.5 million compared to $10.9 million in the Prior Year Period. The Company produced 1,493,453 mcfe at a weighted average price of $8.39 compared to 1,295,879 mcfe at a weighted average price of $8.44. This increase in production was due to new wells placed on-line and gains in stabilizing production in the second quarter of 2007. We had 241 net wells producing as of June 30, 2007, as compared to 169 net wells producing as of June 30, 2006. The weighted average price included $1.4 million and $0.8 million of realized gains from the gas derivative contract for 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:

	Six Months Ended June 30, 2007			Six Months Ended June 30, 2006
Play/Trend	(mcfe)		Amount	(mcfe)		Amount
Antrim	1,384,508	$	11,560,199	1,114,142	$	9,245,791
New Albany	22,892		173,344	9,130		69,101
Other	86,053		798,462	172,607		1,626,328
Total	1,493,453	$	12,532,005	1,295,879	$	10,941,220

Other Revenues. Other revenues increased by $0.6 million, or 99% to $1.0 million in the Current Period from $0.4 million in the Prior Year Period. This increase is attributed to the sale of mining claims ($0.4 million) and to the Bach acquisition ($0.2 million) in October 2006 which provides oil and natural gas field services.

Production Taxes. Production taxes were $0.6 million in the Current Period compared to $0.4 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 $0.38 per mcfe in the Current Period compared to $0.34 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 $4.1 million in the Current Period compared to $2.9 million in the Prior Year Period. On a per unit of production basis, production and lease operating expenses were $2.77 per mcfe in the Current Period compared to $2.20 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 $0.8 million, or $0.54 per mcfe, in the Current Period compared to $0.6 million, or $0.49 per mcfe, in the Prior Year Period, and lease operating expenses were $3.3 million, or $2.23 per mcfe, in the Current Period compared to $2.2 million, or $1.71 per mcfe, in the Prior Year Period.

Production and lease operating expenses for operated properties were $2.57 per mcfe in the Current Period while non-operated production and lease operating expenses were $3.40 per mcfe in the Current Period. Our operated Arrowhead project continues to negatively impact our operating cost controls and efficiency. Production and lease operating expenses for operated properties excluding Arrowhead were $2.27 per mmcfe in the Current Period.

Pipeline Operating Expenses and Field Services Expenses. Pipeline operating expenses were $0.2 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.

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General and Administrative Expenses. Our general and administrative expenses include officer and employee compensation, travel, audit, tax and legal fees, office supplies, utilities, insurance, consulting fees, and office related expense. General and administrative expenses in the Current Period increased by $1.0 million, or 31%, 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. Our staffing requirements increased 39% to 59 employees for the Current Period compared to 52 employees in the Prior Year Period which excludes 29 employees from the Bach acquisition.

Payroll and related costs increased by $1.8 million to $3.1 million in the Current Period due to higher stock-based compensation ($1.2 million), bonuses ($0.3 million) and staffing additions ($0.3 million). Legal, accounting, and other consulting services were reduced by $0.8 million to $0.7 million in the Current Period compared to $1.9 million in the Prior Year Period.

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 $0.8 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 $1.5 million and $2.0 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 $1.02 and $1.55 in the Current Period and the Prior Year Period, respectively.

Other Assets Depreciation and Amortization (“D&A”). D&A of other assets was $1.1 million in the Current Period, compared to $1.0 million in the Prior Year Period. This increase was primarily the result of additions in other assets.

Interest Expense. Interest expense was $2.1 million in the Current Period compared to $3.6 million in the Prior Year Period. This decrease is the result of a change in estimating capitalized interest and reduction in borrowing under the senior secured credit facility. 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.

Taxes, Other.Tax expense (refund) was ($53) in the Current Period compared to $29,361 in the Prior Year Period. This decrease primarily represents a 2003 Indiana property tax refund of $39,884 received in 2007. The Company has significant net operating loss carryforwards, thus no federal income tax expense has been recognized.

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. We may be required to adjust our capital expenditures if the anticipated debt financing is not obtained and we are not able to complete sales of non-core assets. Future cash flows are subject to a number of variables, including the level of production, natural gas prices and successful drilling efforts. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures

Our mezzanine financing is a $50 million credit facility with Trust Company of the West (“TCW”) for the Michigan Antrim shale drilling program. It has a maturity date of September 30, 2009 and commitment expiration date of August 12, 2007. Borrowings under the TCW credit facility as of June 30, 2007 were $40 million with available borrowing capacity of $10 million. The interest rate is fixed at 11.5% per year, calculated and payable in arrears. Beginning September 28, 2006 and quarterly thereafter, the required principal payment is 75% (100% if coverage deficiency or default occurs) of Adjusted Net Cash Flow determined by deducting applicable operating expenses and capital expenditures from gross revenue. The TCW borrowing base is subject to semi-annual re-determination and certain other re-determinations based upon several factors. The borrowing base is impacted by, among other factors, the fair value of our natural gas reserves that are pledged to TCW. Changes in the fair value of our oil and natural gas reserves are caused by changes in prices for natural gas and crude oil, operating expenses and the results of drilling activity. A significant decline in the fair value of these reserves could cause us to be unable to meet certain facility covenants, which could result in a reduction in our borrowing base. The TCW loan agreement prohibits the declaration or payment of dividends and contains certain covenants. As of June 30, 2007, we were in compliance with all of the applicable covenants.

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Our senior secured credit facility is a $100 million senior secured credit facility with BNP Paribas (“BNP”). The current borrowing base under this facility is $50 million and has not been updated for our 2006 year end reserves. As proved reserves are added, this borrowing base may increase up to $100 million with TCW consent. This facility matures the earlier of January 31, 2010, or 91 days prior to the maturity of the mezzanine credit facility. This facility provides for borrowings tied to prime rate or LIBOR plus 1.25 to 2.0% depending on the borrowing base utilization that we select. As of June 30, 2007, interest on borrowings under our senior credit facility had a weighted average interest rate of 7.125% and our total borrowings under this facility were $35 million. A required semi-annual reserve report may result in an increase or decrease in credit availability.

The senior secured credit facility contains, among other things, certain covenants relating to restricted payments, loans or advances to others, additional indebtedness, and incurrence of liens. It also provides for the maintenance of certain financial and operating ratios, including current ratio and specified coverage ratios (collateral coverage and proved developed producing reserves coverage ratios). Effective December 21, 2006, the senior secured credit facility was amended to eliminate the interest coverage ratio covenant for the fiscal quarter ending December 31, 2006, and to modify the 2007 fiscal quarters’ interest coverage ratio covenants. On June 22, 2007, the senior secured credit facility was amended to modify the interest coverage ratio covenant for all remaining fiscal quarters in 2007. The interest coverage ratio will not, as of the last day of any 2007 fiscal quarter, permit the ratio of EBITDAX to Interest Expense for such period to be (i) less than 2.0 to 1.0 for the quarters ending June 30, 2007 and September 30, 2007 and (ii) less than 2.25 to 1.0 for fiscal quarter ending December 31, 2007. As of June 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 June 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.

Our total capitalization was as follows:

	As of June 30, 2007		As of December 31, 2006
Short-term bank borrowings	$	1,418,615	$	542,788
Obligations under capital lease		11,545		17,096
Notes payable		264,170		280,321
Mortgage payables		3,128,741		3,175,298
Mezzanine financing		40,000,000		40,000,000
Senior secured credit facility		35,000,000		10,000,000
Total debt		79,823,071		54,015,503
Shareholders’ equity		138,005,484		139,731,099
Total capitalization	$	217,828,555	$	193,746,602

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Cash Flows from Operating Activities

Cash provided by operating activities was $5.4 million in the Current Period, compared to cash provided by operating activities of $3.6 million in the Prior Year Period. The $1.8 million increase in cash provided by operating activities primarily due to higher production volumes offset by higher operating expenses. The Current Period cash flow provided by operating activities included; (1) $2.7 million received from joint interest partners for development projects and drilling advances; (2) $4.3 million in non-cash charges; (3) $0.4 million decrease in other investment and subsidiaries: (4) $0.2 million received from notes receivable; (5) $0.9 million decrease in current assets and liabilities; and (6) a net loss of $0.5 million. See Results of Operations” for discussion of changes in revenues and expenses.

Cash Flows Used in Investing Activities

Cash flows used in investing activities was $32.0 million in the Current Period, compared to $61.5 million in the Prior Year Period. The following table describes our significant investing transactions that we completed in the periods set forth below:

	Six Months Ended June 30,
	2007		2006
Acquisitions of leasehold
Antrim shale	$	915,684	$	4,496,399
New Albany shale		1,250,111		13,485,397
Other		3,449,129		1,232,308
Drilling and development of oil and natural gas properties
Antrim shale		14,571,159		10,337,497
New Albany shale		3,988,899		307,421
Other		908,678		2,784,404
Infrastructure properties
Antrim shale		6,321,732		6,334,665
New Albany shale		276,234		-
Other		10,288		18,785
Capitalized interest and general and administrative costs on exploration, development and leasehold		2,648,373		1,274,057
Acquisitions of oil and natural gas properties		-		23,967,283
Acquisitions/additions for pipeline, property, and equipment		356,288		3,787,922
Other, net		4,759		475,000
Subtotal of capital expenditures		34,701,334		68,501,138
Sale of oil and natural gas properties		1,024,663		6,990,681
Sale and leaseback of gas compression equipment		1,202,000		-
Sales of other investment and other		457,762		13,096
Subtotal of capital divestitures		2,684,425		7,003,777
Total	$	32,016,909	$	61,497,361

Cash Flows Provided by Financing Activities

Cash flows provided by financing activities were $25.6 million in the Current Period compared to $49.5 million in the Prior Year Period. Cash flows provided in the Current Period included: (1) $26.0 million of senior secured credit borrowing; and (2) $5.3 million of short-term bank borrowings. Cash flows used in the Current Period included: (1) pay-down of $4.5 within short-term bank borrowings; (2) pay-down of $1.0 million in senior credit borrowings; (3) pay-down of $0.2 million in mortgage obligations; and (3) payment of $0.2 million in financing fees.

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Cash flows provided by financing activities in the Prior Year Period included: (1) $40.0 million of senior secured credit borrowing; (2) $18.1 million of net proceeds received from exercise of common stock options and warrants; and (3) $0.8 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 $0.1 million within mortgage obligations and other.

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 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 June 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	$	2,481,798
April 2007—December 2008		Collar		2,000 mmbtu	$	7.55/$ 9.00		129,597
January 2009—December 2009		Swap		7,000 mmbtu	$	8.72		72,968
January 2010—March 2011		Swap		7,000 mmbtu	$	8.68		78,071
Total Estimated Fair Value							$	2,762,434

In July 2007, the Company entered into the following fixed swap contracts: 1) 2,000 mmbtu per day with a fixed price of $8.41 per mmbtu for the period from January 1, 2008 through December 31, 2008; and 2) 7,000 mmbtu per day with a fixed price of $7.62 per mmbtu for the period from April 1, 2011 through September 30, 2011.

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Interest Rate Risk

The Company does not use interest rate derivatives to mitigate exposure to changes in interest rates. The following table sets forth the Company’s principal financing obligation and the related interest rates as of June 30, 2007:

	Expected Maturity	Average Interest Rate as of June 30, 2007	Principal Outstanding
Short-term bank borrowings	Revolving	Variable - 8.25%	1,418,615
Obligations under capital lease	01/10/09	8.25%	11,545
Notes payable	08/01/07-04/25/11	5.50% - 7.50%	264,170
Mortgage payable	10/15/09	Fixed at 6.00%	374,587
Mortgage payable	10/01/08	Fixed at 6.50%	2,754,154
Mezzanine financing	09/30/09	Fixed at 11.50%	35,000,000
Senior secured credit facility	01/31/10	Variable - 7.125%	40,000,000
Total debt			$79,823,071

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Our Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) of the Securities Exchange Act of 1934, as amended) as of June 30, 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.

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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 June 30, 2007.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

Our annual meeting of the shareholders was held on May 18, 2007 for the purposes of electing the Board of Directors. Each of the Company’s nominees for Board of Directors, as listed in the proxy statement, was elected with the number of votes set forth below.

Name	For	Against
William W. Deneau	81,519,752	1,330,616
Gary J. Myles	80,514,242	2,336,126
Earl V. Young	81,405,429	1,444,939
Wayne G. Schaeffer	81,433,350	1,417,018
Kevin D. Stulp	81,582,793	1,287,575
Richard M. Deneau	81,525,352	1,325,016
Ronald E. Huff	80,588,125	2,262,243

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.
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.)

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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.
10.7(2)	Credit Agreement among Aurora Antrim North, L.L.C., et al. and BNP Paribas, et al., dated January 31, 2006.
10.8(2)	Intercreditor and Subordination Agreement among BNP Paribas, et al., TCW Asset Management Company, and Aurora Antrim North, L.L.C., dated January 31, 2006.
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.
*31.1	Rule 13a-14(a) Certification of Principal Executive Officer.
*31.2	Rule 13a-14(a) Certification of Principal Financial and Accounting Officer.
*32.1	Section 1350 Certification of Principal Executive Officer.
*32.2	Section 1350 Certification of Principal Financial and Accounting Officer.

* Filed with this Form 10-Q.

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

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

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

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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: August 9, 2007	By:	/s/ William W. Deneau
		Name:William W. Deneau Title:Chief Executive Officer

Date: August 9, 2007	By:	/s/ Ronald E. Huff
		Name:Ronald E. Huff Title:President and Chief Financial Officer

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