Aurora Oil & Gas 10QSB 2006 Q4 Quarterly report (small business)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-QSB

S QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the quarterly period ended September 30, 2006.

£ TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE EXCHANGE ACT

For the transition period from:

Commission file number: 000-25170

Aurora Oil & Gas Corporation

^{(Exact name of small business issuer as specified in its charter)}

Utah

^{(State or other jurisdiction of incorporation or organization)}

87-0306609

^{(IRS Employer Identification No.)}

4110 Copper Ridge Drive, Suite 100, Traverse City, MI 49684

^{(Address of principal executive offices)}

(231) 941-0073

^{(Issuer’s telephone number)}

_________________________________________________________________________ 

^{(Former name, former address and former fiscal year, if changed since last report)}

Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 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 S No £

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

Yes £ No S

State the number of shares outstanding of each of the issuer’s classes of common equity, as of the latest practicable date: 103,062,966.

Transitional Small Business Disclosure Format (Check one): Yes £ No S

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

			Page
PART I			1
	ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
		Report of Independent Registered Public Accounting Firm	2
		Condensed Consolidated Balance Sheets as of September 30, 2006 (Unaudited) and December 31, 2005	3-4
		Unaudited Statements of Operations for the Three Months and
		Nine Months Ended September 30, 2006 and 2005	5
		Unaudited Statement of Shareholders’ Equity for the Nine Months Ended September 30, 2006	6
		Unaudited Statements of Cash Flows for the Nine Months Ended September 30, 2006 and 2005	7-8
		Notes to Unaudited Condensed Consolidated Financial Statements	9
	ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		22
	ITEM 3. CONTROLS AND PROCEDURES		34
PART II			35
	ITEM 1. LEGAL PROCEEDINGS		35
	ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES		35
	ITEM 3. DEFAULTS UPON SENIOR SECURITIES		35
	ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		35
	ITEM 5. OTHER INFORMATION		35
	ITEM 6. EXHIBITS		35

PART I

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (“Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). 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 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 credit.

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.

1

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Aurora Oil & Gas Corporation and Subsidiaries

Traverse City, Michigan

We have reviewed the accompanying condensed consolidated balance sheet of Aurora Oil & Gas Corporation and Subsidiaries as of September 30, 2006, and the related condensed consolidated statements of operations for the three month and nine month periods ended September 30, 2006 and 2005, shareholders’ equity for the nine month period ended September 30, 2006, and cash flows for the nine month periods ended September 30, 2006 and 2005. These condensed consolidated interim financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to the accompanying condensed consolidated financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Aurora Oil & Gas Corporation and Subsidiaries as of December 31, 2005, and the related consolidated statements of operations, shareholders’ equity and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2006, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2005, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

RACHLIN COHEN & HOLTZ LLP

Miami, Florida

November 13, 2006

2

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30,			December 31,
	2006			2005
ASSETS	(Unaudited)			(Audited)
CURRENT ASSETS:
Cash and cash equivalents	$	2,999,305		$	11,980,638
Accounts receivable
Oil and gas sales		2,568,561			2,409,675
Joint interest owners		4,264,430			4,380,606
Notes receivable
Related party		94,956			35,720
Other		299,744			208,626
Drilling advances		1,261,540			-
Prepaid expenses		318,159			240,242
Short-term derivative instruments		3,105,365			-
Total current assets		14,912,060			19,255,507
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, using full cost accounting:
Proved properties		91,084,766			39,643,003
Unproved properties		44,989,813			37,279,889
Properties held for sale		7,653,612			-
Less: accumulated depletion and amortization		(10,854,451	)		(7,962,138	)
Total oil and natural gas properties, net		132,873,740			68,960,754
Pipelines		4,831,358			-
Other property and equipment		3,967,201			3,723,918
Less: accumulated depreciation		(581,434	)		(113,780	)
Total property and equipment, net		141,090,865			72,570,892
OTHER ASSETS:
Long-term derivative instruments		2,091,473			-
Deposits on purchase of oil and gas properties		-			3,206,102
Goodwill		15,973,346			15,973,346
Intangibles (net of accumulated amortization of
$2,558,333 and $1,407,083, respectively)		2,046,667			3,197,917
Other investments		814,958			1,855,977
Debt issuance costs (net of accumulated amortization
of $677,389 and $79,096, respectively)		2,512,916			723,993
Other		329,641			38,411
Total other assets		23,769,001			24,995,746
TOTAL ASSETS	$	179,771,926		$	116,822,145

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

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30,			December 31,
	2006			2005
LIABILITIES AND SHAREHOLDERS' EQUITY	(Unaudited)			(Audited)
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	8,701,423		$	7,470,579
Short-term bank borrowings		3,610,000			6,210,000
Current portion of obligations under capital leases		4,818			8,823
Current portion of note payable - related party		-			69,833
Current portion of mortgage payable		83,240			72,877
Drilling advances		361,914			-
Deposit on sale of oil and gas properties		-			3,509,319
Total current liabilities		12,761,395			17,341,431
LONG-TERM LIABILITIES:
Obligations under capital leases, net of current portion		-			2,262
Asset retirement obligations		990,704			-
Mortgage payable		2,731,206			2,792,600
Senior secured credit facility		45,000,000			-
Mezzanine financing		40,000,000			40,000,000
Total long-term liabilities		88,721,910			42,794,862
Total liabilities		101,483,305			60,136,293
COMMITMENTS, CONTINGENCIES AND
SUBSEQUENT EVENTS
REDEEMABLE CONVERTIBLE PREFERRED STOCK:
Authorized 20,000,000 shares; outstanding none
in 2006 and 34,984 shares in 2005		-			59,925
SHAREHOLDERS' EQUITY:
Common stock, $.01 par value; authorized 250,000,000
shares; issued and outstanding 82,084,667 shares in
2006 and 61,536,261 shares in 2005		820,847			615,363
Additional paid-in capital		78,971,659			58,670,698
Accumulated other comprehensive income		5,196,838			-
Accumulated deficit		(6,700,723	)		(2,660,134	)
Total shareholders' equity		78,288,621			56,625,927
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	179,771,926		$	116,822,145

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

4

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
REVENUES:
Oil and natural gas sales	$	5,175,635		$	1,878,344		$	16,116,855		$	2,976,250
Pipeline revenue		364,586			-			865,454			-
Interest income		39,784			52,723			283,998			218,633
Equity in (loss) income of
unconsolidated subsidiary		(67,997	)		(10,166	)		(226,711	)		2,231
Other income		41,016			126,696			137,147			476,307
Total revenues		5,553,024			2,047,597			17,176,743			3,673,421
EXPENSES:
General and administrative		2,046,497			766,778			5,289,210			1,875,674
Pipeline operating expenses		188,537			-			472,738			-
Production and lease operating		1,692,080			609,210			5,103,131			1,262,167
Depletion, depreciation and amortization		1,406,011			250,561			4,430,177			338,061
Interest expense		2,279,760			264,902			5,843,914			516,983
Taxes		9,928			4,003			39,289			259,200
Total expenses		7,622,813			1,895,454			21,178,459			4,252,085
INCOME (LOSS) BEFORE MINORITY
INTEREST		(2,069,789	)		152,143			(4,001,716	)		(578,664	)
MINORITY INTEREST IN (INCOME)
LOSS OF SUBSIDIARIES		(16,445	)		25,534			(34,364	)		19,344
NET INCOME (LOSS)	$	(2,086,234	)	$	177,677		$	(4,036,080	)	$	(559,320	)
NET INCOME (LOSS) PER COMMON
SHARE - BASIC AND DILUTED	$	(0.03	)	$	0.01		$	(0.05	)	$	(0.02	)
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING - BASIC
AND DILUTED		82,042,049			38,092,366			78,043,518			36,816,852

Supplemental Information

Net loss for the three and nine months ended September 30, 2006, included stock-based compensation expense under Statement of Financial Accounting Standards No. 123 (revised 2004). The Company recorded stock-based compensation of $957,028 and $1,349,177 under general and administrative expense for the three and nine months ended September 30, 2006, respectively. There was no stock-based compensation expense for the three and nine months ended September 30, 2005 (historical or proforma basis). See Note 9 “Stock-Based Compensation” for additional information.

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

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY

NINE MONTHS ENDED SEPTEMBER 30, 2006

(Unaudited)

COMMON STOCK:	Shares		Amount
Balance, beginning		61,536,261	$	615,363
Cashless exercise of common stock options and warrants		3,280,105		32,801
Conversion of redeemable convertible preferred stock to common stock		34,984		349
Exercise of common stock options and warrants		15,673,457		156,735
Issuance of common stock to related party		90,000		900
Issuance of common stock to related party in lieu
of commission relating to exercise of warrants		1,469,860		14,699
Balance, end		82,084,667		820,847
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning				58,670,698
Cashless exercise of common stock options and warrants				(32,801	)
Conversion of redeemable convertible preferred stock to common stock				59,576
Stock-based compensation				1,909,871
Exercise of common stock options and warrants				18,030,714
Issuance of common stock to related party				348,300
Issuance of common stock to related party in lieu of commission
relating to exercise of warrants				(14,699	)
Balance, end				78,971,659
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Balance, beginning				-
Unrealized gains on derivative instruments				6,991,488
Recognition of gain on derivative instruments				(1,794,650	)
Balance, end				5,196,838
ACCUMULATED DEFICIT:
Balance, beginning				(2,660,134	)
Dividends accrued				(4,509	)
Net loss				(4,036,080	)
Balance, end				(6,700,723	)
TOTAL SHAREHOLDERS' EQUITY			$	78,288,621

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

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended
	September 30,
CASH FLOWS FROM OPERATING ACTIVITIES:	2006			2005
Net loss	$	(4,036,080	)	$	(559,320	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		4,430,177			338,061
Amortization of debt issuance costs		598,569			47,989
Accretion of asset retirement obligations		53,708			-
Stock-based compensation		1,349,177			-
Equity in (income) loss of unconsolidated subsidiary		226,711			(2,231	)
Other		(32,350	)		-
Minority interest in loss (income) of subsidiaries		34,364			(19,344	)
Changes in operating assets and liabilities, net
Accounts receivable		189,655			(2,074,555	)
Accounts receivable - related party		-			(68,393	)
Drilling advance assets		(1,261,540	)		-
Prepaid expenses		(77,917	)		(22,855	)
Accounts payable and accrued liabilities		1,221,524			1,300,338
Drilling advance liabilities		361,914			(387,175	)
Net cash provided by (used in) operating activities		3,057,912			(1,447,485	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for oil and natural gas development		(56,416,435	)		(25,502,472	)
Capital expenditures for property and equipment		(256,163	)		(555,972	)
Proceeds from sale of oil and natural gas properties		15,250,000			7,717,851
Proceeds from sale of other investments		165,082			-
Payments for merger costs		-			(407,496	)
Advances on notes receivable		(93,118	)		(72,379	)
Advances on notes receivable - related parties		(77,956	)		-
Payments received on notes receivable - related parties		20,720			85,000
Purchase of member interest in Hudson Pipelines and Processing Co., L.L.C.		(162,108	)		(501,956	)
Investment in unconsolidated subsidiary		(577,088	)		(125,000	)
Net cash used in investing activities		(42,147,066	)		(19,362,424	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net payments on short-term bank borrowings		(2,600,000	)		(350,000	)
Advances on senior secured credit facility, net of financing costs of $2,386,613		14,997,394			-
Advances on mezzanine financing, net of financing costs of $300,000		-			19,700,000
Payments on mortgage obligation		(51,031	)		-
Payments on notes payable - related party		(69,833	)		(2,948,698	)
Payments on capital lease obligations		(6,267	)		(8,283	)
Distributions to minority interest members		-			(805,000	)
Net proceeds from sales of common stock		-			11,025,000
Net proceeds from exercise of options and warrants		18,187,449			-
Dividends paid on preferred stock		(20,250	)		(44,340	)
Other		(329,641	)		(720	)
Net cash provided by financing activities		30,107,821			26,567,959

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Continued) (Unaudited)

	Nine Months Ended
	September 30,
	2006			2005
Net (decrease) increase in cash and cash equivalents		(8,981,333	)		5,758,050
Cash and cash equivalents, beginning of the period		11,980,638			5,179,582
Cash and cash equivalents, end of the period	$	2,999,305		$	10,937,632
NON-CASH FINANCING AND INVESTING ACTIVITIES:
Oil and natural gas properties asset retirement obligations	$	936,996		$	-
Purchase of oil and gas working interest through senior secured credit facility	$	27,615,993		$	-
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for interest	$	5,418,864		$	1,250,958

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

8

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”) amended its articles of incorporation to change its name to Aurora Oil & Gas Corporation (“AOG”). AOG and its wholly owned subsidiaries are referred to collectively as the “Company”. The Company is an oil and gas corporation 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.

On October 31, 2005, AOG (formerly Cadence) acquired Aurora Energy, Ltd. (“Aurora”) through the merger of a wholly owned subsidiary with and into Aurora. As a result of the merger, Aurora became a wholly-owned subsidiary. The merger has been accounted for as a reverse acquisition using the purchase method of accounting. Although the merger was structured such that Aurora became a wholly-owned subsidiary of AOG (formerly Cadence), Aurora has been treated as the acquiring company for accounting purposes under Statement of Financial Accounting Standards (“SFAS”) No. 141, “Business Combinations”, due to the following factors: (1) Aurora’s stockholders received the larger share of the voting rights in the merger; (2) Aurora received the majority of the members of the board of directors; and (3) Aurora’s senior management prior to the merger dominated the senior management of the combined company.

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. To cover most of the existing production, the Company recently entered into a firm delivery gas contract to be effective for the period April 1, 2006 through March 31, 2007 for the delivery of 5,000 mmbtu per day. The Company will be paid $0.01 per mmbtu less than the published index for this gas. The Company also has three other base contracts for the sale of natural gas. The Company sets the firm delivery volume obligation under these contracts on either a monthly or a daily basis, with the amount of its obligation varying from month to month or day to day. As new wells come on-line and production volume increases, new production will be sold in the spot markets or under the base contracts.

As an independent oil and natural gas producer, 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

The financial information included herein is unaudited, except the balance sheet as of December 31, 2005, which has been derived from our audited consolidated financial statements as of December 31, 2005. 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 2005 financial statements have been reclassified to conform with the 2006 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-QSB 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, 2005.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

As a result of the reverse acquisition discussed in Note 1, the historical financial statements presented for periods prior to the acquisition date are the financial statements of Aurora. The operations of the former Cadence businesses have been included in the consolidated financial statements from the date of acquisition. The common stock per share information in the condensed consolidated financial statements for the three months and nine months ended September 30, 2005 and related notes have been retroactively adjusted to give effect to the reverse merger on October 31, 2005.

NOTE 3.ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT OBLIGATIONS

On January 1, 2006, the Company adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” and FASB Statement No. 143 “Accounting for Asset Retirement Obligations.” This Interpretation clarifies that the term “conditional asset retirement obligation” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. 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 estimated the fair value of the obligation 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. Prior to January 1, 2006, such amount was not considered material.

Effective January 1, 2006, the Company recorded a liability of $812,634 (an “asset retirement obligation” or “ARO”) on the consolidated balance sheet and capitalized the asset retirement cost to oil and gas properties. In general, the amount of an 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. The accretion expense is included in interest expense and the depreciation expense is included in depreciation, depletion and amortization on the condensed consolidated statement of operations.

The change in the ARO for the three and nine months ended September 30, 2006 is as follows:

	Three Months Ended September 30, 2006			Nine Months Ended September 30, 2006
Beginning balance	$	1,013,329		$	812,634
Liabilities incurred		106,763			369,789
Liabilities settled		(123,809	)		(123,809	)
Accretion expense		16,722			53,708
Revisions of estimated liabilities		(22,301	)		(121,618	)
Ending balance	$	990,704		$	990,704

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 4.RECENT ACCOUNTING PRONOUNCEMENTS

In February 2006, the FASB issued SFAS 155, “Accounting for Certain Hybrid Financial Instruments” which eliminates the exemption from applying SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments. SFAS 155 also allows the election of fair value measurement at acquisition, at issuance, or when a previously recognized financial instrument is subject to a re-measurement event. Adoption is effective for all financial instruments acquired or issued after the beginning of the first fiscal year that begins after September 15, 2006. Management believes the adoption of this standard will not have a material impact on the Company’s consolidated financial position, results of operations, or liquidity.

In February 2006, the FASB issued Financial Staff Position (“FSP”) FAS 123(R)-4 "Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event." This FSP amends SFAS No. 123(R), addressing cash settlement features that can be exercised only upon the occurrence of a contingent event that is outside the employee's control. These instruments are not required to be classified as a liability until it becomes probable that the event will occur. The Company adopted this FSP in the second quarter of 2006. The implementation did not have an effect on the results of operations or financial position.

In July 2006, the FASB issued Interpretation No. 48. This Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with SFAS Statement No. 109, “Accounting for Income Taxes.” This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. This Interpretation is effective for fiscal years beginning after December 15, 2006. Management is currently assessing the impact of Interpretation No. 48 on the results of operations and financial position.

In September 2006, the FASB issued SFAS 157, “Fair Value Measurements” which provides guidance for using fair value to measure assets and liabilities. The standard applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. The standard clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. The provisions of SFAS 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. Management believes the adoption of this standard will not have a material impact on the Company’s consolidated financial position, results of operations, or liquidity.

NOTE 5.RISK MANAGEMENT ACTIVITIES

Derivative Instruments

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

11

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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 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 balance sheet until the hedged item is recognized in earnings as 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 swap contracts were in place at September 30, 2006.

Period	Natural Gas Volume per Day		Fixed Price per mmbtu		Fair Value Asset
April 2006 - March 2007		5,000 mmbtu	$	8.59	$	1,666,235
April 2007 - December 2008		5,000 mmbtu	$	9.00		3,530,603
					$	5,196,838

For the nine months ended September 30, 2006, the Company has recognized in Accumulated Other Comprehensive Income, net unrealized gains of $5,196,838 on the swap contracts that have been designated as cash flow hedges on forecasted sales of natural gas. In addition, for the nine months ended September 30, 2006, the Company recognized $1,794,650 net gains from hedging activities included in oil and natural gas revenues. In 2005, the Company had no derivative instruments to manage price risk related to its natural gas production.

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.

NOTE 6.ACQUISITIONS AND DISPOSITIONS

2006 - Hudson Pipeline and Processing Co., L.L.C.

On January 31, 2006, Aurora Antrim North, L.L.C. (“North”), a wholly-owned subsidiary of Aurora, completed the acquisition of oil and gas leases, working interests, and interests in related pipelines and production facilities that are located in the Hudson Township area of the Michigan Antrim shale play. The interests acquired are collectively referred to as the Hudson Properties. In addition, interests in the related pipelines and production facilities were acquired by purchasing additional membership interests in Hudson Pipeline and Processing Co., L.L.C. (“HPPC”). North previously owned a working interest in the properties and a membership interest in HPPC. This acquisition increased North’s working interest in the Hudson Properties from an average of 49% to 96% and increased the membership interest in HPPC from 48.75% to 90.94%.

The total purchase price for the Hudson Properties and HPPC was approximately $27,500,000. North also acquired an additional 2.5% membership interest in HPPC effective January 1, 2006 which increased the membership interest to 93.44%.

12

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

With these increases in membership interest in HPPC, effective January 1, 2006, HPPC was converted from the equity method to being consolidated as a subsidiary in the Company’s accompanying condensed consolidated financial statements.

2006 - Wabash Project

On February 2, 2006, Aurora closed on two Purchase and Sale Agreements with respect to certain New Albany Shale acreage located in Indiana, commonly called the Wabash project. Aurora acquired 64,000 acres of oil and gas leases from Wabash Energy Partners, L.P. for a purchase price of $11,840,000. Aurora then sold half its interest in a combined 95,000 acre lease position in the Wabash project to New Albany-Indiana, L.L.C. (“New Albany”), an affiliate of Rex Energy Operating Corporation, for a sale price of $10,500,000. Internal funds of Aurora were used to pay the net transaction cost of these transactions.

2006 - DeSoto Parish, Louisiana

On July 20, 2006, the Company entered into a Purchase and Sale Agreement with respect to the DeSoto Parish, Louisiana properties to sell certain assets to BEUSA Energy, Inc. for a purchase price of $4,750,000. BEUSA Energy, Inc. is the current operator and joint interest owner in these properties. The properties included: 1) 14 gross wells with working interest ranging from 22.5% to 45%; 2) 4,480 (1,657 net) leasehold acres; and 3) various pipelines and facilities. The effective date of the sale was July 1, 2006.

2006 - Crossroads Project, Henry, Ohio

On August 15, 2006, the Company agreed to assign all of its working interests in the Crossroads Project located in Henry County, Ohio to an unrelated party. The 7.06% working interest included 15,519 (1,096 net) leasehold acres, 13 (0.92 net) wells and pipeline assets. Aurora agreed to pay $250,700 for disposition costs but will receive future pipeline revenue over the life of the project.

2005 - New Albany

On January 3, 2005, El Paso Corporation exercised an option to purchase 95% of the working interest in certain New Albany shale acreage in Indiana. As a result of this transaction, Aurora received gross proceeds in the amount of $7,373,737. After deducting a distribution to subsidiary members of $805,000 and an additional $1,000,000 set aside for the subsidiary’s share of anticipated future drilling expense, approximately $5,500,000 of net proceeds was retained by Aurora.

2005/2006 - GeoPetra Partners, LLC Investment

In June 2005, the Company acquired a 33% cost-sharing interest (30% revenue sharing interest) in GeoPetra Partners, LLC (“GeoPetra”) for $14,000. GeoPetra is a limited liability company engaged primarily in the following activities (i) identification and evaluation for acquisition of oil and gas properties and interests and entities which hold such properties and interests, (ii) areas to be explored and developed for the production of oil and gas and (iii) providing consultation, advice and recommendations to the members of GeoPetra in connection with other oil and gas properties and interests, operations and activities. GeoPetra was formed April 1, 2005. In July 2006, the Company finalized a sale of 18% of its 33% interest in GeoPetra to JetEx, LLC. This transaction reduced the gross investment made to GeoPetra by $199,000. Thus, as of September 30, 2006, the Company had contributed approximately $887,000 to GeoPetra with an investment balance of $547,055 at September 30, 2006.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

2005 - New Albany Corner #1 Project

In July 2005, the Company sold a 50% working interest in 28,610 leasehold acres located in the New Albany shale to Samson Resources Company for $344,100. This included an 80% net revenue interest in the existing leasehold acres.

NOTE 7.DEBT

Short-Term Bank Borrowings

On October 12, 2005, the Company entered into a $7.5 million revolving line-of-credit agreement with Northwestern Bank of Traverse City, Michigan (“Northwestern Bank”) for general corporate purposes. On January 31, 2006, the credit availability on this line of credit was reduced to $5.0 million to meet the requirements of the senior secured credit facility (as described below). To secure this line of credit, two trusts controlled by an executive officer pledged certain shares of the Company common stock under the officer control. The interest rate under the revolving line-of-credit is Wall Street prime with interest payable monthly in arrears. Principal is payable at the expiration of the revolving line-of-credit agreement. Northwestern Bank has recently extended the expiration date to October 15, 2007. Interest expense for the three and nine months ended September 30, 2006 was $70,280 and $248,734, respectively.

Note Payable - Related Parties

Through May 1, 2006, the Company was indebted under a note payable to a minority member of Indiana Royalty Trustory, L.L.C., an affiliated company, in the amount of $69,833. The interest rate was 10.5% per year. The note payable matured on May 1, 2006 and was paid in full.

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. During September 2006, Northwestern Bank released the personal guarantees of three of the Company’s officers that were previously provided as security on the mortgage loan. The payment schedule is monthly interest only for the first three 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. Interest expense for the three and nine months ended September 30, 2006 was $46,956 and $146,690, respectively.

Mezzanine Financing

On December 8, 2005, the Company entered into an Amended Note Purchase Agreement, to increase its five-year mezzanine credit facility with Trust Company of the West (“TCW”) from $30 million to $50 million for the Michigan Antrim drilling program. The borrower is North. 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. 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.

14

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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).

Pursuant to the mezzanine financing arrangement, North conveyed to TCW a 4% overriding royalty interest net to North’s interest, in all of North’s existing oil and gas leases in the counties of Alcona, Alpena, Charlevoix, Cheboygan, Montmorency and Otsego in the State of Michigan. Additionally, North is required to convey a 4% overriding royalty interest, net to its interest, in any new leases acquired in these counties while the loan is outstanding.

For the three months ended September 30, 2006, interest expense for the mezzanine credit facility was $1,175,417 of which $18,028 was capitalized. For the three months ended September 30, 2005 interest expense was $595,028 of which $344,461 was capitalized.

For the nine months ended September 30, 2006, interest expense for the mezzanine credit facility was $3,526,528 of which $573,550 was capitalized. For the nine months ended September 30, 2005 interest expense was $1,236,249 of which $801,128 was capitalized.

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. The initial borrowing base was $40 million without hedges. Effective July 14, 2006, the borrowing base was increased to $50 million. As proved reserves are added, this borrowing base may increase to $100 million with TCW consent. A required semi-annual 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. For the three months ended September 30, 2006, interest expense was $785,738 of which $12,677 was capitalized. For the nine months ended September 30, 2006, interest expense was $1,892,134 of which $104,132 was capitalized.

On July 14, 2006, the senior secured credit facility was amended to defer the trailing 12-month interest coverage ratio covenant until the fourth quarter of 2006, and to provide for a reduced ratio for that quarter. The trailing 12-month interest coverage ratio amendment was intended to correct a previous error in the covenant, which failed to account for the fact that the acquisition of the Hudson Properties (as described in Note 6 “Acquisitions and Dispositions”) in the first quarter of 2006 would not have a full trailing 12 months of cash flow included in the financial statements until the first quarter of 2007. This amendment supersedes the waiver BNP issued regarding the interest coverage covenant for the first quarter of 2006.

15

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

The senior secured credit facility contains, among other things, a number of financial and non-financial covenants relating to restricted payments (as defined), loans or advances to others, additional indebtedness, incurrence of liens; 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).

NOTE 8.COMMON STOCK

From late December 2005 through early February 2006, the Company reduced the exercise price of certain outstanding options and warrants in order to encourage the early exercise of these securities. Each holder who took advantage of the reduced exercise price was required to execute a six-month lock up agreement with respect to the shares issued in the exercise. As a result of the options and warrants exercised pursuant to this reduced exercise price arrangement, and pursuant to other exercises of outstanding options, an additional 20,423,422 shares were issued during the nine months ended September 30, 2006 representing 15,673,457 shares issued for cash proceeds of $18,187,449, and 4,749,965 shares issued pursuant to cashless exercises of the applicable warrants or options. In December 2005 an additional 2,160,000 shares were issued for cash proceeds of $2,916,000.

In June 2006, an officer of the Company was issued 30,000 shares for services provided in 2005. Compensation expense related to this activity was recorded in 2005.

Additionally in June 2006, two directors of the Company were issued 30,000 shares each for their services provided to Aurora as Board members prior to the merger with Cadence. Compensation expense related to this activity was recorded in 2005.

For the three and nine months ended September 30, 2006, a total of 11,650 shares and 34,984 shares, respectively, of redeemable convertible preferred stock were converted into common stock.

NOTE 9.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.

For the three months ended September 30, 2006, the Company recorded stock-based compensation of $1,152,429 under the 2006 Stock Incentive Plan (as described in Note 10 “Common Stock Options”) and a certain employment agreement (as described in Note 13 “Contingencies and Commitments”). Of that amount, $957,028 has been included in general and administrative expense on the condensed consolidated statement of operations and $195,401 has been capitalized in oil and natural gas properties.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

For the nine months ended September 30, 2006, the Company recorded stock-based compensation of $1,909,871 under the 2006 Stock Incentive Plan (as described in Note 10 “Common Stock Options”) and a certain employment agreement (as described in Note 13 “Contingencies and Commitments”). Of that amount, $1,349,177 has been included in general and administrative expense on the condensed consolidated statement of operations and $560,694 has been capitalized in oil and natural gas properties. The impact on future net income is estimated to be $3,800,000 recognized over the applicable requisite service period of approximately three years.

Prior to 2006, the Company applied APB No. 25 and related interpretations in accounting for its plans. Under APB 25, if the exercise price of the stock options was greater than the market value of the shares at the date of grant, no compensation cost was recognized in the condensed consolidated financial statements. The following table illustrates the effect on net loss and loss per share as if the Company had applied the fair value recognition provisions of SFAS 123 during the nine months ended September 30, 2005:

	2005
Net loss	$	(559,320	)
Deduct total stock-based compensation expense determined under fair value based method for all awards, net of related tax effects		-
Pro forma net loss	$	(559,320	)
Loss per share - basic and diluted
As reported	$	(0.02	)
Pro forma	$	(0.02	)

There were no options granted during the nine months ended September 30, 2005.

NOTE 10.COMMON STOCK OPTIONS

Stock Option Plans

At December 31, 2005, the Company had two stock-based compensation plans, which are more fully described in Note 18 in the Annual Report on Form 10-KSB for the year ended December 31, 2005. Prior to 2006, the Company accounted for those plans under the recognition and measurement provisions of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and its related Interpretations. No stock-based employee compensation cost was reflected in previously reported results, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant.

On March 16, 2006, the Company’s Board of Directors adopted an incentive stock option plan as part of a larger equity incentive plan (the “2006 Stock Incentive Plan”) that also provides for non-statutory stock options, stock bonuses and restricted stock awards. The shareholders approved the Plan at the annual meeting of the shareholders on May 19, 2006. The purpose of the Plan 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 affiliates. The 2006 Stock Incentive Plan provides that no more than 8,000,000 shares of stock may be issued in equity awards or stock options under the plan, the exercise price for incentive stock options shall not be less than 100% of fair market value on the date of grant, and unless otherwise determined by the Board, the exercise price for non-statutory stock options shall be not less than 100% of fair market value on the date of grant. The maximum term for options granted is 10 years.

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Activity related to the three stock option plans (2006 Stock Incentive Plan, 2004 Equity Incentive Plan and the 1997 Stock Option Plan) was as follows for the nine months ended September 30, 2006 and 2005:

	2006			2005
Options outstanding at beginning of period		1,205,000			344,000
Options granted		2,464,500			-
Options forfeited and other adjustments		(454,266	)		-
Options exercised		(342,734	)		-
Options outstanding at end of period		2,872,500			344,000

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

	2006		2005
Risk-free interest rate		4%		-
Expected years until exercise		2.5-6.0		-
Expected stock volatility		41%		-
Dividend yield		0%		-

For the three months ended September 30, 2006, the Company recorded stock-based compensation of $886,511 for options and stock issued under the 2006 Stock Incentive Plan. Of that amount, $691,110 has been included in general and administrative expense on the condensed consolidated statement of operations and $195,401 has been capitalized.

For the nine months ended September 30, 2006, the Company recorded stock-based compensation of $1,609,268 for options and stock issued under the 2006 Stock Incentive Plan. Of that amount, $1,048,574 has been included in general and administrative expense on the condensed consolidated statement of operations and $560,694 has been capitalized.

All Stock Options

Activity with respect to all stock options is presented below for the nine months ended September 30, 2006 and 2005:

	2006					2005
	Shares			Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
Options outstanding at the beginning of period		6,448,468		$	0.72		2,700,664	$	0.99
Options granted		2,464,500			4.02		-		-
Options exercised		(3,750,926	)		0.67		-		-
Forfeitures and other adjustments		(359,266	)		4.75		-		-
Options outstanding at end of period		4,802,776		$	2.16		2,700,664	$	0.99
Exercisable at end of period		2,666,609		$	0.89
Weighted average fair value of options granted during the period	$	4.77

18

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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 outstanding at September 30, 2006 was approximately $6,534,000 and the intrinsic value of the options exercisable at September 30, 2006 was approximately $6,092,000. The intrinsic value of the options exercised during the nine months ended September 30, 2006 was approximately $8,999,000.

The options weighted average remaining life by exercise price as of September 30, 2006 is summarized below:

Range of Exercise Prices	Outstanding Shares		Weighted Average Life		Exercisable Shares		Weighted Average Life
$0.25 - $0.38		789,996		3.8		789,996		3.8
$0.50 - $0.75		1,540,000		2.2		1,540,000		2.2
$1.25 - $1.75		402,000		7.1		110,000		1.9
$2.23 - $2.55		180,280		3.3		80,280		3.0
$3.62		1,000,000		4.1		-		-
$4.45 - $4.70		640,500		9.1		6,333		4.6
$5.50 - $5.54		250,000		6.6		140,000		4.5
$0.25 - $5.54		4,802,776		4.5		2,666,609		2.8

NOTE 11.COMMON STOCK WARRANTS

The following table provides information related to stock warrant activity for the nine months ended September 30, 2006:

	Number of Shares Underlying Warrants
Outstanding at the beginning of the period		19,697,500
Granted		-
Exercised under early exercise program		(13,182,625	)
Exercised		(3,489,871	)
Forfeited		(945,504	)
Outstanding at the end of the period		2,079,500

As of September 30, 2006, these common stock warrants had an average remaining contractual life of 2.14 years and a weighted average exercise price of $1.71.

NOTE 12.NET INCOME (LOSS) PER SHARE

Basic earnings (loss) per share are computed by dividing net income (loss) by the weighted average number of common shares outstanding for the period. The computation of diluted net income (loss) per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company.

During the three months ended September 30, 2006 and nine months ended September 30, 2006 and 2005, stock options and warrants were excluded in the computation of diluted loss per share because their effect was anti-dilutive. During the three months ended September 30, 2005, common share equivalents were included in the computation of diluted loss per share; however the effect of their inclusion was not material.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 13.CONTINGENCIES AND COMMITMENTS

Environmental Risk

Due to the nature of the oil and gas business, the Company is exposed to possible environmental risks. The Company manages its exposure to environmental liabilities for both properties it owns as well as properties to be acquired. The Company has historically not experienced any significant environmental liability, and is not aware of any potential material environmental issues or claims at September 30, 2006.

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 gas wells. The existing letters of credit have been issued by Northwestern Bank and are secured only by a Reimbursement and Indemnification Commitment issued by the Company, together with a right of set-off against all of the Company’s deposit accounts with Northwestern Bank. At September 30, 2006, letters of credit in the amount of $947,500 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 two-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.

NOTE 14.RETIREMENT BENEFITS

Effective May 1, 2006, the Company established a qualified retirement plan referred to as Aurora 401(k) Plan (“the Plan”). The Plan is available to all employees who have completed at least 1,000 hours of service over their first twelve consecutive months of employment and are at least 21 years of age. Effective July 1, 2006, the Company waived the age and service requirements for any employee employed by the Company on or before July 1, 2006. The Company may provide: 1) discretionary matching of employee contributions, 2) discretionary profit sharing contributions and 3) qualified non-elective contributions to the Plan. Company-provided contributions are subject to certain vesting schedules.

20

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 15.OIL AND NATURAL GAS PROPERTIES HELD FOR SALE

Management is currently in the process of evaluating the Company’s property portfolio to ensure that the oil and gas properties portfolio properly matches the Company’s long-term strategic plan. During the second quarter of 2006, the Company identified certain leasehold properties as held for sale due to their high probability of being sold within the next 12 months. Total oil and natural gas properties held for sale before accumulated depletion and amortization amounted to $7,653,612 at September 30, 2006 of which $3,454,122 is proved and $4,199,490 is unproved (See Note 6 “Acquisitions and Dispositions”). These properties are carried at the lower of historical cost or fair value. Under the full cost method, sales of oil and 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 has evaluated the proved reserves of these properties and determined that there is no significant effect on the proved reserves regarding the assets held for sale. In 2005, no properties were classified as held for sale.

NOTE 16.SUBSEQUENT EVENTS

Pending Acquisition

On May 9, 2006, North signed a letter of intent with a third party to acquire oil and gas leases, working interests, and interests in related pipelines and production facilities that are located in the Michigan Antrim shale. This encompasses two projects that are still in development, but already are generating some production. On June 30, 2006, the letter of intent was amended to extend the due diligence effort through September 30, 2006 with anticipated closing of the transaction on or before November 15, 2006. It is anticipated that this acquisition will cost approximately $10.5 million, and closing is subject to due diligence and approval of the financial institutions providing financing to the Company.

Bach Acquisition

On October 6, 2006, the Company closed on the purchase of all assets of Bach Enterprises, Inc., certain assets owned by Bach Energy, LLC and a limited liability company known as Kingsley Development LLC (together “Bach”). Bach is primarily an oil and natural gas service company. The Company has been working exclusively with Bach as a service business in Michigan for several years. Services they have provided include building compressors, CO2 removal, pipelining, and facility construction. The purchase price included common stock and cash. The common stock issued is subject to a one-year lock-up period. In addition, the Company entered into five-year employment agreements with two principals of Bach who agreed not to compete during their employment and for a period of one year following termination of their employment.

Public Equity Offering

On October 27, 2006, the Company filed Amendment No. 4 to Form SB-2 to initiate a public offering to sell 16 million shares of its common stock. Based on a public offering price of $3.00 per share, the Company will receive net proceeds of approximately $44.5 million or approximately $54.7 million if the underwriters’ over-allotment option of 3.6 million shares is fully exercised. The Company expects to use the net proceeds primarily to fund exploration and development activities. Pending such use, the net proceeds will be used to repay the current borrowings under the senior secured credit facility.

The Company closed on the public offering of 16 million shares on November 7, 2006 and received net proceeds of approximately $44.5 million, which were utilized to repay amounts outstanding under the senior secured credit facility. The 30-day over-allotment option granted to the underwriters for the purchase of 3.6 million additional shares was exercised and closed on November 13, 2006, and the Company received net proceeds of approximately $10.2 million.

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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 2005 Annual Report on Form 10-KSB, as well as the consolidated financial statement and notes hereto included in this quarterly report on Form 10-QSB. The following discussion contains forward-looking statements that involve risks, uncertainties, and assumptions such as statements of our plans, objectives, expectations, intentions and estimated reserves. Our actual results may differ materially from those discussed in these forward-looking statements because of the risks and uncertainties inherent in future events. For additional risk factors affecting our business, see the information in Item 1A in our 2005 Annual Report on Form 10-KSB and subsequent filings.

BUSINESS 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 natural 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.

As a result of the reverse merger, the historical financial statements presented for periods prior to the acquisition date are the financial statements of Aurora. The operations of the former Cadence Resources Corporation businesses have been included in the financial statements from the date of acquisition. 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 natural 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.

BUSINESS STRATEGY

Our strategy is to maximize shareholder value by leveraging our significant acreage position. As an early stage developer of properties, we anticipate that reserve growth will be our initial focus followed in a few years by a more traditional balance between reserve and production growth. The principal elements of our strategy to maximize shareholder value are:

Generate growth through drilling. We expect to generate long-term reserve and production growth predominantly through our drilling activities. We believe the experience and expertise of our management and technical teams enables us to identify, evaluate and develop natural gas projects. We anticipate the substantial majority of our future capital expenditures will be directed toward the drilling of wells, although we expect to continue to acquire additional leasehold interests. Initially, we anticipate reserve growth will be our primary focus with a more balanced reserve and production growth profile as we continue to execute our growth strategy.

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Focus on lower risk shale development projects, with selective expenditures outside our focus areas. Most of our acreage in the Antrim and New Albany shale contains lower risk unconventional natural gas development plays, including 592,321 net leasehold acres on which we have identified approximately 2,768 net potential drilling locations. In the Antrim shale play there have been over 8,000 wells drilled since the inception of the play with a historic success rate of approximately 95%. The New Albany shale play is an emerging play without the history of the Antrim shale play, but we believe it will have similar success characteristics to the Antrim shale play. We believe that by focusing our drilling budget on development oriented activities in our shale areas in the short run, we can maintain high drilling success rates yielding attractive rates of return. We anticipate committing a small portion of our drilling budget to locations outside of our shale project areas to continually evaluate and test new areas for exploration and development potential.

Employ leading edge technologies to grow reserves and production and enhance returns. We employ several leading edge technologies in the drilling, completion and development of our natural gas reserves. For example, our employees have developed and implemented a low pressure natural gas production system to increase the estimated recoverable reserves and improve production rates of shale-oriented natural gas. We have installed several low pressure, small modular style compression facilities in our Antrim shale play. We believe this system has reduced development costs, increased production rates, extended the commercial life of existing wells and increased the total amount of reserves ultimately recoverable from each well bore when compared to the high pressure, large compression facilities that are typically used in the Antrim shale play. We believe this innovative system gives us a competitive advantage compared to other operators in the area.

Manage costs by maximizing operational control. We seek to exert control over our exploration, exploitation and development activities. As the operator of our projects, we have greater control over the amount and timing of the expenditures associated with those activities. As we manage our growth, we are focused on reducing lease operating expenses, general and administrative costs and finding and development costs on a per mcfe basis. As of September 30, 2006, we operated 36% of our completed wells. We believe this percentage will continue to increase as we plan to operate approximately 49% of our wells drilled in 2007.

Pursue complementary leasehold interest and property acquisitions. We intend to use our experience and regional expertise to supplement our drilling strategy with complementary leasehold interest and property acquisitions.

RECENT HIGHLIGHTS

For the first nine months of 2006, we continued to execute our strategy of focusing on lower risk shale development projects. As of September 30, 2006, our leasehold acres (both developed and undeveloped) were 1,119,085 (633,350 net) which represent a 74% increase over our December 31, 2005 net acres. Of the 303,621 (269,260 net) leasehold acres acquired, 55,242 net acres were in the Antrim shale play and 187,025 net acres were in the New Albany shale play with the balance in Other areas.

With regard to our strategy to generate growth through drilling, we drilled or participated in 124 (49 net) wells for the first nine months of 2006. As of September 30, 2006, we had 425 (192 net) producing wells and 77 (27 net) wells awaiting hook-up. We also continued our strategy to have greater control over our projects by operating 183 (158 net) wells, thus, operating 36% of our gross wells. We also supplemented our drilling strategy with the Hudson properties acquisition. This acquisition increased our proved reserves by approximately 24 bcfe in the Antrim shale play.

We began 2006 with estimated proved reserves of 64 bcfe and at June 30, 2006 had 105 bcfe, an increase of 41 bcfe, or 64%. Of the 105 bcfe in estimated proved reserves, 101 bcfe was from the Antrim shale play and two bcfe was from the New Albany shale play.

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In order to reduce exposure to fluctuations in the price of natural gas, we will periodically enter into financial arrangements with a major financial institution. We have entered into a financial swap contract for 5,000 mmbtu per day at a fixed price of $8.59 per mmbtu covering the period of April 2006 through March 2007 and another financial swap contract on July 14, 2006 for 5,000 mmbtu per day at a fixed price of $9.00 per mmbtu for the period from April 2007 through December 2008.

To further our growth, we entered into a senior secured credit facility on January 31, 2006 with an initial borrowing base of $40 million. As proved reserves are added, the borrowing base may increase to $50 million without consent under our mezzanine financing arrangement and $100 million with consent under the mezzanine financing arrangement. Effective July 14, 2006, the borrowing base was increased to $50 million.

From late December 2005 through early February 2006, we reduced the exercise price of certain outstanding options and warrants in order to encourage the early exercise of these securities. As a result of the options and warrants exercised pursuant to this reduced exercise price arrangement, and pursuant to other exercises of outstanding options, an additional 20,423,422 shares were issued during the nine months ended September 30, 2006 representing 15,673,457 shares issued for cash proceeds of $18,187,449 and 4,749,965 shares issued pursuant to cashless exercises of the applicable warrants or options. In December 2005, an additional 2,160,000 shares were issued for cash proceeds of $2,916,000.

The Company closed on the public offering of 16 million shares on November 7, 2006 and received net proceeds of approximately $44.5 million, which were utilized to repay amounts outstanding under the senior secured credit facility. The 30-day over-allotment option granted to the underwriters for the purchase of 3.6 million additional shares was exercised and closed on November 13, 2006, and the Company received net proceeds of approximately $10.2 million.

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RESULTS OF OPERATION

Operating Statistics

The following table sets forth certain key operating statistics for the three and nine months ended September 30, 2006 (the “Current Quarter” and the “Current Period”) and the three and nine months ended September 30, 2005 (the “Prior Quarter” and the “Prior Period”):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
Total net acreage held
Antrim shale		133,405		65,559		133,405		65,559
New Albany shale		458,916		225,262		458,916		225,262
Other		41,029		3,952		41,029		3,952
Total		633,350		294,773		633,350		294,773
Net productive wells drilled (a)
Antrim shale		13		33		42		52
New Albany shale		1		-		4		-
Other		3		-		3		-
Total		17		33		49		52
Total net wells (end of period)
Net producing		192		64		192		64
Net waiting hookup		27		39		27		39
Total		219		103		219		103
Production
Natural gas (mcf)		653,944		242,026		1,878,495		389,924
Crude oil (bbls)		5,334		2,639		17,223		5,402
Natural gas equivalent (mcfe)		685,948		257,860		1,981,833		422,336
Average daily production
Natural gas (mcf)		7,108		2,631		6,880		1,428
Crude oil (bbls)		58		29		63		20
Natural gas equivalent (mcfe)		7,456		2,805		7,258		1,548
Average sales prices (including realized gains or losses from hedging)
Natural gas ($ per mcf)	$	7.36	$	7.21	$	7.99	$	6.98
Crude oil ($ per bbl)		67.90		50.28		64.06		47.15
Natural gas equivalent ($ per mcfe)		7.55		7.28		8.13		7.05
Total production revenue
Natural gas	$	$4,813,443	$	1,745,657	$	15,013,553	$	2,721,565
Crude oil		362,192		132,687		1,103,302		254,685
Total	$	$5,175,635	$	1,878,344	$	16,116,855	$	2,976,250
Production expense	$	1,692,080	$	609,210	$	5,103,131	$	1,262,167
Production expense per mcfe	$	2.47	$	2.36	$	2.57	$	2.98
Number of employees (end of period)		53		31		53		31

(a) A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

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RESULTS OF OPERATIONS

Three Months Ended September 30, 2006 (“Current Quarter”) compared with Three Months Ended September 30, 2005 (“Prior Quarter”)

General. For the Current Quarter, the Company had a net loss of $2,086,234 on total revenues of $5,553,024. This compares to net income of $177,677 on total revenue of $2,047,597 during the Prior Quarter. This $3,505,427 increase in revenue represents the initial results that we are realizing as an early stage developer of natural gas properties.

Oil and Natural Gas Sales. During the Current Quarter, oil and natural gas sales were $5,175,635 compared to $1,878,344 in the Prior Quarter. We produced and sold 685,948 mcfe at a weighted average price of $7.55 per mcfe compared to 257,860 mcfe at a weighted average price of $7.28 per mcfe. This increase was primarily due to the ramping up of production from new wells placed into production, acquisition of additional working interests in Hudson properties and the producing assets from the Cadence reverse merger. For the Prior Quarter, nearly 66% of natural gas sales were generated from the Hudson project within the Antrim shale play. The Antrim shale play represented approximately 87% of our oil and natural gas revenue for the Current Quarter.

At the end of the Current Quarter, we had 192 net wells producing compared to 64 net wells at the end of the Prior Quarter. During the Current Quarter, we had a favorable volume variance by placing 22 net wells into production. The weighted average price variance included $1,002,300 of realized gains from the natural gas hedging instruments currently under contract for the Current Quarter. The gas derivatives covered approximately 70% of our average daily natural gas production for the Current Quarter.

Miscellaneous Income. Miscellaneous income for the Current Quarter primarily includes $364,586 of pipeline revenue from the 2006 Hudson acquisition. During the Current Quarter, other income was $41,016 compared to $126,696 in the Prior Quarter. This decrease was primarily due to reduction in lease management fees and the move in the Company’s growth strategy to developing oil and natural gas properties.

General and Administrative Expenses. Our general and administrative expenses include officer and employee compensation, travel, audit, tax and legal fees, office supplies, utilities, insurance, other consulting fees and office related expense. Effective January 1, 2006, general and administrative expenses excludes certain internal payroll and benefit costs that can be directly identified with our acquisition, exploration and development activities. For the Current Quarter, $569,408 of payroll and benefit costs were capitalized to oil and natural gas properties.

The $1,279,719 increase in general and administrative expenses for the Current Quarter was primarily the result of the Company’s growth strategy of acquiring and developing operating interests in unconventional drilling programs in the Michigan Antrim shale and the New Albany shale. This growth has resulted in substantial increases in employees and related costs, legal and accounting services related to SEC filings as well as increased consulting services. The Prior Quarter expenses reflect Aurora as a private entity whereas the Current Quarter represents the costs associated with being a public entity and execution of the Company’s growth strategy.

We incurred an additional $372,396 in compensation and benefit expenses related to 22 new employees as compared to Prior Quarter. In addition, stock-based compensation in the Current Quarter was $1,152,429 which includes $318,450 for directors, $345,530 for senior management and $488,449 for employees. Of that amount $957,028 has been included in general and administrative expense and $195,401 has been capitalized. The Prior Quarter did not have any stock-based compensation.

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We continue to experience significant legal, accounting and other consulting services as a result of our growth strategy including development costs associated with becoming a public entity and on-going public costs. The following table sets forth the majority of our outside services for the Current Quarter as compared to the Prior Quarter:

Expense category	For the three months ended September 30, 2006		For the three months ended September 30, 2005
Legal expenses	$	97,924	$	1,388
Accounting expenses		96,140		21,363
Consulting and other expenses		76,509		27,428
Total	$	270,573	$	50,179

Production and Lease Operating Expenses. Our production and lease operating expenses include services related to producing oil and natural gas, such as severance taxes, post production costs (including marketing and transportation), and lease operating expenses (including expenses to operate the wells and equipment on a producing lease).

Production and lease operating expenses were $1,692,080 for the Current Quarter compared to $609,210 for the Prior Quarter. On a unit of production basis, production expenses were $2.47 per mcfe in the Current Quarter compared to $2.36 for the Prior Quarter. The increase in the Current Quarter was primarily a result of our new production coming on-line and incurring substantial cost during the dewatering period. Those new development wells had a production expense of $6.43 per mcfe due to minimal production volumes. We anticipate that our fixed costs of control processing facilities and water disposal facilities will begin to be spread over more production as new development wells come on line and production increases.

The following table sets forth the major components of production and operating expenses for the Current Quarter and Prior Quarter:

	For the three months ended September 30, 2006				For the three months ended September 30, 2005
Expense category	Per Mcfe		Amount		Per Mcfe		Amount
Severance taxes	$	.31	$	210,435	$	.26	$	69,206
Post-production expenses		.58		399,295		.70		179,652
Lease operating expenses		1.58		1,082,350		1.40		360,352
Total	$	2.47	$	1,692,080	$	2.36	$	609,210

Depletion, Depreciation and Amortization (DD&A). Depletion, depreciation and amortization was $1,406,011 and $250,561 for the Current Quarter and the Prior Quarter, respectively. DDA of oil and gas properties was $882,445 during the Current Quarter as compared to $250,561 during the Prior Quarter. This increase reflects the transfer to production assets of approximately $80.7 million. This represents wells being placed into production with costs being transferred from unproven properties to proven properties.

Other depreciation and amortization was $523,566 during the Current Quarter, of which $383,750 represented amortization of intangible assets recognized in connection with the Cadence merger, $76,508 represented depreciation of the Hudson pipeline assets, $14,475 represented amortization of asset retirement obligation (“ARO”) and $48,833 represented depreciation of other property and equipment.

Interest Expense. Interest expense was $2,279,760 in the Current Quarter compared to $264,902 in the Prior Quarter. This increase is due to higher utilization of debt to continue our growth strategy of acquiring and developing operating interests in the Michigan Antrim shale and the New Albany shale. The amount of capitalized interest has decreased significantly from the Prior Quarter as our properties are transferred from undeveloped to producing or as financing is used for proven acquisition. As of September 30, 2006, we had outstanding borrowings of $91.4 million as compared to $30.0 million as of September 30, 2005.

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Taxes. Tax expense was $9,928 in the Current Quarter compared to $4,003 in the Prior Quarter.

Nine Months Ended September 30, 2006 (“Current Period”) compared with Nine Months Ended September 30, 2005 (“Prior Period”)

General. For the Current Period, the Company had a net loss of $4,036,080 on total revenues of $17,176,743. This compares to a net loss of $559,320 on total revenue of $3,673,421 during the Prior Period. The $13,503,322 increase in revenue represents the results of the initial steps that we are taking as an early stage developer of properties. We had 192 net wells producing at the end of the Current Period as compared to 64 net wells producing at the end of the Prior Period.

Oil and Natural Gas Sales. During the Current Period, oil and natural gas sales were $16,116,855 compared to $2,976,250 in the Prior Period. We produced 1,981,833 mcfe at a weighted average price $8.13 per mcfe compared to 422,336 mcfe at a weighted average price of $7.05 per mcfe. This increase in production was due to the ramping up of production from new wells placed into production, acquisition of additional working interest in Hudson properties and the producing assets from the Cadence reverse merger. The Antrim shale play represented approximately 83% of our oil and natural gas revenue for the Current Period.

During the Current Period, we had a favorable volume variance by placing 128 net wells into production as compared to the Prior Period and a favorable average price variance that included $1,794,650 of realized gains from the natural gas hedging instruments currently under contract for the Current Period.

Miscellaneous Income. Miscellaneous income for the Current Period primarily includes $865,454 of pipeline revenue from the 2006 Hudson acquisition. During the Current Period other income was $137,147 as compared to $476,307 in the Prior Period. This decrease was primarily due to reduction in lease management fees and the move in the Company’s growth strategy to developing oil and natural gas properties. During the Current Period, the equity in loss of the unconsolidated subsidiary was $226,711 compared to $2,231 of income in the Prior Quarter. This decrease was primarily due to our investment in GeoPetra, Partners LLC.

General and Administrative Expenses. Our general and administrative expenses include officer and employee compensation, travel, audit, tax and legal fees, office supplies, utilities, insurance, other consulting fees and office related expense. Effective January 1, 2006, general and administrative expenses excludes certain internal payroll and benefit costs that can be directly identified with our acquisition, exploration and development activities. For the Current Period, $1,561,780 of payroll and benefit costs were capitalized to oil and gas properties.

The $3,413,536 increase in general and administrative expenses for the Current Period was the result of the Company’s growth strategy in land acquisitions and drilling programs. This growth has resulted in substantial increases in employees and related costs, legal and accounting services related to SEC filings as well as increased consulting services. In addition, we continue to experience significant general and administrative expenses as a result of the Cadence merger. The Prior Period expenses reflect Aurora as a private entity whereas the Current Period represents both development costs associated with becoming a public entity and on-going public costs.

We incurred $682,349 of additional compensation and benefit expenses related to 23 new employees as compared to Prior Period. In addition, stock-based compensation in the Current Period was $1,909,871 which includes $468,280 for directors, $633,021 for senior management and $808,570 for employees. Of that amount $1,349,177 has been included in general and administrative expense and $560,694 has been capitalized. The Prior Period did not have any stock-based compensation.

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We continue to experience significant legal, accounting and other consulting services as a result of our growth strategy including development costs associated with becoming a public entity and on-going public costs. The following table sets forth the majority of our outside services for the Current Period as compared to the Prior Period:

Expense Category	For the nine months ended September 30, 2006		For the nine months ended September 30, 2005
Legal expenses	$	522,834	$	15,773
Accounting expenses		547,284		56,751
Consulting and other expenses		541,223		118,107
Total	$	1,611,341	$	190,631

The Current Period legal expenses include significant SEC services covering various SEC filings for financial reporting, stock-compensation plans, and corporate issues concerning stock options, lost certificates of stock, corporate structuring, acquisitions, etc. We incurred an additional $99,289 in legal expenses associated with 2005 transactions. We also believe that a certain amount of legal expenses will diminish as internal systems and staffing are introduced. The Current Period accounting expenses include approximately $177,752 associated with 2005 year end audit work, work associated with the Hudson acquisition, and disclosures on reserves. The Current Period consulting and other expenses include the following expenditures: 1) $50,000 for publishing the annual report and proxy; 2) one-time fee of $65,000 for our AMEX listing and $23,000 annual prorated AMEX listing fee; 3) $18,000 fee for the stock transfer agent, 4) $39,300 for consulting services that addressed process improvements; 5) $122,470 in one-time consulting fees and temporary help; 6) $45,200 for research and development; and 7) $65,250 one-time rent settlement.

Production and Lease Operating Expenses. Our production and lease operating expenses include services related to producing oil and natural gas, such as severance taxes, post production costs (including marketing and transportation), and lease operating expenses (including expenses to operate the wells and equipment on a producing lease).

Production and lease operating expenses were $5,103,131 for the Current Period compared to $1,262,167 for the Prior Period. On a unit of production basis, production expenses were $2.57 per mcfe in the Current Period compared to $2.98 for the Prior Period. The decrease in the Current Period was primarily due to allocating our fixed costs of control processing facilities and water disposal facilities over more production as new development wells come on line. Current Period also reflects new development wells with production expense of $6.05 per mcfe due to minimal production volumes. We also recognized a reduction of $327,511 in transportation expense due to the Hudson pipeline acquisition.

The following table sets forth the major components of production and operating expenses for the Current Period and Prior Period:

	For the nine months ended September 30, 2006				For the nine months ended September 30, 2005
Expense category	Per Mcfe		Amount		Per Mcfe		Amount
Severance taxes	$	.33	$	656,261	$	.74	$	312,170
Post-production expenses		.57		1,142,604		.44		185,861
Lease operating expenses		1.67		3,304,266		1.80		764,136
Total	$	2.57	$	5,103,131	$	2.98	$	1,262,167

Depletion, Depreciation and Amortization (DD&A). Depletion, depreciation and amortization was $4,430,177 and $338,061 during the Current Period and the Prior Period, respectively. DDA of oil and gas properties was $2,858,823 during the Current Period as compared to $338,061 during the Prior Period. This increase reflects the increase to production assets of approximately $80.7 million. This represents wells being placed into production with costs being transferred from unproven properties to proven properties. In addition, there was an increase in depletion rates associated with the producing assets from the Cadence merger, since these assets have reserves with shorter lives than the Michigan Antrim shale.

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Other depreciation and amortization was $1,571,354 during the Current Period of which $1,151,250 represented amortization of the intangible assets recognized in connection with the Cadence merger and $232,868 represented depreciation related to the Hudson pipeline acquisition, $48,480 represented amortization of ARO and $138,756 represented depreciation of other property and equipment.

Interest Expense. Interest expense was $5,843,914 in the Current Period compared to $516,983 in the Prior Period. This increase is due to higher utilization of debt to continue our growth strategy of acquiring and developing operating interests in the Michigan Antrim shale and the New Albany shale. The amount of capitalized interest has decreased significantly from the Prior Period as our properties are transferred from undeveloped to producing or as financing is used for proven acquisition. As of September 30, 2006, we had outstanding borrowings of $91.4 million compared to $30.0 million as of September 30, 2005.

Taxes. Tax expense was $39,289 in the Current Period compared to $259,200 in the Prior Period. This decrease resulted from the reversal of an accrual related to the January 2005 sale of the 95% working interest to El Paso Corporation in certain New Albany shale acreage.

CAPITAL RESOURCES AND LIQUIDITY

We expect to fund our growth strategy using a combination of debt, existing cash balances, internally generated cash flows from natural gas production, and the proceeds from a recent equity offering. Our 2006 capital budget for drilling and related well work and infrastructure is approximately $51.2 million with an anticipated participation in 221 (106 net) wells. Our 2006 capital budget for leasehold interest and property acquisitions is approximately $14.2 million and $39.3 million, respectively. Our 2007 capital budget for drilling and related well work and infrastructure is estimated to be approximately $105.6 million with an anticipated participation in 410 (228 net) wells. Our 2007 capital budget for leasehold interest and property acquisitions is estimated to be approximately $9 million and $1 million, respectively. We believe that the proceeds of the recent equity offering, our available credit facilities with anticipated increases in our borrowing bases, and our operating cash flow will be sufficient to fund our operations and capital expenditures for the next 18 months. However, future cash flows are subject to a number of variables, including the level of production and prices. 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 term credit facility with certain affiliates of Trust Company of the West (“TCW”) for the Michigan Antrim shale drilling program. It is a non-revolving term loan facility that has a commitment expiration date of August 12, 2007 and a maturity date of September 29, 2009. Borrowings under the TCW credit facility as of September 30, 2006 were $40 million with available borrowing capacity of $10 million. The interest rate is fixed at 11.5% per year, compounded quarterly, and is payable in arrears. Beginning September 28, 2006 and quarterly thereafter, the required principal payment is 75% (100% if a coverage deficiency or default occurs) of “adjusted net cash flow” determined by deducting specified expenses, including capital expenditures from “gross cash revenue.” We estimate that no principal payments on the mezzanine financing will be required until maturity because of the level of our anticipated capital expenditures. We have granted TCW a security interest in certain of our Michigan Antrim shale assets. This security interest is subordinated to the security interest of our senior lender described below. The TCW loan agreement contains, among other things, a number of financial and non-financial covenants, including covenants prohibiting the declaration or payment of dividends and covenants requiring the maintenance of certain financial and operating ratios, including collateral coverage and proved developed producing coverage ratios. As of September 30, 2006, we were in compliance with all of the applicable covenants.

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As additional consideration to induce TCW to enter into the mezzanine term credit facility, we provided an affiliate of TCW an overriding royalty interest in all of our properties drilled or developed in the counties of Alcona, Alpena, Charlevoix, Cheboygan, Montmorency and Otsego in the State of Michigan. The overriding royalty interest is four percent, subject to certain adjustments.

Our senior secured credit facility is a $100 million senior secured revolving credit facility with BNP Paribas (“BNP”). The amount that we can borrow under this facility is limited to the amount of our borrowing base, which is determined semi-annually and at certain other times by our lenders. The initial borrowing base under this facility was $40 million. Effective July 14, 2006, the borrowing base was increased to $50 million. As proved reserves are added, this borrowing base may increase to $100 million with TCW consent. This facility matures on the earlier of January 31, 2010 or 91 days prior to the maturity of the mezzanine credit facility with TCW, unless we elect to terminate the commitment earlier pursuant to the terms of the credit facility. This facility provides for interest on borrowings tied to BNP’s prime rate (or, if higher, the federal funds effective rate plus 0.5%) or a LIBOR-based rate (LIBOR multiplied by a statutory reserve rate) plus 1.25 to 2.0% depending on our borrowing base utilization. Our borrowing base utilization is the percentage of our borrowing base that is drawn under our senior credit facility from time to time. As our borrowing base utilization increases, our LIBOR-based interest rates increase under this facility. As of September 30, 2006, interest on borrowings under our senior secured credit facility had a weighted average interest rate of 7.47%. A required semi-annual reserve report may result in an increase or decrease in our borrowing base and hence our credit availability. On July 14, 2006, the senior secured credit facility was also amended to defer the application of the trailing 12-month interest coverage ratio covenant until the fourth quarter of 2006, and to provide for a reduced ratio for that quarter. At September  30, 2006, our total borrowings under this facility were $45 million. As discussed in our subsequent event footnote, we have closed on our public offering of 19.6 million shares and utilized the funds to repay amounts outstanding under the senior secured credit facility.

The security for our senior secured credit facility includes a first lien position in certain of our Michigan Antrim shale assets, a guarantee from Aurora, and a guarantee from us, secured by a pledge of our stock in Aurora. The senior secured credit facility contains, among other things, a number of financial and non-financial covenants, including covenants relating to restricted payments, loans or advances to others, additional indebtedness, incurrence of liens, a prohibition on our ability to prepay our mezzanine term credit facility with TCW, geographic limitations on our operations to the United States, and the maintenance of certain financial and operating ratios, including a current ratio and an interest coverage ratio. As of September 30, 2006, 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. At September 30, 2006, our total borrowings under this facility were $3.6 million with available borrowing capacity of $1.4 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. Northwestern Bank has recently agreed to extend the expiration date to October 15, 2007.

From late December 2005 through early February 2006, we reduced the exercise price of certain outstanding options and warrants in order to encourage the early exercise of these securities. Each holder who took advantage of the reduced exercise price was required to execute a six-month lock up agreement with respect to the shares issued in the exercise. As a result of the options and warrants exercised pursuant to this reduced exercise price arrangement, and pursuant to other exercises of outstanding options, an additional 20,423,422 shares were issued during the nine months ended September 30, 2006 representing 15,673,457 shares issued for cash proceeds of $18,187,449 and 4,749,965 shares issued pursuant to cashless exercises of the applicable warrants or options. In December 2005 an additional 2,160,000 shares were issued for cash proceeds of $2,916,000.

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CAPITALIZATION

Our total capitalization was as follows:

	As of September 30, 2006				As of December 31,
	Historical		Pro Forma *		2005
Short-term bank borrowings	$	3,610,000	$	610,000	$	6,210,000
Obligations under capital lease		4,818		4,818		11,085
Related party note payable				-		69,833
Mortgage payable		2,814,446		2,814,446		2,865,477
Mezzanine financing		40,000,000		40,000,000		40,000,000
Senior secured credit facility		45,000,000		-		-
Total debt	$	91,429,264	$	43,429,264	$	49,156,395
Redeemable convertible preferred stock	$		$	-	$	59,925
Shareholders’ equity		78,288,621		132,979,989		56,625,927
Total capitalization	$	169,717,8851	$	176,409,253	$	105,842,247

* Provides proforma effect to public offering discussed below.

The Company closed on the public offering of 16 million shares on November 7, 2006 and received net proceeds of approximately $44.5 million, which were utilized to repay amounts outstanding under the senior secured credit facility. The 30-day over-allotment option granted to the underwriters for the purchase of 3.6 million additional shares was exercised and closed on November 13, 2006, and the Company received net proceeds of approximately $10.2 million. The Company expects to use the net proceeds primarily to fund exploration and development activities. Pending such use, the net proceeds will be used to repay the current borrowings under the senior secured credit facility.

CASH FLOWS

Operating activities

We generated $3,057,912 in net cash from operations in the Current Period compared to using $1,447,485 in the Prior Period. The $4,505,397 increase was primarily due to higher realized prices and higher volumes of oil and natural gas production as discussed in the Results of Operations.

Investing activities

Net cash flows used in investing activities was $42,147,066 in the Current Period compared to $19,362,424 used in the Prior Period. This excludes asset retirement obligation of $936,996, capitalized stock-based compensation of $560,693 and investment adjustment for Hudson acquisition of $1,403,592.

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The following table describes our significant investing transactions that we completed in the Current Period compared to the Prior Period:

	Nine Months Ended September 30,
	2006		2005
Acquisitions of leaseholds
Michigan Antrim shale	$	4,775,638	$	1,543,978
New Albany shale (a)		19,641,452		4,917,192
Other		565,355
Drilling and development of oil and gas properties
Michigan Antrim shale		19,900,559		16,747,526
New Albany shale		1,571,244		5,179
Other		1,413,746		15,295
Infrastructure properties
Michigan Antrim shale		7,388,786		2,273,302
New Albany shale		618,196		-
Other		133		-
Acquisitions of producing properties		293,029		-
Dispositions of producing properties		248,297		-
Additions to pipeline		162,108
Additions to other investments		577,088		626,956
Additions to other property and equipment		256,163		555,972
Payments for merger costs		-		407,496
Advances on notes receivable		171,074		72,379
Subtotal of capital expenditures	$	57,582,868	$	27,165,275
Disposition of oil and gas properties (a)		15,250,000		7,717,851
Divestiture of other receivables and investments		185,802		85,000
Subtotal of capital divestitures	$	15,435,802	$	7,802,851
Total (b)	$	42,147,066	$	19,362,424

(a) On February 2, 2006, we closed an acquisition of certain New Albany shale acreage located in Indiana, commonly called the Wabash project. We acquired 64,000 acres of oil and natural gas leases from Wabash Energy Partners, L.P. for a purchase price of $11,840,000. We then sold half our interest in a combined 95,000 acre lease position in the Wabash project to New Albany-Indiana, L.L.C., an affiliate of Rex Energy Operating Corporation for a sale price of $10,500,000. We used internal funds to pay the net transaction cost of these transactions.

(b) On January 31, 2006, we completed the acquisition of oil and natural gas leases, working interests, and interests in related pipelines and production facilities that are located in the Hudson Township area of the Antrim gas play. We acquired 24 bcfe in proved reserves plus a controlling interest in a related pipeline company for a total purchase price of $27,615,993. This transaction was treated as a non-cash financing transaction since our financial institution paid the seller directly and is not included in the above table. 

Financing activities

Cash flows provided by financing activities for the Current Period was $30,107,821 compared to $26,567,959 during the Prior Period. Cash flows provided and used for the Current Period included: 1) $42,613,387 of senior secured borrowing, of which, $27,615,993 was paid directly for the Hudson acquisition; 2) $18,187,449 of proceeds received from the exercise of common stock options and warrants; and 3) net pay-down of $2,600,000 in short-term bank borrowings. Cash flows provided and used by financing activities for the Prior Period included: 1) $11,025,000 of proceeds received from sales of common stock; 2) $19,700,000 of mezzanine borrowing, net of financing costs of $300,000; 3) pay-off of $2,948,698 of certain related-party notes; and 4) distributions of $805,000 to minority interest members for their proportionate share of the El Paso sales proceeds.

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RECENT ACCOUNTING PRONOUNCEMENTS

Reference is made to Note 4 and 9 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

Our financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. The reported financial results and disclosures were determined using the significant accounting policies, practices and estimates described in the notes to the financial statements. We believe that the reported financial results are reliable and the ultimate actual results will not differ materially from those reported. Uncertainties associated with the methods, assumptions and estimates underlying our critical accounting measurements are discussed in the audited consolidated financial statements and notes included in our Annual Report on Form 10-KSB for year-end December 31, 2005. We consider accounting policies related to oil and natural gas properties, oil and natural gas reserves, ceiling test, stock-based compensation, and income taxes to be critical policies.

ITEM 3. 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 and Rule 15d-15 of the Securities Exchange Act of 1934, as amended) as of September 30, 2006, 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 Quarterly Report on Form 10-QSB 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 quarterly period ended September 30, 2006 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.

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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 2. UNREGISTERED SALES OF EQUITY SECURITIES

We did not sell any equity securities that were not registered under the Securities Act of 1933, as amended, or repurchase any of our outstanding equity securities during the quarter ended September 30, 2006.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

3.1(1)	Restated Articles of Incorporation of Aurora Oil & Gas Corporation.
3.2(1)	Bylaws of Aurora Oil & Gas Corporation.
4.1	Articles of Amendment to Articles of Incorporation, relating to the Class A Preferred Stock. (Filed as Exhibit 4 to our Form 10-KSB for the fiscal year ended September 30, 2003, filed with the SEC on January 13, 2004, and incorporated herein by reference.)
10.1	Securities Purchase Agreement between Cadence Resources Corporation and the investors signatory thereto, dated April 2, 2004. (Filed as Exhibit 99.3 to our Current Report on Form 8-K filed with the SEC on April 5, 2004, and incorporated herein by reference.)
10.2	Agreement and Plan of Merger dated as of January 31, 2005 between Cadence Resources Corporation, Aurora Acquisition Corp. and Aurora Energy, Ltd. (Filed as Exhibit 10.3 to our Form S-4 Registration Statement filed with the SEC on May 13, 2005, and incorporated herein by reference.)
10.3(2)	Asset Purchase Agreement with Nor Am Energy, L.L.C., Provins Family, L.L.C. and O.I.L. Energy Corp. dated January 10, 2006.
10.4	Note Purchase Agreement between Aurora Antrim North, LLC et al. and TCW Asset Management Company, dated August 12, 2004 (filed as an Exhibit to the Registrant’s 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, LLC et al. and TCW Asset Management Company, dated December 8, 2005 (filed as an Exhibit to the Registrant’s 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.

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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	Letter Agreement with Bach Enterprises dated July 10, 2006. This Agreement is confidential, was omitted from the filing of our Form 10-QSB for the period ended June 30, 2006 filed with the SEC on August 7, 2006, 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(5)	LLC Membership Interest Purchase Agreement dated October 6, 2006 relating to Kingsley Development Company, L.L.C.
10.19(5)	Asset Purchase Agreement with Bach Enterprises, Inc., et al., dated October 6, 2006.
10.20(5)	Promissory Note from Aurora Energy, Ltd. to Northwestern Bank dated October 15, 2006.
10.21(5)	Indemnification letter agreement between Aurora Oil & Gas Corporation and Rubicon Master Fund.
10.22(5)	Patricia A. Deneau Trust Commercial Guaranty of obligations to Northwestern Bank.
10.23(5)	Patricia A. Deneau Trust Commercial Pledge Agreement to Northwestern Bank.
15*	Awareness letter from Rachlin Cohen & Holtz LLP.
31.1*	Rule 13a-14(a) Certification of Principal Executive Officer.
31.2*	Rule 13a-14(a) Certification of Principal Financial and Accounting Officer
32.1*	Rule 13a-14(a) Certification of Principal Executive Officer.
32.2*	Rule 13a-14(a) Certification of Principal Financial and Accounting Officer

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

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

(3) Filed on September 8, 2006 with our Form SB-2 registration statement filing, registration no. 333-137176, and incorporated herein by reference.

(4) Filed on October 18, 2006 with our Amendment No. 1 to Form SB-2 registration statement filing, registration no. 333-137176, and incorporated herein by reference.

(5) 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.

* Filed with this report.

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SIGNATURES

In accordance with the requirements of the Securities Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned duly authorized.

	AURORA OIL & GAS CORPORATION
Date: November 14, 2006	By:	/s/ William W. Deneau
		William W. Deneau, President and Chief Executive Officer
		(Principal Executive Officer)

By:	/s/ Ronald E. Huff
	Ronald E. Huff Chief Financial Officer
	(Principal Financial Officer and Principal Accounting Officer)

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