Aurora Oil & Gas POS AM Prospectus update (post-effective amendment)

As filed with the Securities and Exchange Commission on October 31, 2007

Registration No. 333-129695

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Post Effective Amendment No. 4

to

Form SB-2

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

AURORA OIL & GAS CORPORATION

(Name of Small Business Issuer in its Charter)

Utah	1311	87-0306609
(State or other jurisdiction of	(Primary Standard Industrial	(I.R.S. Employer
incorporation or organization)	Classification Code Number)	Identification No.)

4110 Copper Ridge Drive, Suite 100

Traverse City, Michigan 49684

(231) 941-0073

(Address and telephone number of principal executive offices, place ofbusiness)

Name, address and telephone number of agent for service:

William W. Deneau, Chief Executive Officer

Aurora Oil & Gas Corporation

4110 Copper Ridge Drive, Suite 100

Traverse City, Michigan 49684

(231) 941-0073

With a copy to:

Iris K. Linder

Fraser Trebilcock Davis & Dunlap, PC

124 West Allegan, Suite 1000

Lansing, MI 48933

Approximate date of proposed sale to the public:  As soon as practicable after this Registration Statement becomes effective.

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering:  o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering:  o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering:  o

If delivery of the prospectus is expected to be made pursuant to Rule 434, check the following box:  o

The Registrant hereby amends this Registration Statement on such date or dates as maybe necessary to delay its effective date until the Registrant shall file a furtheramendment which specifically states that this Registration Statement shall thereafterbecome effective in accordance with Section 8(a) of the Securities Act of 1933,as amended, or until this Registration Statement shall become effective on such dateas the Securities and Exchange Commission, acting pursuant to said Section 8(a),may determine.

SUBJECT TO COMPLETION, DATED OCTOBER 31, 2007.

8,900,000 Shares

Common Stock

All of the shares to which this prospectus relates are being registered for resale by certain selling security holders as described more fully beginning on page 61. We will not sell any of these shares nor will we receive any proceeds from the sale of the shares.

Our common stock is traded on the American Stock Exchange under the symbol “AOG.” On October 30, 2007, the last sales price of our common stock as reported on the American Stock Exchange was $1.42 per share.

Investing in our common stock involves risks.  See “Risk Factors” beginningon page 11.

Neither the Securities and Exchange Commission nor any state securities commissionhas approved or disapproved of these securities or passed upon the adequacy oraccuracy of this prospectus. Any representation to the contrary is a criminaloffense.

The date of this prospectus is October 31, 2007.

TABLE OF CONTENTS

PROSPECTUS SUMMARY	1
RISK FACTORS	11
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS	21
USE OF PROCEEDS	22
PRICE RANGE OF COMMON STOCK	23
SELECTED HISTORICAL FINANCIAL DATA	24
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	26
BUSINESS	39
MANAGEMENT	49
EXECUTIVE COMPENSATION	57
PRINCIPAL AND SELLING SECURITY HOLDERS	60
RELATED PARTY TRANSACTIONS	65
DESCRIPTION OF SECURITIES	68
LEGAL MATTERS	71
EXPERTS	71
CHANGE IN INDEPENDENT AUDITORS	71
WHERE YOU CAN FIND MORE INFORMATION	72
FINANCIAL STATEMENTS	F1-F51
APPENDIX A — GLOSSARY OF OIL AND NATURAL GAS TERMS	A1-A4

You should rely only on the information contained in this prospectus or to which wehave referred you. We have not authorized anyone to provide you with information thatis different. This document may only be used where it is legal to sell thesesecurities. The information in this document may only be accurate on the date of thisprospectus.

Except as otherwise indicated or required by the context, references in this prospectus to “we”, “us,” “our” or the “Company” refer to Aurora Oil & Gas Corporation and its subsidiaries. The term “you” refers to a prospective investor.

i

PROSPECTUS SUMMARY

This summary contains basic information about us and the offering. Because it is asummary, it does not contain all the information that you should consider beforeinvesting in our common stock. You should read and carefully consider this entireprospectus before making an investment decision, especially the information presentedunder the heading “Risk Factors” and our consolidated financial statements and theaccompanying notes included elsewhere in this prospectus, as well as the otherdocuments to which we refer you. We have provided definitions for some of the oil andnatural gas industry terms used in this prospectus in the “Glossary of Oil andNatural Gas Terms” in Appendix A. Natural gas equivalents are determined usingthe ratio of six mcf of natural gas to one bbl of crude oil, condensate or naturalgas liquids.

AURORA OIL & GAS CORPORATION

Overview

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

We commenced operations in 1969 to explore and mine natural resources under the name Royal Resources, Inc. In July 2001, we reorganized our business to pursue oil and 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.

Our strategy is to maximize shareholder value by leveraging our significant acreage position and the experience of our management and technical teams in finding and developing natural gas reserves to profitably grow our reserves and production. Over the last several years we have focused primarily on the acquisition of properties in the Antrim and New Albany shale. We have recently begun to acquire properties in the Woodford shale. As an early stage developer of properties, we anticipate reserve growth will be our initial focus followed by a more traditional balance between reserve and production growth.

Our Strategy

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.

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 612,577 net leasehold acres on which we have identified approximately 2,500 net potential drilling locations. In the Antrim shale play there have been over 9,000 successful gas wells drilled and are currently in production. 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.

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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-sourced 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 June 30, 2007, we operated 39% of our completed wells.

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.

Our Strengths

We believe that our strengths will help us successfully execute our strategy. These strengths include:

Inventory of growth opportunities. We have established an asset base of approximately 612,577 net leasehold acres in our shale areas, of which approximately 92% were undeveloped as of June 30, 2007. As of that date, we had approximately 2,500 net potential drilling locations on this acreage. At our current planned drilling rate, this would accommodate approximately fifteen plus years of drilling activity.

Experienced management and technical teams. Our four senior executive officers average 26 years of experience in the natural gas industry. In addition, we employ one staff geologist, one senior oil and gas petroleum engineer, and three senior land professionals with an average over 22 years of oil and gas experience.

Operational control. As of June 30, 2007, we operated approximately 39% of the wells in which we have an interest, and we expect our 66% average working interest in leases to allow us to increase the number of wells we will operate in the future. This will afford us a significant degree of control over costs and other operational matters.

Our Challenges

Investing in our common stock involves risks. You should read carefully the section of this prospectus entitled “Risk Factors” beginning on page 11 and “Cautionary Note Regarding Forward-Looking Statements” on page 21 for an explanation of these risks before investing in our common stock. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy as well as activities on our properties, which could cause a decrease in the price of our common stock and a loss of all or part of your investment.

Price volatility. Market prices for natural gas may fluctuate widely for reasons that are outside of our control.

Risks relating to the development of natural gas reserves. Our natural gas reserves and future production and, therefore, our future cash flow and income are highly dependent on our ability to successfully execute our drilling program, which will require substantially greater amounts of capital than we currently have available to us.

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Risks relating to natural gas reserve estimates. Reserve estimates are based on many assumptions and our properties may not produce the reserves we originally forecast. Our reserves will decline unless we are successful in finding or acquiring new reserves.

Access to equipment and personnel. Shortages of drilling rigs, equipment, supplies or personnel could delay, restrict or increase the cost of our exploration, exploitation and development operations, which in turn could impair our financial condition and results of operations.

Operating Areas

Antrim Shale. Our Antrim shale properties are located in Michigan and represent our primary area of development over the near term. Nearly all of our development operations in this play/trend are focused on unconventional shale plays. Shale development typically results in higher drilling success and lower drilling costs when compared to conventional exploration and development activity.

Antrim shale underlies the entire Michigan basin. The shale is very thick (140 to over 200 feet) and has a high percentage of organic content (up to 20%). Due to the makeup of the natural fractures in the Antrim shale, production will vary from well to well.

The productive, fractured trend for the Antrim shale runs across the northern portion of the Michigan basin from Lake Huron to Lake Michigan (160 miles). Gas wells have been drilled and produced in the Antrim shale from depths of 250 feet down to 1,500 feet below the surface. A high percentage of the wells drilled in the Antrim shale have been put into production and levels of production vary from well to well. Over 9,000 wells are currently producing in the Antrim shale. In recent years, 200 to 400 wells have been drilled annually by all operators in the Antrim shale.

The gas produced from the Antrim shale is primarily a biogenic gas due to the presence of microbes in the low to medium saline waters. The low-density pay zones in the Antrim shale are over 100 feet thick. Methane gas is continuously being generated by anaerobic bacteria that feed on C02 organic material, and the heavier oil and gases stored in the shale.

The Antrim shale gas adsorbs to organic material in a manner similar to gas in coal seams. Water in the natural fractures of the shale provides a trapping mechanism to hold the gas in place. As the water is produced, lowering the fluid and pressure in the reservoir, gases are released from the organic material and are produced to the surface. At depths of less than 1,500 feet, the gas-in-place is typically 90% methane or greater, with the balance being C02 and some heavier gases.

The oldest Antrim shale gas field was drilled in the 1940s, and it is still in production today. The production curve for the shale typically contains a peak rate of gas occurring after the first two years of production when the shale reservoir has been thoroughly dewatered. Peak rate production usually continues for some time. After the water is taken from the formation and the gas is able to fully release from the shale into the well bore, the rate of production will typically begin to decline 2% to 7% per year.

We have identified the Michigan Antrim shale as an area with natural fractures using a variety of diagnostic tests, including a review of production trends, fracture imaging logs and geological mapping. In management's opinion, based upon performance information from over 9,000 wells with comparable geologic characteristics, areas with natural fractures in shale have compelling production potential.

At June 30, 2007, we owned working interests in 528 (270 net) Antrim wells. For the six months ended June 30, 2007, we drilled or participated in 29 (13 net) wells with a 92% success rate. In 2006, we drilled 173 (98 net) Antrim wells and successfully completed 164 gross wells for a success rate of 95%. On average, our Antrim wells are drilled to depths ranging from 250 to 1,500 feet targeting reserves of 0.513 bcfe per well based upon our December 31, 2006, Schlumberger reserve report.

New Albany shale. Our New Albany shale properties are located in Southern Indiana and Western Kentucky and represent a relatively new area of activity for us. Most of our exploratory and developmental operations in the Illinois geological basin are focused on unconventional shale plays. The New Albany shale play, much of which is located in Indiana, is an emerging play with similar characteristics to the Antrim shale play. It is also very thick (100 to over 200 feet) and covers approximately 6,000,000 gross acres, with proven producing pay zones throughout. The shale is capped by the Borden shale, a very thick, dense, gray-green shale.

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In the New Albany shale, a well commonly produces water along with the gas. In the early 1900's, it was learned that a simple open-hole completion in the very top of the shale would yield commercial gas wells that would last for many years, even while producing some water. Vertical fractures in the shale feed the gas flow at the top of the shale. The potential of these wells was seldom realized in the early to mid-twentieth century, as the production systems for handling the associated water were limited. However, with current technology, the water can be dealt with cost effectively and allow for better rates of gas production.

Significant research and study has been conducted to evaluate the producibility of the New Albany shale. In cooperation with the Gas Research Institute, we combined resources and data with 11 other industry partners in a shale gas producibility consortium lasting almost two years (concluded in 1999). The consortium identified critical differences and similarities of the New Albany shale play to other shale plays. The consortium study observed that the New Albany shale reservoir contained high-angled (vertical or nearly so) natural fractures that are open to unimpeded flow. The predominant fracture system is oriented east-west with spacing between joints estimated to average five feet based on outcrop studies and production simulations. Based on this information, it was concluded that increases in performance could be achieved with a horizontally drilled well compared to a vertically drilled well in the same reservoir.

Reserve studies were conducted on behalf of the consortium by Schlumberger Holditch & Associates for both vertical producing wells and horizontal wells. Since then, we have participated in approximately 30 pilot horizontal well drilling projects across multiple counties which support the conclusions of the consortium. With the data from these pilot wells, we have established a development concept for the New Albany shale, which we began to implement in 2006.

Our New Albany shale projects are characterized by declining natural gas and water production with peak natural gas and water flow rates occurring in the first 60 days. Our New Albany shale wells are drilled to depths ranging from 500 to 3,000 feet and based on our December 31, 2006, Schlumberger reserve report could yield an average reserve of 1.2 bcfe per well. At June 30, 2007, we owned working interests in 50 (11.61 net) New Albany shale wells. For the six months ended June 30, 2007, we drilled or participated in 16 (4.05 net) wells with a 100% success rate. In 2006, we drilled 26 (7.49 net) New Albany shale wells and successfully completed 25 of these wells for a success rate of 96%.

Recent Developments

Refinancing. On August 20, 2007, we entered into a second lien term loan agreement (the “Term Loan”) with BNP Paribas (“BNP”), as the arranger and administrative agent, and several other lenders forming a syndication. The initial term loan is $50 million for a 5-year term which may increase up to $70 million under certain conditions over the life of the loan facility. The proceeds of the loan were used to pay off the Company’s existing mezzanine financing with Trust Company of the West (‘”TCW”) and for general corporate purposes.

In connection with the Term Loan, we also agreed to the amendment and restatement of its senior secured credit facility with BNP and other lenders, pursuant to which the borrowing base under the senior secured credit facility was increased from the current authorized borrowing base of $50 million to $70 million.

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

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Upon execution of the Term Loan, we also entered into a 3-year interest rate swap transaction with BNP to hedge its exposure to the floating interest rate on the Term Loan debt. This hedge transaction on $50 million will yield an effective interest rate of 11.86% for the period from August 23, 2007 through August 23, 2010.

Effective August 20, 2007, our subsidiary Aurora Antrim North, L.L.C. (“North”) terminated its Amended Note Purchase Agreement with TCW which provided $50 million in mezzanine financing. As of the effective date, North had outstanding borrowing of $40 million. TCW had limited the borrowing base and the agreement contained a commitment expiration date of August 12, 2007. Under the termination provisions, we were required to pay certain fees and prepayment charges associated with early termination. The following represents the expenditures paid to TCW: (i) $40 million payment of principal; (ii) $0.7 million payment of interest expense from June 27, 2007 through August 20, 2007; (iii) $0.35 million payment of interest make-whole provision from August 21, 2007 through September 27, 2007; (iv) $1.25 million payment of prepayment premium; and (v) $0.2 million payment for a make-whole provision on principal greater than $30 million.

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

Woodford Shale Play. We have established an acreage position of over 30,000 net acres in the Woodford Shale natural gas play of Oklahoma. In early 2006, in conjunction with a private operator based in Oklahoma, we had identified a Woodford Shale target area. Together, the companies initiated the requisite administrative and leasing efforts required to assemble an acreage block of sufficient scale to offer competitive advantages and support exploration activities. The identified target area is focused in central Oklahoma, which is experiencing a significant increase in leasing and drilling activity. It is positioned among geological provinces with active Woodford Shale development, with average depths over 5,000 feet and organic shale thickness up to 300 feet.

We have expended approximately $6.5 million for an 89% working interest in over 35,000 gross acres in the play. The early leasing activities have allowed us to establish this competitive position in the targeted play area. Leasing activities are continuing. We have targeted 2008 for a pilot program of 5 test wells in its project area. Since our current capital expenditure budget has been dedicated to further development of the Antrim and New Albany Shales, we have been in discussions with potential financing and joint venture partners to facilitate aggressive development of this acreage. No financing for this development has been procured as of the date of this prospectus.

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

Our Offices

Our principal executive offices are located at 4110 Copper Ridge Drive, Suite 100, Traverse City, Michigan 49684, and our telephone number is 231-941-0073. Our website is www.auroraogc.com. Information contained on our website does not constitute a part of this prospectus.

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The Offering

Common stock offered by us	8,900,000 shares
Use of proceeds	We will not receive any of the proceeds from the sale of the shares by the selling security holders. We may receive proceeds in connection with the exercise of warrants, the underlying shares of which may be sold by the selling security holders under this Prospectus. See “Use of Proceeds.”
Dividend policy	We currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future.
AMEX market symbol	“AOG”
Risk factors	Investing in our common stock involves certain risks. You should carefully consider the risk factors discussed under the heading “Risk Factors” beginning on page 11 of this prospectus and other information contained in this prospectus before deciding to invest in our common stock.

Except as otherwise indicated, all information contained in this prospectus:

· excludes 5,257,500 shares of common stock reserved for issuance under our 2006 Stock Incentive Plan;

· excludes 4,794,444 shares of our common stock issuable upon exercise of outstanding options at a weighted average exercise price of $2.30 per share; and

· excludes 1,952,000 shares of our common stock issuable upon exercise of outstanding warrants at a weighted average exercise price of $1.74 per share.

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Summary Financial Data

The following table shows our summary financial data as of and for each of the periods indicated. The data as of and for the years ended December 31, 2006, and 2005, is derived from our historical audited consolidated financial statements for the periods indicated. The data as of and for the six months ended June 30, 2007, and 2006, is derived from our historical unaudited condensed consolidated financial statements for the interim periods indicated. The interim unaudited information was prepared on a basis consistent with that used in preparing our audited consolidated financial statements and includes all adjustments, consisting of normal and recurring items, that we consider necessary for a fair presentation of the financial position, results of operations and cash flows for the unaudited periods. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated historical financial statements and related notes included elsewhere in this prospectus.

	Six Months Ended June 30,						Year Ended December 31,(a)
	2007			2006			2006			2005
Statement of operations data
Revenues
Oil and natural gas sales	$	12,532,005		$	10,941,220		$	21,591,811		$	6,743,444
Pipeline transportation and marketing		286,932			242,299			1,179,431			-
Field service and sales		249,602			-			125,611			-
Interest and other income		474,758			181,631			220,592			666,850
Total revenue		13,543,297			11,365,150			23,117,445			7,410,294
Expenses
Production taxes		566,969			445,825			877,319			506,635
Production and lease operating expense		4,126,700			2,853,374			6,278,131			1,587,205
Pipeline operating expense		177,802			137,484			643,963			-
Field service expense		200,096			-			90,913			-
General and administrative expense		4,233,701			3,242,713			7,531,718			3,435,507
Oil and natural gas depletion and amortization		1,523,460			2,010,383			2,681,290			767,511
Other assets depreciation and amortization		1,142,104			1,013,783			2,083,191			308,647
Interest expense		2,050,403			3,564,154			4,573,785			1,307,370
Taxes (refunds), other		(53	)		29,361			250,884			29,651
Total expenses		14,021,182			13,297,077			25,011,194			7,942,526
Loss before minority interest		(477,885	)		(1,931,927	)		(1,893,749	)		(532,232	)
Minority interest in (income) loss of subsidiaries		(32,957	)		(17,919	)		(50,898	)		15,960
Net loss	$	(510,842	)	$	(1,949,846	)	$	(1,944,647	)	$	(516,272	)
Net loss per common share — basic and diluted	$	(0.01	)	$	(0.03	)	$	(0.02	)	$	(0.01	)
Weighted average common shares outstanding — basic and diluted		101,602,875			70,265,281			82,288,243			40,622,000
Cash flow data
Cash provided (used) by operating activities	$	5,411,775		$	3,607,502		$	2,244,535		$	(2,392,118	)
Cash used by investing activities		(32,016,909	)		(61,497,361	)		(86,317,737	)		(39,881,947	)
Cash provided by financing activities		25,590,236			49,504,174			73,827,960			49,075,121

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	As of June 30,		As of December 31,(a)
	2007		2006		2005
Balance sheet data
Cash and cash equivalents	$	720,498	$	1,735,396	$	11,980,638
Other current assets		9,006,600		12,728,588		7,274,869
Oil and gas properties, net (using full cost accounting)		184,249,398		161,294,155		68,960,754
Other property and equipment, net		9,306,214		9,221,228		3,610,138
Other assets		25,116,848		27,407,825		24,995,746
Total assets	$	228,399,558	$	212,387,192	$	116,822,145
Current liabilities	$	11,207,070	$	18,117,955	$	17,341,431
Long-term debt, net of current maturities		79,187,004		54,538,138		42,794,862
Redeemable convertible preferred stock		-		-		59,925
Shareholders’ equity		138,005,484		139,731,099		56,625,927
Total liabilities and shareholders’ equity	$	228,399,558	$	212,387,192	$	116,822,145

(a) 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. 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 (now known as Aurora Oil & Gas Corporation) businesses have been included in the financial statements from the date of acquisition. The common stock per share information in the consolidated financial statements for the year ended December 31, 2005, and related notes have been retroactively adjusted to give effect to the reverse merger on October 31, 2005.

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Summary Operating and Reserve Data

The following table summarizes our operating and reserve data as of and for each of the periods indicated:

	Six Months Ended June 30,		Year Ended December 31,
	2007		2006		2005
Production
Oil (bbls)		13,772		22,588		10,628
Natural gas (mcf)		1,410,820		2,517,897		687,271
Natural gas equivalent (mcfe)		1,493,453		2,653,427		751,039
Oil and natural gas sales
Oil sales	$	784,991	$	1,399,445	$	558,455
Natural gas sales		11,747,014		20,192,366		6,184,989
Total	$	12,532,005	$	21,591,811	$	6,743,444
Average sales price (including realized gains or losses from hedging)
Oil ($ per bbl)	$	57.00	$	61.95	$	52.54
Natural gas ($ per mcf)		8.33		8.02		9.00
Natural gas equivalent ($ per mcfe)		8.39		8.14		8.98
Average production cost ($ per mcfe)
Production taxes	$	0.38	$	0.33	$	0.67
Post-production expenses		0.54		0.55		0.50
Leasing operating expenses		2.23		1.82		1.62
Total	$	3.15	$	2.70	$	2.79

	As of December 31,
	2006		2005
Estimated proved reserves(a)
Oil (mbbls)		81		99
Natural gas (mmcf)		152,964		63,321
Natural gas equivalent (mmcfe)		153,450		63,915
PV-10(b)	$	158,782,810	$	199,507,440
Standardized measure(c)	$	130,461,821	$	152,868,240

(a) Proved reserves are those quantities of gas which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable from known reservoirs and under current economic conditions, operating methods, and government regulations.

(b) Represents the present value, discounted at 10% per annum (PV-10), of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on economic conditions prevailing at December 31, 2006, and 2005, respectively. The estimated future production is priced at December 30, 2006, without escalation, using $57.81 per bbl and $5.84 per mmbtu. The estimated future production is priced at December 31, 2005, without escalation, using $55.75 to $57.92 per bbl and $9.89 per mmbtu. PV-10 is a non-GAAP financial measure because it excludes income tax effects. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of PV-10 to the most directly comparable GAAP measure — standardized measure of discounted future net cash flows — in the following table:

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	As of December 31,
	2006		2005
Standardized measure of discounted future net cash flows	$	130,461,821	$	152,868,240
Add: Present value of future income tax discounted at 10%		28,320,989		46,639,204
PV-10	$	158,782,810	$	199,507,444

(c) The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

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RISK FACTORS

An investment in our common stock involves a high degree of risk. You shouldcarefully consider the following risks and all of the other information contained inthis prospectus before deciding to invest in our common stock. The risks describedbelow are not the only ones facing our company. Additional risks not presently knownto us or which we currently consider immaterial also may adversely affect ourcompany.

RISKS RELATED TO OUR BUSINESS

Natural gas prices are volatile. A substantial decrease in natural gas prices wouldsignificantly affect our business and impede our growth.

Our revenues, profitability and future growth depend upon prevailing natural gas prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of natural gas that we can economically produce. It is possible that prices will be low at the time periods in which the wells are most productive, thereby reducing overall returns. It is possible that prices will drop so low that production will become uneconomical. Ongoing production costs that will continue include equipment maintenance, compression and pumping costs. If production becomes uneconomical, we may decide to discontinue production until prices improve.

Prices for natural gas fluctuate widely. For example, from January 1, 2006, through June 30, 2007, natural gas prices quoted for the near month NYMEX contract have ranged from a low of $6.03 per mmbtu to a high of $8.23 per mmbtu. The prices for natural gas are subject to a variety of factors beyond our control, including:

· the level of consumer product demand;

· weather conditions;

· domestic and foreign governmental regulations;

· the price and availability of alternative fuels;

· political conditions in oil and natural gas producing regions;

· the domestic and foreign supply of oil and natural gas;

· speculative trading and other market uncertainty; and

· worldwide economic conditions.

The failure to develop reserves could adversely affect our production and cash flows.

Our success depends upon our ability to find, develop or acquire natural gas reserves that are economically recoverable. We will need to conduct successful exploration or development activities or acquire properties containing proved reserves, or both. The business of exploring for, developing or acquiring reserves is capital intensive. We may not be able to make the necessary capital investment to expand our natural gas reserves from cash flows, and external sources of capital may be limited or unavailable. Our drilling activities may not result in significant reserves, and we may not have continuing success drilling productive wells. Exploratory drilling involves more risk than development drilling because exploratory drilling is designed to test formations in which proved reserves have not been discovered. Additionally, while our revenues may increase if prevailing gas prices increase significantly, our finding costs for reserves also could increase, and we may not be able to finance additional exploration or development activities.

We may have difficulty financing our planned growth.

We have incurred and expect to continue to incur substantial capital expenditures and working capital needs, particularly as a result of our property acquisition and development drilling activities. We will require substantial additional financing to fund our planned growth. Additional financing may not be available to us on acceptable terms or at all. If additional capital resources are unavailable, we may be forced to curtail our acquisition, development drilling and other activities or to sell some of our assets on an untimely or unfavorable basis. We are in the process of evaluating strategic alternatives as of the date of this prospectus.

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Most of our current development activity and producing properties are located inMichigan and Indiana, making us vulnerable to risks associated with operating in thisregion.

Our current development activity is concentrated in Michigan and Indiana, and our currently producing properties are located primarily in a six-county area in Michigan. As a result, we may be disproportionately exposed to the impact of drilling and other delays or disruptions of production from these regions caused by weather conditions, governmental regulation, lack of field infrastructure, or other events which impact these areas. In addition, a majority of our leaseholds held for development is located in the more untested New Albany shale play/trend.

Our potential drilling locations comprise an estimation of part of our futuredrilling plans over several years, making them susceptible to uncertainties thatcould materially alter the occurrence or timing of their drilling.

As of June 30, 2007, we had approximately 3,700 net potential drilling locations to be included in our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, seasonal conditions, regulatory approvals, natural gas prices, costs and drilling results. Because of these uncertainties, we do not know if our numerous potential drilling locations will ever be drilled or if we will be able to produce natural gas from these or any other potential drilling locations, which could materially affect our business.

We may continue to incur losses.

We reported a net loss for the years ended December 31, 2006, and 2005, and the six months ended June 30, 2007. We expect to report a net loss in the third quarter of 2007 and also expect to show a net reduction in working capital and shareholder equity in the third quarter of 2007. There is no assurance that we will be able to achieve and maintain profitability.

We do not operate a substantial amount of our properties.

We conduct much of our oil and natural gas exploration, development and production activities in joint ventures with others. In some cases, we act as operator and retain significant management control. In other cases, we have reserved only an overriding royalty interest and have surrendered all management rights. In still other cases, we have reserved the right to participate in management decisions, but do not have ultimate decision-making authority. As of June 30, 2007, we operated 39% of our wells. As a result of these varying levels of management control, for those properties that we do not operate, we have no control over:

· the number of wells to be drilled;

· the location of wells to be drilled;

· the timing of drilling and re-completing of wells;

· the field company hired to drill and maintain the wells;

· the timing and amounts of production;

· the approval of other participants in drilling wells;

· development and operating costs;

· capital calls on working interest owners; and

· pipeline nominations.

These and other aspects of the operation of our properties and the success of our drilling and development activities will in many cases be dependent on the expertise and financial resources of our joint venture partners and third-party operators.

We may be unable to make acquisitions of producing properties or prospects orsuccessfully integrate them into our operations.

Acquisitions of producing properties and undeveloped oil and natural gas leases have been an essential part of our long-term growth strategy. As of June 30, 2007, we had acquired approximately 1,312,331 (718,699 net) acres with 153,450 mmcfe in net proved reserves. We may not be able to identify suitable acquisitions in the future or to finance these acquisitions on favorable terms or at all. In addition, we compete against other companies for acquisitions, many of whom have substantially greater managerial and financial resources than we have. The successful acquisition of producing properties and undeveloped natural gas leases requires an assessment of the properties’ potential natural gas reserves, future natural gas prices, development costs, operating costs, potential environmental and other liabilities and other factors beyond our control. These assessments are necessarily inexact and their accuracy inherently uncertain. Such a review may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geological characteristics or geographic location than existing properties. Our acquisitions may not be integrated successfully into our operations and may not achieve desired profitability objectives. For example, in 2006 we closed on the acquisition of all of the assets of Bach Enterprises, Inc. (or "Bach") and certain of its affiliates. Bach is an oil and natural gas services company whose services include building compressors, CO2 removal, pipelining and facility construction. Although the Bach acquisition will be operated separately from our current production operations, we have no prior experience in the management of such a service company, and may encounter issues that prevent us from successfully integrating it as part of our business.

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We may lose key management personnel.

Our current management team has substantial experience in the oil and natural gas business. We only have an employment agreement with one member of our management team. The loss of any of these individuals could adversely affect our business. If one or more members of our management team dies, becomes disabled or voluntarily terminates employment with us, there is no assurance that a suitable or comparable replacement will be found.

Much of our proved reserves are not yet generating production revenues.

Of our proved natural gas reserves as of December 31, 2006, approximately 54% are classified as proved developed producing, 15% are classified as proved developed non-producing, and 31% are classified as proved undeveloped.

You should be aware that our ability to convert proved reserves into revenues is subject to certain limitations, including the following:

· Reserves characterized as proved developed producing reserves may be producing predominantly water and generate little or no production revenue;

· Production revenues from estimated proved developed non-producing reserves will not be realized until some time in the future, after we have installed supporting infrastructure or taken other necessary steps. It will be necessary to incur additional capital expenditures to install this required infrastructure;

· Production revenues from estimated proved undeveloped reserves will not be realized until after such time, if ever, as we make significant capital expenditures with respect to the development of such reserves, including expenditures to fund the cost of drilling wells, dewatering the wells, and building the supporting infrastructure; and

· The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of the costs associated with developing these reserves in accordance with industry standards, no assurance can be given that our estimates of capital expenditures will prove accurate, that our financing sources will be sufficient to fully fund our planned development activities, or that development activities will be either successful or in accordance with our schedule. We cannot control the performance of our joint venture partners on whom we depend for development of a substantial number of properties in which we have an economic interest and which are included in our reserves. Further, any significant decrease in oil and natural gas prices or any significant increase in the cost of development could result in a significant reduction in the number of wells drilled. No assurance can be given that any wells will yield commercially viable quantities.

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The oil and natural gas reserve data included in this document are estimates based onassumptions that may be inaccurate and existing economic and operating conditionsthat may differ from future economic and operating conditions.

Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and is based upon assumptions that may change from year to year and vary considerably from actual results. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. Information regarding discounted future net cash flows should not be considered as the current market value of the estimated oil and natural gas reserves that will be attributable to our properties. Examples of items that may cause our estimates to be inaccurate include, but are not limited to, the following:

· The estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower;

· Because we have limited operating cost data to draw upon, the estimated operating costs used to calculate our reserve values may be inaccurate;

· Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation;

· The reserve report for our Michigan Antrim properties assumes that production will be generated from each well for a period of 50 years. Because production is expected for such an extended period of time, the probability is enhanced that conditions at the time of production will vary materially from the current conditions used to calculate future net cash flows; and

· The 10% discount factor, which is required by the Financial Accounting Standards Board in Statement of Financial Accounting Standards No. 69 to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks that will be associated with our operations or the oil and natural gas industry in general.

Our drilling activities may be unsuccessful.

We cannot predict prior to drilling and testing a well whether the well will be productive or whether we will recover all or any portion of our investment in the well. Our drilling for natural gas may involve unprofitable efforts, not only from dry holes but from wells that are productive but do not produce sufficient quantities to cover drilling and completion costs and are not economically viable. Our efforts to identify commercially productive reservoirs, such as studying seismic data, the geology of the area and production history of adjoining fields, do not conclusively establish that natural gas is present in commercial quantities. If our drilling efforts are unsuccessful, our profitability will be adversely affected. For the 18-month period ending June 30, 2007, approximately 7.7% of the gross wells we drilled were unsuccessful.

Production levels cannot be predicted with certainty.

Until a well is drilled and has been in production for a number of months, we will not know what volume of production we can expect to achieve from the well. Even after a well has achieved its full production capacity, we cannot be certain how long the well will continue to produce or the production decline that will occur over the life of the well. Estimates as to production volumes and production life are based on studies of similar wells (of which there are relatively few in the New Albany play) and, therefore, are speculative and not fully reliable. As a result, our revenue budgets for producing wells may prove to be inaccurate.

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Drilling and production delays may occur.

In order to generate revenues from the sale of oil and natural gas production from new wells, we must complete significant development activity. Delay in receiving governmental permits, adverse weather, a shortage of labor or parts, and/or dewatering time frames may cause delays, as discussed below. These delays will result in delays in achieving revenues from these new wells.

Oil and natural gas producers often compete for experienced and competent drilling, completion and facilities installation vendors and production laborers. The unavailability of experienced and competent vendors and laborers may cause development and production delays.

From time to time, vendors of equipment needed for oil and natural gas drilling and production become backlogged, forcing delays in development until suitable equipment can be obtained.

For each new well, before drilling can commence, we will have to obtain a drilling permit from the state in which the well is located. We will also have to obtain a permit for each salt water disposal well. It is possible that for reasons outside of our control, the issuance of the required permits will be delayed, thereby delaying the time at which production is achieved. We have previously experienced a delay in receiving permits from the State of Michigan, Department of Environmental Quality ("DEQ"), for drilling horizontal wells, while the DEQ further reviews this drilling methodology. As a result of these delays, we have had to defer the drilling of certain wells in the Antrim shale until the review by the DEQ was completed and permits were issued. The DEQ has also forced producers to discontinue operations in certain areas of the Michigan Antrim so that the DEQ can inspect the salt water disposal wells operated in those areas. We have no control over this type of regulatory delay.

The DEQ has also recently instituted a water sampling and monitoring requirement for wells north of a line that includes three of our Antrim projects. The drilling permits for these wells require produced water monitoring and reporting of gas and water volume and water quality. If the water produced by a well has levels of dissolved solid concentration below specified levels, we may be required to shut-in the well. If the well cannot be remediated so that fresh water is no longer produced, we may be required to plug the well.

Adverse weather may foreclose any drilling or development activity, forcing delays until more favorable weather conditions develop. This is more likely to occur during the winter and spring months, but can occur at other times of the year.

Different natural gas reservoirs contain different amounts of water. The actual amount of time required for dewatering with respect to each well cannot be predicted with accuracy. The period of time when the volume of gas that is produced is limited by the dewatering process may be extended, thereby delaying revenue production.

Pipeline capacity may be inadequate.

Because of the nature of natural gas development, there may be periods of time when pipeline capacity is inadequate to meet our gas transportation needs. It is often the case that as new development comes online, pipelines are close to or at capacity before new pipelines are built. During periods when pipeline capacity is inadequate, we may be forced to reduce production or incur additional expense as existing production requires additional compression to enter existing pipelines.

Our reliance on third parties for gathering and distribution could curtail futureexploration and production activities.

The marketability of our production will depend on the proximity of our reserves to, and the capacity of, third party facilities and services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities. The unavailability or insufficient capacity of these facilities and services could force us to shut-in producing wells, delay the commencement of production, or discontinue development plans for some of our properties, which would adversely affect our financial condition and performance. During 2006, production was hampered by curtailments in a third-party processing facility; we recently completed construction of our own processing facility and built an alternative pipeline route in response to this curtailment.

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There is a potential for increased costs.

The oil and natural gas industry has historically experienced periods of rapidly increasing drilling and production costs, frequently during times of increased drilling activities. If significant cost increases occur with respect to our development activity, we may have to reduce the number of wells we drill, which may adversely affect our financial performance.

We may incur compression difficulties and expense.

As production of natural gas increases, more compression is generally required to compress the production into the pipeline. As more compression is required, production costs increase, primarily because more fuel is required in the compression process. Furthermore, because compression is a mechanical process, a breakdown may occur that will cause us to be unable to deliver natural gas until repairs are made.

We may not have good and marketable title to our properties.

It is customary in the oil and natural gas industry that upon acquiring an interest in a non-producing property, only a preliminary title investigation is done at that time and that a drilling title opinion is done prior to the initiation of drilling, neither of which can substitute for a complete title investigation. We have followed this custom to date and intend to continue to follow this custom in the future. Furthermore, title insurance is not available for mineral leases, and we will not obtain title insurance or other guaranty or warranty of good title. If the title to our prospects should prove to be defective, we could lose the costs that we have incurred in their acquisition or incur substantial costs for curative title work.

Competition in our industry is intense, and we are smaller and have a more limitedoperating history than most of our competitors.

We compete with major and independent oil and natural gas companies for property acquisitions and for the equipment and labor required to develop and operate these properties. Most of our competitors have substantially greater financial and other resources than we do. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for oil and natural gas prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to complete transactions in this highly competitive environment.

Oil and natural gas operations involve various operating risks.

The oil and natural gas business involves operating hazards such as well blowouts, craterings, explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks. Personal injuries, damage to property and equipment, reservoir damage, or loss of reserves may occur if such a catastrophe occurs, any one of which could cause us to experience substantial losses. In addition, we may be liable for environmental damage caused by previous owners of properties purchased or leased by us.

Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions all could adversely affect our ability to produce and market our natural gas and crude oil. Production from natural gas wells in many geographic areas of the United States has been curtailed or shut-in for considerable periods of time due to a lack of market demand, and such curtailments may continue for a considerable period of time in the future. There may be an excess supply of natural gas in areas where our operations will be conducted. If so, it is possible that there will be no market or a very limited market for our production.

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As a result of operating hazards, regulatory risks and other uninsured risks, we could incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate funds available for exploration, development or acquisitions.

We may lack insurance that could lower risks to our investors.

We have procured insurance policies for general liability, property/pollution, well control and director and officer liability in amounts considered by management to be adequate, as well as a $20 million excess liability umbrella policy. Nonetheless, the policy limits may be inadequate in the case of a catastrophic loss, and there are some risks that are not insurable. We have limited business interruption insurance. An uninsured loss could adversely affect our financial performance.

Our credit facilities have operating restrictions and financial covenants that limitour flexibility and may limit our borrowing capacity; needed increases in borrowingcapacity may not be available.

As of June 30, 2007, our outstanding debt includes a senior credit facility with a current approved borrowing base of $50 million, $35 million of which is currently drawn, a mezzanine financing facility with a current approved borrowing base of $50 million, of which $40 million is currently drawn, and a $5 million revolving line of credit, of which $1.4 million is currently drawn. Our mezzanine credit facility limits the amount of earnings from production that are available to us with regard to the properties pledged as collateral on the loan. All of our credit facilities, other than our office mortgage loan, have operational restrictions and credit ratio compliance requirements that limit our flexibility. If the ratio requirements are not satisfied, curative action may be required, such as repaying a part of the outstanding principal or pledging more assets as collateral, and we will be unable to draw more funds to use in development.

The value of the assets pledged as collateral under our senior credit facility and mezzanine financing facility will depend on the then current commodity prices for natural gas. If prices drop significantly, we may have trouble satisfying the ratio covenants of these credit facilities. As noted above, oil and natural gas prices are volatile. The value of the stock pledged to support the guaranty of our revolving line of credit is tied to the price at which our stock is trading. We will be unable to control this variable.

In order to execute our current development plan we will need to increase our credit availability as we add proved reserves. If we are unable to convert our assets to proved reserves at our planned pace, or if the value of our proved reserves drops as described above, we may be unable to increase our available credit as needed. Furthermore, any increases to our available credit will be entirely within the discretion of our lenders and may not be available to us even if we are successful in increasing the value of our proved reserves.

If we are unable to make use of our credit facilities, it may be difficult to find replacement sources of financing to use for working capital, capital expenditures, drilling, technology purchases or other purposes. Even if replacement financing is available, it may be on less advantageous terms than the current credit facilities. If we are unable to obtain increases in our borrowing capacity as needed, we may be unable to execute our development plan as described in this Prospectus.

We have hedged and may continue to hedge a portion of our production, which mayresult in our making cash payments or prevent us from receiving the full benefit ofincreases in prices for oil and natural gas.

In order to reduce our exposure to short-term fluctuations in the price of oil and natural gas, and in some cases as required by our lenders, we periodically enter into hedging arrangements. Our hedging arrangements apply to only a portion of our production and provide only partial price protection against declines in oil and natural gas prices. Such hedging arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected, our customers fail to purchase contracted quantities of oil or natural gas or a sudden, unexpected event materially impacts oil or natural gas prices. In addition, our hedging arrangements may limit the benefit to us of increases in the price of oil and natural gas.

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We will be subject to the requirements of Section 404 of the Sarbanes-Oxley Act.If we are unable to timely comply with Section 404 or if the costs related tocompliance are significant, our profitability, stock price and results of operationsand financial condition could be materially adversely affected.

We will be required to comply with the provisions of Section 404 of the Sarbanes-Oxley Act of 2002 as of December 31, 2007. Section 404 requires that we document and test our internal controls over financial reporting and issue management’s assessment of our internal controls over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls and management’s assessment of those controls. We will be required to evaluate our existing controls against the criteria established in "Internal Control — Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO. During the course of our ongoing evaluation and integration of the internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review.

We believe that the out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance significantly exceed our current expectations, our results of operations could be materially affected.

We cannot be certain at this time that we will be able to successfully complete the procedures, certification and attestation requirements of Section 404 or that we or our auditors will not identify material weaknesses in internal control over financial reporting. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report such material weakness, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal controls over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

We are subject to complex federal, state and local laws and regulations that couldadversely affect our business.

Oil and natural gas operations are subject to various federal, state and local government laws and regulations, which may be changed from time to time in response to economic or political conditions. Matters that are typically regulated include:

· discharge permits for drilling operations;

· drilling bonds;

· reports concerning operations;

· spacing of wells;

· unitization and pooling of properties;

· environmental protection; and

· taxation.

From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of natural gas and crude oil. We also are subject to changing and extensive tax laws, the effects of which we cannot predict.

The development, production, handling, storage, transportation and disposal of natural gas and crude oil, by-products and other substances and materials produced or used in connection with oil and natural gas operations are subject to laws and regulations primarily relating to protection of human health and the environment. The discharge of natural gas, crude oil or pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties and may result in the assessment of civil or criminal penalties or require us to incur substantial costs of remediation.

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Legal and tax requirements frequently are changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. Existing laws or regulations, as currently interpreted or reinterpreted in the future, could harm our business, results of operations and financial condition.

RISKS RELATED TO THE OWNERSHIP OF OUR STOCK

We may experience volatility in our stock price.

For the 18-month period ending June 30, 2007, our stock traded as high as $3.30 per share and as low as $1.30 per share. The market price of our common stock may fluctuate significantly in response to a number of factors, some of which are beyond our control, including:

· changes in natural gas prices;

· changes in the natural gas industry and the overall economic environment;

· quarterly variations in operating results;

· changes in financial estimates by securities analysts;

· changes in market valuations of other similar companies;

· announcements by us or our competitors of new discoveries or of significant technical innovations, contracts, acquisitions, strategic partnerships or joint ventures;

· additions or departures of key personnel;

· any deviations in net sales or in losses from levels expected by securities analysts; and

· future sales of our common stock.

In addition, the stock market from time to time experiences extreme volatility that has often been unrelated to the performance of particular companies. These market fluctuations may cause our stock price to fall regardless of our performance.

A small number of existing shareholders control us and we do not have cumulativevoting.

In connection with the closing of the merger of Cadence Resources Corporation and Aurora Energy, Ltd. certain of our shareholders, including certain former Aurora shareholders who became shareholders of us in connection with the merger, executed and delivered voting agreements pursuant to which they agreed, until October 31, 2008, to vote their shares of our common stock in favor of (i) five directors designated by William W. Deneau, who were initially William W. Deneau, Earl V. Young, Gary J. Myles, Richard Deneau, and Ronald E. Huff; and (ii) two directors designated by William W. Deneau from among our board of directors immediately before the closing of the merger, who were initially Howard Crosby and Kevin Stulp. In addition, these shareholders agreed to vote all of their shares of common stock to ensure that the size of our board of directors will be set and remain at seven directors. After recent amendments to the voting agreements, an aggregate of 11,702,580 shares, approximately 11.5% of our outstanding shares, are subject to these voting agreements.

Also in connection with the closing of the merger, certain of our shareholders executed and delivered irrevocable proxies naming William W. Deneau and Lorraine King as proxies to vote their shares through October 31, 2008, in the manner determined by such proxies. An aggregate of approximately 10.7 million shares of our common stock held by such shareholders was subject to these proxies at June 30, 2007. These provisions will limit our other shareholders’ ability to influence the outcome of shareholder votes through October 31, 2008, including votes concerning the election of directors, the adoption or amendment of provisions in our articles of incorporation or bylaws and the approval of mergers and other significant corporate transactions.

Our shareholders do not have the right to cumulative voting in the election of our directors. Cumulative voting, in some cases, could allow a minority group to elect at least one director to our board. Because there is no provision for cumulative voting, a minority group will not be able to elect any directors. Accordingly, the holders of a majority of the shares of common stock, present in person or by proxy, will be able to elect all of the members of our board of directors.

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Our articles of incorporation contain provisions that discourage a change of control.

Our articles of incorporation contain provisions that could discourage an acquisition or change of control without our board of directors’ approval. Our articles of incorporation authorize our board of directors to issue preferred stock without shareholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire control of us, even if that change of control might be beneficial to our shareholders.

You may experience dilution of your ownership interests due to the future issuance ofshares of our common stock, which could have an adverse effect on our stock price.

We may, in the future, issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present shareholders. Our authorized capital stock consists of 250,000,000 shares of common stock and 20,000,000 shares of preferred stock with such designations, preferences and rights as may be determined by our board of directors. On June 30, 2007, we had 101,589,456 shares of common stock outstanding.

At June 30, 2007, we had warrants and options outstanding that were exercisable for 6,746,444 shares of our common stock. We have an additional 5,257,500 shares available for award as either option or stock grants under our existing incentive plans. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock. We may also issue additional shares of our common stock or other securities that are convertible into or exercisable for common stock in connection with the hiring of personnel, future acquisitions, private placements of our securities for capital raising purposes, or for other business purposes. In the future, we may engage in public offerings of our stock. Future sales of substantial amounts of our common stock, or the perception that sales could occur, could have a material adverse effect on the price of our common stock.

The market price of our common stock could be adversely affected by sales ofsubstantial amounts of our common stock in the public markets.

We have two shelf registration statements that are currently effective, which together have registered almost 20.6 million shares of common stock for resale. The sale of a large number of shares of our common stock pursuant to the resale registration statements, the perception that any such sale might occur, or the issuance of a large number of shares of our common stock in connection with future acquisitions, equity financings or otherwise, could cause the market price of our common stock to decline significantly. As of June 30, 2007, we had approximately 101.6 million shares of common stock issued and outstanding, including approximately 10.5 million shares of our common stock held or controlled by our executive officers and directors. Of those 10.5 million shares, 8.6 million are subject to lock-up agreements through October 31, 2008, 0.5 million are eligible for resale on two S-8 registration statements, and the balance are eligible for sale under Rule 144 ("Rule 144") under the Securities Act of 1933, as amended (the "Securities Act"). We have two currently effective S-8 registration statements that, combined, include 469,996 shares owned or controlled by our executive officers and directors that are registered for resale.

20

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

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

· uncertainties about the estimates of reserves;

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

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

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

· domestic demand for oil and natural gas;

· drilling and operating risks;

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

· changes in our drilling plans and related budgets;

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

· other factors discussed above under the heading "Risks Related To Our Business".

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.

21

USE OF PROCEEDS

We will not receive any of the proceeds from the sale of the shares owned by the selling security holders. We may receive proceeds in connection with the exercise of warrants, the underlying shares of which may in turn be sold by the selling security holders. Although the amount and timing of our receipt of any such proceeds are uncertain, such proceeds, if received, will be used for general corporate purposes.

22

PRICE RANGE OF COMMON STOCK

Our common stock trades under the symbol AOG on the American Stock Exchange (“AMEX”). Prior to May 2006, our common stock traded under the symbol CDNR.BB on the Over-the-Counter Bulletin Board Electronic Quotation System maintained by the National Association of Securities Dealers. The following chart shows the range of high and low bid prices/sales prices for our common stock for each fiscal quarter in the last two calendar years plus the first two quarters of 2007. The prices during the time in which our stock traded over-the-counter are bid prices, without retail mark-up, mark-down or commission, and may not necessarily represent actual transactions. The prices during the time in which our stock traded on AMEX are actual sales prices.

Quarter Ended	High Bid/ Sales Price		Low Bid/ Sales Price
March 31, 2005	$	2.95	$	1.05
June 30, 2005	$	2.67	$	2.00
September 30, 2005	$	3.47	$	1.86
December 31, 2005	$	4.85	$	3.15
March 31, 2006	$	7.44	$	4.45
June 30, 2006	$	6.10	$	3.76
September 30, 2006	$	4.74	$	2.94
December 31, 2006	$	3.22	$	3.08
March 31, 2007	$	3.30	$	2.06
June 30, 2007	$	2.77	$	1.30

On September 28, 2007, the last reported sale price of our common stock on AMEX was $1.44 and there were 101,679,456 shares of our common stock outstanding and approximately 527 holders of record.

DIVIDEND POLICY

There have been no cash dividends declared on our common stock since we were formed. We do not intend to pay cash dividends on our common stock for the foreseeable future. Our current credit facilities prohibit our borrowing subsidiaries from declaring dividends, which means that we will generally not have cash flow available from which to pay cash dividends.

23

SELECTED HISTORICAL FINANCIAL DATA

The following table sets forth our selected historical financial data as of and for each of the periods indicated. The data as of and for the years ended December 31, 2006, and 2005, is derived from our historical audited consolidated financial statements for the periods indicated. The data as of and for the six months ended June 30, 2007, and 2006, is derived from our historical unaudited condensed consolidated financial statements for the interim periods indicated. The interim unaudited information was prepared on a basis consistent with that used in preparing our audited consolidated financial statements and includes all adjustments, consisting only of normal and recurring items, that we consider necessary for a fair presentation of the financial position, results of operations and cash flows for the unaudited periods. Operating results for the six months ended June 30, 2007, are not necessarily indicative of results that may be expected for the entire year 2007 or any future periods. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated historical financial statements and related notes included elsewhere in this prospectus.

	Six Months Ended June 30,						Year Ended December 31,(a)
	2007			2006			2006			2005
Statement of operations data
Revenues
Oil and natural gas sales	$	12,532,005		$	10,941,220		$	21,591,811		$	6,743,444
Pipeline transportation and marketing		286,932			242,299			1,179,431			-
Field service and sales		249,602			-			125,611			-
Interest and other income		474,758			181,631			220,592			666,850
Total revenue		13,543,297			11,365,150			23,117,445			7,410,294
Expenses
Production taxes		566,969			445,825			877,319			506,635
Production and lease operating expense		4,126,700			2,853,374			6,278,131			1,587,205
Pipeline operating expense		177,802			137,484			643,963			-
Field service expense		200,096			-			90,913			-
General and administrative expense		4,233,701			3,242,713			7,531,718			3,435,507
Oil and natural gas depletion and amortization		1,523,460			2,010,383			2,681,290			767,511
Other assets depreciation and amortization		1,142,104			1,013,783			2,083,191			308,647
Interest expense		2,050,403			3,564,154			4,573,785			1,307,370
Taxes		(53	)		29,361			250,884			29,651
Total expenses		14,021,182			13,297,077			25,011,194			7,942,526
Loss before minority interest		(477,885	)		(1,931,927	)		(1,893,749	)		(532,232	)
Minority interest in (income) loss of subsidiaries		(32,957	)		(17,919	)		(50,898	)		15,960
Net loss	$	(510,842	)	$	(1,949,846	)	$	(1,944,647	)	$	(516,272	)
Net loss per common share — basic and diluted	$	(0.01	)	$	(0.03	)	$	(0.02	)	$	(0.01	)
Weighted average common shares outstanding — basic and diluted		101,602,875			70,265,281			82,288,243			40,622,000
Cash flow data
Cash provided (used) by operating activities	$	5,411,775		$	3,607,502		$	2,244,535		$	(2,392,118	)
Cash used by investing activities		(32,016,909	)		(61,497,361	)		(86,317,737	)		(39,881,947	)
Cash provided by financing activities		25,590,236			49,504,174			73,827,960			49,075,121

24

	As of June 30,		As of December 31,(a)
	2007		2006		2005
Balance sheet data
Cash and cash equivalents	$	720,498	$	1,735,396	$	11,980,638
Other current assets		9,006,600		12,728,588		7,274,869
Oil and gas properties, net (using full cost accounting)		184,249,398		161,294,155		68,960,754
Other property and equipment, net		9,306,214		9,221,228		3,610,138
Other assets		25,116,848		27,407,825		24,995,746
Total assets	$	228,399,558	$	212,387,192	$	116,822,145
Current liabilities	$	11,207,070	$	18,117,955	$	17,341,431
Long-term debt, net of current maturities		79,187,004		54,538,138		42,794,862
Redeemable convertible preferred stock		-		-		59,925
Shareholders’ equity		138,005,484		139,731,099		56,625,927
Total liabilities and shareholders’ equity	$	228,399,558	$	212,387,192	$	116,822,145

(a) We acquired 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. 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 (now known as Aurora Oil & Gas Corporation) businesses have been included in the financial statements from the date of acquisition. The common stock per share information in the consolidated financial statements for the year ended December 31, 2005, and related notes have been retroactively adjusted to give effect to the reverse merger on October 31, 2005.

25

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the“Selected Historical Financial Data” and the consolidated financial statements andrelated notes included elsewhere in this prospectus. This discussion containsforward-looking statements reflecting our current expectations and estimates andassumptions concerning events and financial trends that may affect our futureoperating results or financial position. Actual results and the timing of events maydiffer materially from those contained in these forward-looking statements due to anumber of factors, including those discussed in the sections entitled “Risk Factors”and “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere inthis prospectus.

Executive Summary

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

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

Our revenue, profitability and future rate of growth are substantially dependent on our ability to find, develop, and acquire gas reserves that are economically recoverable based on prevailing prices of natural gas and oil. Historically, the energy markets have been very volatile, and it is likely that oil and natural gas prices will continue to be subject to wide fluctuations in the future. A substantial or extended decline in natural gas and oil prices could have a material adverse effect on our financial position, results of operations, cash flows, access to capital and on the quantities of natural gas and oil that can be economically produced.

Highlights

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

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

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

26

Effective June 1, 2007, the Company entered into a firm sales contract with Integrys Energy Services, Inc. (formerly WPS) for 5,000 mmbtu per day at MichCon city-gate for the period of June 1, 2007 through December 31, 2008. Integrys Energy Services, Inc. will be the Company’s primary marketing partner for all of Michigan operated properties. The Company expects this partnering to provide extensive market and pipeline knowledge, strong credit worthiness as well as back office support.

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

Our 2007 capital budget for drilling and related well work and infrastructure has been revised from an estimated $73.7 million with participation in 291 (182 net) wells to an estimated $52.9 million with participation in 162 (111 net) wells. The following table summarizes our revised 2007 drilling and related well work budget for our key exploration and development areas:

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

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

27

RESULTS OF OPERATIONS

Operating Statistics

The following table sets forth certain key operating statistics for the six months ended June 30, 2007, and 2006, and for the years ended December 31, 2006, and 2005:

	Six Months Ended June 30,				Year Ended December 31,
	2007		2006		2006		2005
Total net acreage held
Antrim		156,517		125,993		154,643		78,163
New Albany		456,060		449,460		441,351		271,891
Other		106,122		45,837		93,897		14,036
Total		718,699		621,290		689,891		364,090
Net wells drilled
Antrim		12		27		93		105
New Albany		4		2		7		-
Other		8		4		5		1
Dry		4		2		7		7
Total		28		35		112		113
Total net wells
Antrim - producing		227		154		199		110
Antrim - awaiting hookup		33		31		51		52
NAS - producing		1		-		1		-
NAS - awaiting hookup		1		3		7		2
Other - producing		13		15		14		13
Other - awaiting hookup		1		4		1		6
Total		276		207		273		183
Production
Natural gas (mcf)		1,410,820		1,224,551		2,517,897		687,271
Crude oil (bbls)		13,772		11,888		22,588		10,628
Natural gas equivalent		1,493,453		1,295,879		2,653,427		751,039
Average daily production
Natural gas (mcf)		7,795		6,765		6,898		1,883
Crude oil (bbls)		76		66		62		29
Natural gas equivalent		8,251		7,161		7,270		2,057
Average sales prices (including realized gains or losses from hedging)
Natural gas ($ per mcf)	$	8.33	$	8.33	$	8.02	$	9.00
Crude oil ($ per bbl)	$	57.00	$	62.34	$	61.95	$	52.54
Natural gas equivalent	$	8.39	$	8.44	$	8.14	$	8.98
Production revenue
Natural gas	$	11,747,014	$	10,200,110	$	20,192,366	$	6,184,989
Crude oil		784,991		741,110		1,399,445		558,455
Total	$	12,532,005	$	10,941,220	$	21,591,811	$	6,743,444

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	Six Months EndedJune 30,				Year EndedDecember 31,
	2007		2006		2006		2005
Average expenses ($ per mcfe)
Production taxes	$	0.38	$	0.34	$	0.33	$	0.67
Post-production expenses		0.54		0.49		0.55		0.50
Leasing operating expenses		2.23		1.71		1.82		1.62
General and administrative expense		2.83		2.50		2.84		4.57
General and administrative expense excluding stock-based compensation		2.03		1.92		2.00		4.57
Oil and natural gas depreciation, depletion and amortization expense		1.02		1.55		1.01		1.02
Other assets depreciation and amortization		0.76		0.78		0.79		0.41
Interest expense		1.37		2.75		1.72		1.74
Taxes		-		0.02		0.09		0.04
Number of employees		88		53		90		36

RESULTS OF OPERATIONS

Six Months Ended June 30, 2007 (“Current Period”), compared with Six Months Ended June 30, 2006 (“Prior Year Period”)

General. For the Current Period, the Company had a net loss of $0.5 million, or $(0.01) per diluted common share, on total revenues of $13.5 million. This compares to a net loss of $1.9 million, or $(0.03) per diluted common share, on total revenue of $11.4 million for the Prior Year Period. The $2.2 million increase in revenue represents our initial steps as an early stage developer of oil and natural gas properties as well as a gain recognized in the sale of mining claims.

Oil and Natural Gas Sales. During the Current Period, oil and natural gas sales were $12.5 million compared to $10.9 million in the Prior Year Period. The Company produced 1,493,453 mcfe at a weighted average price of $8.39 compared to 1,295,879 mcfe at a weighted average price of $8.44. This increase in production was due to new wells placed on-line and gains in stabilizing production in the second quarter of 2007. We had 241 net wells producing as of June 30, 2007, as compared to 169 net wells producing as of June 30, 2006. The weighted average price included $1.4 million and $0.8 million of realized gains from the gas derivative contract for Current Period and Prior Year Period, respectively. Production from the Antrim shale play represented approximately 92% of our oil and natural gas revenue for the Current Period.

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

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

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

Production Taxes. Production taxes were $0.6 million in the Current Period compared to $0.4 million in the Prior Year Period. This increase is attributed to new wells being added and production growth of existing wells. On a unit of production basis, production taxes were $0.38 per mcfe in the Current Period compared to $0.34 per mcfe in the Prior Year Period.

29

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

Production and lease operating expenses were $4.1 million in the Current Period compared to $2.9 million in the Prior Year Period. On a per unit of production basis, production and lease operating expenses were $2.77 per mcfe in the Current Period compared to $2.20 per mcfe in the Prior Year Period. The increase in the Current Period was primarily attributable to higher energy costs, higher property taxes, higher pumping costs, repair and maintenance associated with meters, compressors and pumps, and outside labor. On a component basis, post-production expenses were $0.8 million, or $0.54 per mcfe, in the Current Period compared to $0.6 million, or $0.49 per mcfe, in the Prior Year Period, and lease operating expenses were $3.3 million, or $2.23 per mcfe, in the Current Period compared to $2.2 million, or $1.71 per mcfe, in the Prior Year Period.

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

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

General and Administrative Expenses. Our general and administrative expenses include officer and employee compensation, travel, audit, tax and legal fees, office supplies, utilities, insurance, consulting fees, and office related expense. General and administrative expenses in the Current Period increased by $1.0 million, or 31%, from the Prior Year Period. This increase is the result of executing our growth strategy. This has resulted in substantial increases in employees and related cost. Our staffing requirements increased 39% to 59 employees for the Current Period compared to 52 employees in the Prior Year Period which excludes 29 employees from the Bach acquisition.

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

The Company follows the full cost method of accounting under which all costs associated with property acquisition, exploration, and development activities are capitalized. We capitalized certain internal costs that can be directly identified with our acquisition, exploration, and development activities and do not include any costs related to production, general corporate overhead, or similar activities. We capitalized $0.8 million of payroll and benefit costs for the Current Period compared to $1.0 million in the Prior Year Period.

Oil and Natural Gas Depletion, Depreciation and Amortization (“DD&A”). DD&A of oil and natural gas properties was $1.5 million and $2.0 million during the Current Period and the Prior Year Period, respectively. DD&A is a function of capitalized costs in the full cost pool and related underlying reserves in the periods presented. This decrease is the result of a change in estimate of DD&A from proven developed reserves to total proven reserves and the underlying reserves increasing by 89 bcfe as of December 31, 2006. The average DD&A cost per mcfe was $1.02 and $1.55 in the Current Period and the Prior Year Period, respectively.

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

Interest Expense. Interest expense was $2.1 million in the Current Period compared to $3.6 million in the Prior Year Period. This decrease is the result of a change in estimating capitalized interest and reduction in borrowing under the senior secured credit facility. During the fourth quarter 2006, the Company modified its approach to estimating capitalized interest by recognizing that debt need not be specific debt incurred on a specific asset.

30

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

Year Ended December 31, 2006, compared with Year Ended December 31, 2005

General. For the year ended December 31, 2006, the Company had a net loss of $1.9 million, or $(0.02) per diluted common share, on total revenues of $23.1 million. This compares to a net loss of $0.5 million, or $(0.01) per diluted common share, on total revenue of $7.4 million during the year ended December 31, 2005. The $15.7 million increase in revenue represents our initial steps as an early stage developer of oil and natural gas properties.

Oil and Natural Gas Sales. During 2006, oil and natural gas sales were $21.6 million compared to $6.7 million in the 2005. The Company produced 2,653,427 mcfe at a weighted average price of $8.14 compared to 751,039 mcfe at a weighted average price of $8.98. This increase in production was due to new wells placed on-line, acquisition of additional working interest in the Hudson properties and the producing assets from the Cadence reverse merger. We had 213 net wells producing as of December 31, 2006 as compared to 123 net wells producing as of December 31, 2005. The weighted average price included $2.7 million of realized gains from the gas derivative contract entered into 2006. Production from the Antrim shale play represented approximately 88% of our oil and natural gas revenue for the 2006.

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

	Year Ended December 31, 2006				Year Ended December 31, 2005
Play/Trend	(mcfe)		Amount		(mcfe)		Amount
Antrim		2,353,691	$	18,948,300		649,660	$	6,139,670
New Albany		28,517		190,079		11,079		94,620
Other		271,219		2,453,432		90,300		509,154
Total		2,653,427	$	21,591,811		751,039	$	6,743,444

Other Revenues. Other revenues increased by $0.9 million, or 129% to $1.5 million in 2006 from $0.7 million in 2005. This increase is attributed to two acquisitions in 2006. The first acquisition is the Hudson gas properties with pipeline business component and the second acquisition is Bach which provides oil and natural gas field services.

Production Taxes. Production taxes were $0.9 million in 2006 compared to $0.5 million in 2005. This increase is attributed to new wells being added and production growth of existing wells. On a unit of production basis, production taxes were $0.33 per mcfe in 2006 compared to $0.67 per mcfe in 2005.

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

Production and lease operating expenses were $6.3 million in 2006 compared to $1.6 million in 2005. On a unit of production basis, production and lease operating expenses were $2.37 per mcfe in 2006 compared to $2.11 per mcfe in 2005. The increase in 2006 was primarily attributable to higher energy costs, higher pumping costs, repair and maintenance associated with compressors and pumps, and road and location maintenance. On a component basis, post-production expenses were $1.5 million, or $0.55 per mcfe in 2006 compared to $0.4 million or $0.50 per mcfe in 2005 and lease operating expenses were $4.8 million, or $1.82 per mcfe in 2006 compared to $1.2 million, or $1.62 per mcfe in 2005.

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Production and lease operating expenses for operated properties were $2.22 per mcfe in 2006 compared to $1.53 per mcfe in 2005. Non-operated production and lease operating expenses were $2.77 per mcfe in 2006 compared to $2.36 in 2005.

Pipeline Operating Expense and Field Services Expenses. Pipeline operating expenses were $0.6 million in 2006 compared to no expense in 2005 which are attributable to the Hudson acquisition. Field services expenses were $0.1 million in 2006 compared to no expense in 2005 which are attributable to the Bach acquisition.

General and Administrative Expenses. Our general and administrative expenses include officer and employee compensation, travel, audit, tax and legal fees, office supplies, utilities, insurance, consulting fees and office related expense. General and administrative expenses in 2006 increased by $4.1 million, or 119%, from 2005. This increase is the result of executing our growth strategy as well as costs of becoming and maintaining a public entity. This has resulted in substantial increases in employees and related costs, legal and accounting services related to SEC filings as well as increased consulting services. General and administrative expenses in 2005 primarily reflected Aurora as a private entity.

Payroll and related costs increased by $2.1 million to $4.6 million in 2006. This included stock-based compensation of $2.2 million in 2006 which consists of $0.8 million for directors, $0.8 for senior management and $0.6 for employees. Fiscal year 2005 did not have any stock-based compensation. We incurred $1.8 million in 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 Company follows the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We capitalized certain internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. During the year ended December 31, 2006, we capitalized $1.4 million of payroll and benefit costs to oil and natural gas properties.

Oil and Natural Gas Depletion, Depreciation and Amortization (“DD&A”). DD&A of oil and natural gas properties was $2.7 million and $0.8 million during 2006 and 2005, respectively. DD&A is a function of capitalized costs in the full cost pool and related underlying reserves in the periods presented. This increase is the result of $81.5 million being added to proved properties in the full cost pool, production growth, and the underlying reserves increasing by 89 bcfe. The average DD&A cost per mcfe was $1.01 and $1.02 in 2006 and 2005, respectively

Other Assets Depreciation and Amortization (“D&A”). D&A of other assets was $2.1 million in 2006, compared to $0.3 million in 2005. This increase was primarily the result of intangible assets amortization of $1.5 million connected with the Cadence merger, pipeline depreciation of $0.3 million related to the 2006 Hudson pipeline acquisition and $0.3 million depreciation related to other property and equipment.

Interest Expense. Interest expense was $4.6 million in 2006, compared to $1.3 million in 2005. This increase is due to higher utilization of debt to continue our growth strategy of acquiring and developing operating interests in the Antrim shale and the New Albany shale.

Taxes, Other. Tax expense was $0.3 million in 2006, compared to $29,651 in 2005. This increase represents state taxes on Texas and Louisiana properties, as well as real and personal property taxes in Michigan.

LIQUIDITY AND CAPITAL RESOURCES

We expect to fund our growth using a combination of existing and anticipated debt capacity, sale of non-core assets, existing cash balances, and internally generated cash flows from sales of natural gas production. Our revised 2007 capital budget for drilling and related well work and infrastructure is estimated to be approximately $52.9 million with anticipated participation in 162 (111 net) wells. We may be required to adjust our capital expenditures if the anticipated debt financing is not obtained and we are not able to complete sales of non-core assets. Future cash flows are subject to a number of variables, including the level of production, natural gas prices and successful drilling efforts. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures.

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

Interest under the Term Loan is payable at rates based on the London Interbank Offered Rate plus 700 basis points with a step-down of 25 basis points once the Company’s ratio of total indebtedness to earnings before interest, taxes, depreciation, depletion, amortization, and other noncash charges is lower than or equal to a ratio of 4.0 to 1.0 on a trailing four quarters basis. The Company has the ability to prepay the Term Loan during the first year at a price equal to 103% of par, during the second year at a price equal to 102% of par, and thereafter at a price equal to 100% of par.

The loan contains, among other things, a number of financial and non-financial covenants relating to restricted payments (as defined), loans or advances to others, additional indebtedness, incurrence of liens, geographic limitations on operations to the United States, and maintenance of certain financial and operating ratios, including (i) maintenance of a minimum current ratio, (ii) maintenance of a minimum interest coverage ratio, (iii) maintenance of a maximum of indebtedness to earnings before interest, income taxes, depreciation, depletion and amortization and non-cash expenses, and (iv) maintenance of minimum reserve value to indebtedness.

In connection with the Term Loan, the Company also agreed to the amendment and restatement of its senior secured credit facility with BNP and other lenders, pursuant to which the borrowing base under the senior secured credit facility was increased from the current authorized borrowing base of $50 million to $70 million.

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

Upon execution of the Term Loan, the Company also entered into a 3-year interest rate swap transaction with BNP to hedge its exposure to the floating interest rate on the Term Loan debt. This hedge transaction on $50 million will yield an effective interest rate of 11.86% for the period from August 23, 2007 through August 23, 2010.

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

The senior secured credit facility contains, among other things, a number of financial and non-financial covenants relating to restricted payments (as defined), loans or advances to others, additional indebtedness, incurrence of liens, geographic limitations on operations to the United States, and maintenance of certain financial and operating ratios, including (i) maintenance of a minimum current ratio, (ii) maintenance of a minimum interest coverage ratio, (iii) maintenance of a maximum of indebtedness to earnings before interest, income taxes, depreciation, depletion and amortization and non-cash expenses, and (iv) maintenance of minimum reserve value to indebtedness. As of June 30, 2007, we were in compliance with all of the applicable covenants.

Effective August 20, 2007, the Company’s subsidiary Aurora Antrim North, L.L.C. (“North”) terminated its Amended Note Purchase Agreement with TCW which provided $50 million in mezzanine financing. As of the effective date, North had outstanding borrowing of $40 million. TCW had limited the borrowing base and the agreement contained a commitment expiration date of August 12, 2007. Under the termination provisions, the Company was required to pay certain fees and prepayment charges associated with early termination. The following represents the expenditures paid to TCW: (i) $40 million payment of principal; (ii) $0.7 million payment of interest expense from June 27, 2007, through August 20, 2007; (iii) $0.35 million payment of interest make-whole provision from August 21, 2007, through September 27, 2007; (iv) $1.25 million payment of prepayment premium; and (v) $0.2 million payment for a make-whole provision on principal greater than $30 million.

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

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

Our total capitalization was as follows:

	As of June 30, 2007		As of December 31, 2006		As of December 31, 2005
Short-term bank borrowings	$	1,418,615	$	542,788	$	6,210,000
Obligations under capital lease		11,545		17,096		11,085
Related party notes payable		264,170		280,321		69,833
Mortgage payable		3,128,741		3,175,298		2,865,477
Mezzanine financing		40,000,000		40,000,000		40,000,000
Senior secured credit facility		35,000,000		10,000,000		—
Total debt		79,823,071		54,015,503		49,156,395
Redeemable convertible preferred stock						59,925
Shareholders’ equity		138,005,484		139,731,099		56,625,927
Total capitalization	$	217,828,555	$	193,746,602	$	105,842,247

CASH FLOWS

Operating activities

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

Cash provided by operating activities was $2.2 million in 2006, compared to cash used of $2.4 million in 2005. This $4.6 million increase in net cash provided by operating activities was substantially due to a 220% increase in production revenues. See “Results of Operations” for discussion of changes in revenues and expenses. Non-cash charges increased due to higher depreciation, depletion and amortization as well as recognition of stock-based compensation in 2006. Changes in current operating assets and liabilities decreased cash flow from operations by $4.0 million.

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Investing activities

The following table describes our significant investing transactions that we completed in the periods set forth below:

	Six Months Ended June 30,						Year Ended December 31,
	2007			2006			2006			2005
Acquisitions of leaseholds
Antrim	$	915,684		$	4,496,399		$	7,138,014		$	5,747,079
New Albany		1,250,111			13,485,397			16,143,356			8,488,834
Other		3,449,129			1,232,308			3,556,327			4,047,089
Drilling and development of oil and natural gas properties
Antrim		14,571,159			10,337,497			22,088,181			22,127,354
New Albany		3,988,899			307,421			3,050,097			9,422
Other		908,678			2,784,404			2,561,400			321,416
Infrastructure properties
Antrim		6,321,732			6,334,665			12,035,440			6,523,298
New Albany		276,234			-			1,934,415			105,770
Other		10,288			18,785			378,566			-
Acquisitions of oil and natural gas properties		-			23,967,283			24,011,335			-
Acquisitions/additions to pipeline, property and equipment		356,288			3,787,922			4,111,780			4,523,706
Additions to other property and equipment		2,653,132			1,749,057			855,070			485,741
Subtotal of capital expenditures		34,701,334			68,501,138			97,863,981			52,379,709
Sale of oil and natural gas properties		(1,024,663	)		(6,990,681	)		(11,489,456	)		(11,504,428	)
Other, net		(1,659,762	)		(13,096	)		(56,788	)		(36,314	)
Net cash acquired in merger		-			-			-			(957,020	)
Subtotal of capital divestitures		(2,684,425	)		(7,003,777	)		(11,546,244	)		(12,497,762	)
Total	$	32,016,909		$	61,497,361		$	86,317,737		$	39,881,947

Financing activities

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

Cash flows provided by financing activities in the Prior Year Period included: (1) $40.0 million of senior secured credit borrowing; (2) $18.1 million of net proceeds received from exercise of common stock options and warrants; and (3) $0.8 million in short-term borrowings. Cash flows used by financing in the Prior Year Period included: (1) net pay-down of $7.0 million within short-term bank borrowings; (2) payments of $2.4 million in financing fees; and (3) pay-down of $0.1 million within mortgage obligations and other.

Cash flows provided by financing activities were $73.8 million in 2006 compared to $49.1 million in 2005. Cash flows provided in 2006 included: 1) $60.0 million of senior secured credit borrowing, of which, $27.6 million was paid directly for the Hudson acquisition; 2) $54.5 million of proceeds from public equity offering; and 3) $17.6 million of net proceeds received from exercise of common stock options and warrants and rescission of certain officer exercised stock options. Cash flows used in 2006 included: 1) net pay-down of $5.8 in short-term bank borrowings; 2) $50.0 million pay-down of the senior secured credit facility; 3) pay-down of $0.1 million in mortgage obligations; and 4) payment of $2.5 million in financing fees.

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Cash flows provided by financing activities in 2005 included: 1) $14.7 million of proceeds received from sales of common stock; 2) $30.0 million of mezzanine borrowing; 3) $2.9 million of mortgage obligation to purchase office space; and 4) $5.8 million of net short-term bank borrowings. Cash flows used by financing in 2005 included: 1) pay-off of $2.9 million of certain related-party notes; 2) distributions of $0.8 million to minority interest members for their proportionate share of the El Paso sale proceeds; and 3) pay-down of $0.5 million in financing fees.

RECENT ACCOUNTING PRONOUNCEMENTS

The following is a summary of recent accounting pronouncements issued in 2007. 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.

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

CRITICAL ACCOUNTING POLICIES

Our consolidated 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 consolidated 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 below.

Use of Estimates

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

Oil and Gas Properties

The Company utilizes the full cost method of accounting for oil and natural gas properties. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration, and development activities of oil and natural gas, including costs of unsuccessful exploration and overhead charges directly related to acquisition, exploration, and development activities, are capitalized. The Company is currently participating in oil and natural gas exploration and development projects in the Antrim shale of Michigan and the New Albany shale of southern Indiana and western Kentucky. Thus, all capitalized costs of oil and natural gas properties considered proven, are amortized on the unit-of-production method using estimates of proven reserves. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and natural gas properties unless the sale represents a significant portion of oil and natural gas properties and the gain or loss significantly alters the relationship between capitalized costs and proven reserves.

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Capitalized costs of oil and natural gas properties may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proven reserves plus the lower of cost or fair value of unproven properties. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net cash flows is computed by applying year-end prices of oil and natural gas to estimated future production of proved oil and natural gas reserves as of year end less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.

Oil and Gas Reserves

Our estimates of oil and natural gas reserves, by necessity, are projections based on geological and engineering data, and there are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance and excise taxes, development costs, and workover and remedial costs, all of which may, in fact, vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected from there may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and natural gas properties and/or the rate of depletion of the oil and natural gas properties. Actual production, revenues, and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Many factors will affect actual net cash flows, including the following: the amount and timing of actual production; supply and demand for natural gas; curtailments or increases in consumption by natural gas purchasers; and changes in governmental regulations or taxation.

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 year ended December 31, 2006, the Company recorded stock-based compensation of $2,663,814 under the 2006 Stock Incentive Plan and 1997 Stock Option Plan, as well as a certain employment agreement. Of that amount, $2,206,801 has been included in general and administrative expense on the consolidated statement of operations and $457,013 has been capitalized in oil and natural gas properties. The impact on future net income is estimated to be $3,411,000 recognized over the applicable requisite service period of approximately 3 years.

Income Taxes

The Company has adopted the provisions of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (“SFAS No. 109”). Under the asset and liability method of SFAS No. 109, deferred tax assets and liabilities are recognized for future tax consequences attributable to the differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted income tax rates to apply to taxable income in the years in which those differences are expected to be recovered or settled. Under SFAS No. 109, the effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. At December 31, 2006, the Company had approximately $34.3 million of net operating loss carryforwards which expire between 2010 and 2026.

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SIGNIFICANT ACCOUNTING PRINCIPLES RELATING TO THE MERGER

As a result of the reverse merger, we were required to conform certain of Cadence’s accounting principles to the accounting principles used by Aurora prior to the merger. This was required because Aurora was considered to be the accounting acquirer. Our financial statements for the year ended December 31, 2005 were prepared using these accounting principles. A summary of these accounting principles is as follows:

· Aurora is treated as the acquirer in the merger for accounting purposes, and accordingly, reverse acquisition accounting is applied to the business combination.

· We measured the cost of the business acquired in the merger by reference to the fair value of the target’s securities (i.e., shares of Cadence common stock, including outstanding options and warrants to purchase such shares) at the date of the merger agreement, January 31, 2005. The fair value was determined to be approximately $41,500,000.

· We uniformly apply the full cost method to all of our oil and natural gas operations. Accordingly, the consolidated financial statements include a net upward adjustment to the Cadence assets in the amount of $774,912 to capitalized costs previously expensed by Cadence under the successful efforts method. This increased capitalized costs was used to recalculate depreciation on the new asset base.

· In accounting for stock-based compensation for the year ended December 31, 2005, we continued to use the intrinsic value method under APB Opinion 25. For the year ending December 31, 2006, we will use FAS No. 123(R). Aurora stock options outstanding as of the date of the merger are not accounted for under APB Opinion 25 or FAS 123 because these options were fully vested at the time of the merger. Their fair value was included in the cost of the business acquired, as discussed above.

OFF BALANCE SHEET ARRANGEMENTS

We have no special purpose entities, financing partnerships, guarantees, or off-balance sheet arrangements other than the outstanding letter of credits totaling $1.1 million discussed in Note 9 “Commitments and Contingencies” of our unaudited condensed consolidated financial statements for the six months ended June 30, 2007, and 2006.

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BUSINESS

GENERAL

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.

Our strategy is to maximize shareholder value by leveraging our significant acreage position and the experience of our management and technical teams in finding and developing natural gas reserves to profitably grow our reserves and production. Over the last several years we have focused primarily on the acquisition of properties in the Antrim and New Albany shale. As an early stage developer of properties, we anticipate reserve growth will be our initial focus followed by a more traditional balance between reserve and production growth.

OPERATING AREAS

Antrim shale

Our Antrim shale properties are located in Michigan and represent our primary area of development over the next 12 months. Nearly all of our development operations in this play/trend are focused on unconventional shale plays. Shale development typically results in higher drilling success and lower drilling costs when compared to conventional exploration and development activity.

Antrim shale underlies the entire Michigan basin. The shale is very thick (140 to over 200 feet) and has a high percentage of organic content (up to 20%). Due to the makeup of the natural fractures in the Antrim shale, production will vary from well to well.

The productive, fractured trend for the Antrim shale runs across the northern portion of the Michigan basin from Lake Huron to Lake Michigan (160 miles). Gas wells have been drilled and produced in the Antrim shale from depths of 250 feet down to 1,500 feet below the surface. A high percentage of the wells drilled in the Antrim shale have been put into production and levels of production vary from well to well. Over 9,000 wells are currently producing in the Antrim shale. In recent years, 200 to 400 wells have been drilled annually by all operators in the Antrim shale.

The gas produced from the Antrim shale is primarily a biogenic gas due to the presence of microbes in the low to medium saline waters. The low-density pay zones in the Antrim shale are over 100 feet thick. Methane gas is continuously being generated by anaerobic bacteria that feed on C02 organic material, and the heavier oil and gases stored in the shale.

The Antrim shale gas adsorbs to organic material in a manner similar to gas in coal seams. Water in the natural fractures of the shale provides a trapping mechanism to hold the gas in place. As the water is produced, lowering the fluid and pressure in the reservoir, gases are released from the organic material and are produced to the surface. At depths of less than 1,500 feet, the gas-in-place is typically 90% methane or greater, with the balance being C02 and some heavier gases.

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The oldest Antrim shale gas field was drilled in the 1940s, and it is still in production today. The production curve for the shale typically contains a peak rate of gas occurring after the first two years of production when the shale reservoir has been thoroughly dewatered. Peak rate production usually continues for some time. After the water is taken from the formation and the gas is able to fully release from the shale into the well bore, the rate of production will typically begin to decline 2% to 7% per year.

We have identified the Michigan Antrim shale as an area with natural fractures using a variety of diagnostic tests, including a review of production trends, fracture imaging logs and geological mapping. In management's opinion, based upon performance information from over 9,000 wells with comparable geologic characteristics, areas with natural fractures in shale have compelling production potential.

At June 30, 2007, we owned working interests in 528 (270 net) Antrim wells. For the six months ended June 30, 2007, we drilled or participated in 29 (13 net) wells with a 92% success rate. In 2006, we drilled 173 (98 net) Antrim wells and successfully completed 164 gross wells for a success rate of 95%. On average, our Antrim wells are drilled to depths ranging from 250 to 1,500 feet targeting reserves of 0.513 bcfe per well based upon to our December 31, 2006, Schlumberger reserve report.

New Albany shale

Our New Albany shale properties are located in Southern Indiana and Western Kentucky and represent a relatively new area of activity for us. Most of our exploratory and developmental operations in the Illinois geological basin are focused on unconventional shale plays. The New Albany shale play, much of which is located in Indiana, is an emerging play with similar characteristics to the Antrim shale play. It is also very thick (100 to over 200 feet) and covers approximately 6,000,000 gross acres, with proven producing pay zones throughout. The shale is capped by the Borden shale, a very thick, dense, gray-green shale.

In the New Albany shale, a well commonly produces water along with the gas. In the early 1900's, it was learned that a simple open-hole completion in the very top of the shale would yield commercial gas wells that would last for many years, even while producing some water. Vertical fractures in the shale feed the gas flow at the top of the shale. The potential of these wells was seldom realized in the early to mid-twentieth century, as the production systems for handling the associated water were limited. However, with current technology, the water can be dealt with cost effectively and allow for better rates of gas production.

Significant research and study has been conducted to evaluate the producibility of the New Albany shale. In cooperation with the Gas Research Institute, we combined resources and data with 11 other industry partners in a shale gas producibility consortium lasting almost two years (concluded in 1999). The consortium identified critical differences and similarities of the New Albany shale play to other shale plays. The consortium study observed that the New Albany shale reservoir contained high-angled (vertical or nearly so) natural fractures that are open to unimpeded flow. The predominant fracture system is oriented east-west with spacing between joints estimated to average five feet based on outcrop studies and production simulations. Based on this information, it was concluded that increases in performance could be achieved with a horizontally drilled well compared to a vertically drilled well in the same reservoir.

Reserve studies were conducted on behalf of the consortium by Schlumberger Holditch & Associates for both vertical producing wells and horizontal wells. Since then, we have participated in approximately 30 pilot horizontal well drilling projects across multiple counties which support the conclusions of the consortium. With the data from these pilot wells, we have established a development concept for the New Albany shale, which we began to implement in 2006.

Our New Albany shale projects are characterized by declining natural gas and water production with peak natural gas and water flow rates occurring in the first 60 days. Our New Albany shale wells are drilled to depths ranging from 500 to 3,000 feet and based on our December 31, 2006, Schlumberger reserve report could yield an average reserve of 1.2 bcfe per well. At June 30, 2007, we owned working interests in 50 (11.61 net) New Albany shale wells. For the six months ended June 30, 2007, we drilled or participated in 16 (4.05 net) wells with a 100% success rate. In 2006, we drilled 26 (7.49 net) New Albany shale wells and successfully completed 25 of these wells for a success rate of 96%.

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Drilling techniques and natural gas processing

We are experienced at drilling both vertical and horizontal wells. In the Antrim, our first choice would typically be vertical drilling, although in some situations, we may determine that horizontal drilling is preferred. Our drilling technique in the New Albany shale continues to evolve as we seek to improve cost containment and producibility. Horizontal drilling has become our development method of first choice in the New Albany shale, primarily because of the high angled natural fractures. We seek to maximize intersections of the east-west natural fractures through horizontal drilling, as we believe that this will optimize production results. Directional drilling with enhanced shale technology fracturing helps test New Albany exploration areas for development potential.

For shale gas wells, we generally use a production system that is designed to achieve low pressure on the wells, pipelines, facilities and reservoir. This is done by keeping natural fractures open to the well bore and by using low-pressure gas processing near well sites. Using this low-pressure production approach, we seek to increase the recoverability of shale gas production through lower down-hole reservoir pressure enhancing dewatering and gas recovery.

In the Michigan Antrim, we use a simple proven completion procedure with industry proven hydraulic fracturing technology. This procedure involves drilling through several pay zones, setting and cementing casing, and drilling extended rat-hole, which is used for gas-water separation. The wells are then hydraulically fractured with a specifically designed fracture procedures incorporating multiple stages with enhanced diversion methods to increase effective vertical coverage. Imaging logs are used to identify which zones are best fractured and will yield commercial gas production. For horizontal New Albany shale wells, no stimulation has been required to date to make economic gas wells. In exploratory areas of the New Albany and Antrim, shale log analysis is incorporated to enhance fracturing and completion design.

In order to contain costs, we try to keep facilities for gas processing decentralized. Salt water disposal wells are drilled close to the compression facilities, near to each field's wells. Skid mounted separators that can be easily upgraded or downsized are used at the site of the salt water disposal wells. The localized disposal of water reduces power demand. Different reservoirs contain different amounts of water. We cannot accurately predict the actual amount of time required for dewatering with respect to each well. The period of time during which the gas production rate is limited by the dewatering process could be as much as two years, thereby delaying peak revenue production.

We use skid mounted compressors in a series to maximize compression efficiencies from the well to the transportation line. We also seek to maintain low pressure in the gathering systems. Gas is usually drawn at low wellhead pressure using a five and one-half inch or seven inch production casing and up to 12-inch polypipe.

One strategy we use to minimize costs is to minimize the use of land surface. This is accomplished by using small well sites in open areas near roads, and by not building central processing facilities, but instead using localized facilities as described above. We continue to explore innovations in technology and methodologies that will reduce production costs and increase efficiencies. We may use other drilling, completion and operating procedures than those described above if, in our opinion, alternative procedures will generate higher returns.

Our wells are drilled by outside drilling companies. We believe that there is currently enough capacity available in the areas in which we are working that we will not have a problem finding one or more drilling companies available to meet our time schedule for drilling wells. However, over time, circumstances could change as development activity in the industry accelerates.

Oil and natural gas reserves

The following table presents information as of December 31, 2006 with respect to our estimated proved reserves. Estimates of our future net revenues from proved reserves are discounted to present value using an annual discount rate of 10% (PV-10), using oil and natural gas prices in effect as of the dates of such estimates, held constant throughout the life of the properties. The information presented is based on a reserve report prepared by Data & Consulting Services Division of Schlumberger Technology Corporation ("Schlumberger"). According to this report, approximately 46% of our proved reserves are classified as either proved developed non-producing or proved undeveloped.

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	As of December 31, 2006
Oil and Natural Gas Reserves(a)	Oil		Gas		Total		PV-10(d)		Standardized Measure(e)
	(mbbls)		(mmcf)		(mmcfe)		(In thousands)		(In thousands)
Proved developed producing		54		82,580		82,904	$	97,553	$	76,952
Proved developed non-producing		-		22,693		22,693		28,428		19,238
Proved undeveloped		27		47,691		47,853		32,802		34,272
Total proved (b) (c)		81		152,964		153,450	$	158,783	$	130,462

Oil and Natural Gas Reserves by Play/Trend(a)	Total		Percent of Proved Reserves			PV-10
	(mmcfe)					(In thousands)
Antrim		150,107		98	%	$	152,427
New Albany		2,298		1	%		2,977
Other		1,045		1	%		3,379
Total		153,450		100	%	$	158,783

Change in reserve quantity information for the year ended December 31, 2006(a)	Oil			Gas			Total
	(mbbls)			(mmcf)			(mmcfe)
Proved reserves as of December 31, 2005		99			63,322			63,916
Revisions of previous estimates		(40	)		4,880			4,640
Purchases of minerals in place		-			22,843			22,843
Extensions and discoveries		45			65,095			65,365
Production		(23	)		(2,511	)		(2,649	)
Sales of minerals in place		-			(665	)		(665	)
Proved reserves as of December 31, 2006		81			152,964			153,450

(a) The information presented for reserves is based on reserve reports prepared by Schlumberger. Consistent with Schlumberger's standard engineering practices, these reports and such reserves excluded the impact of financial hedges.

(b) Proved reserves are those quantities of gas which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable from known reservoirs and under current economic conditions, operating methods, and government regulations.

(c) Developed reserves are expected to be recovered from existing wells. Undeveloped reserves are expected to be recovered: (i) from new wells on undrilled acreage; (ii) from deepening existing wells to a different reservoir; or (iii) where relatively large expenditure is required to recomplete an existing well or install production or transportation facilities for primary or improved recovery projects.

(d) Represents the present value, discounted at 10% per annum (PV-10), of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net revenues were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on economic conditions prevailing at December 31, 2006. The estimated future production is priced at December 31, 2006, without escalation, using $57.81 per bbl and $5.84 per mmbtu, in each case adjusted by lease for transportation fees and regional price differentials. PV-10 is a non-GAAP financial measure because it excludes income tax effects. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of PV-10 to the most directly comparable GAAP measure - standardized measure of discounted future net cash flow - in the following table:

	As of December 31,
	2006		2005
Standardized measure of discounted future net cash flows	$	130,461,821	$	152,868,240
Add: Present value of future income tax discounted at 10%		28,320,989		46,639,204
PV-10	$	158,782,810	$	199,507,444

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(e) The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes. As noted in footnote (a) above, this excludes the impact of our hedges.

Management uses future net revenue, which is calculated without deducting estimated future income tax expense, and the present value thereof as one measure of the value of our current proved reserves and to compare relative values among peer companies without regard to income taxes. We also understand that securities analysts use this measure in similar ways.

Acreage

The following table sets forth as of June 30, 2007, the gross and net acres of both developed and undeveloped oil and gas leases which we hold. "Gross" acres are the total number of acres in which we own a working interest. "Net" acres refer to gross acres multiplied by our fractional working interest. Acreage numbers do not include our options to acquire additional leaseholds which have not been exercised.

	Developed(a)				Undeveloped(b)				Total
Play/Trend	Gross		Net		Gross		Net		Gross		Net
Antrim		82,278		43,824		211,572		112,693		293,850		156,517
New Albany		10,560		3,133		876,581		452,927		887,141		456,060
Other		1,313		1,062		130,027		105,060		131,340		106,122
Total		94,151		48,019		1,218,180		670,680		1,312,331		718,699

(a) Developed refers to the number of acres which are allocated or assignable to producing wells or wells capable of production. Developed acreage includes acreage having wells shut-in awaiting the addition of infrastructure.

(b) Undeveloped refers to lease acreage on which wells have not been developed or completed to a point that would permit the production of commercial quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

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Production and price information

The following table summarize sales volumes, sales prices, and production cost information for the periods indicated:

	Six Months Ended June 30,		Year Ended December 31,
	2007		2006		2005
Production
Oil (bbls)		13,772		22,588		10,628
Natural gas (mcf)		1,410,820		2,517,897		687,271
Natural gas equivalent (mcfe)		1,493,453		2,653,427		751,039
Oil and natural gas sales
Oil sales	$	784,991	$	1,399,445	$	558,455
Natural gas sales		11,747,014		20,192,366		6,184,989
Total	$	12,532,005	$	21,591,811	$	6,743,444
Average sales price (including realized gains or losses from hedging)
Oil ($ per bbl)	$	57.00	$	61.95	$	52.54
Natural gas ($ per mcf)		8.33		8.02		9.00
Natural gas equivalent ($ per mcfe)		8.39		8.14		8.98
Average production expenses ($ per mcfe)
Production taxes	$	0.38	$	0.33	$	0.67
Post-production expenses		0.54		0.55		0.50
Leasing operating expenses		2.23		1.82		1.62
Total	$	3.15	$	2.70	$	2.79

Productive wells

The following table sets forth as of June 30, 2007, information relating to the productive wells in which we owned a working interest. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of productive wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

	Natural Gas				Oil
Play/Trend	Gross Wells		Net Wells		Gross Wells		Net Wells
Antrim		528		270.34		-		-
New Albany		50		11.61		-		-
Other		9		7.24		29		13.97
Total		587		289.19		29		13.97

Drilling activities

The following table sets forth information with respect to wells drilled and completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

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	Gross Wells						Net Wells
Type of Well	Productive(b)		Dry(c)		Total		Productive(b)			Dry(c)		Total
Six Months Ended 06/30/07
Exploratory(a)
Antrim		-		-		-		-			-		-
New Albany		7		-		7		3.60			-		3.60
Other		7		4		11		6.48			3.10		9.58
Total		14		4		18		10.08			3.10		13.18
Development(a)
Antrim		28		1		29		11.94			1.00		12.94
New Albany		9		-		9		0.45			-		0.45
Other		2		-		2		1.45			-		1.45
Total		39		1		40		13.84	��		1.00		14.84
Year Ended 12/31/06
Exploratory(a)
Antrim		2		-		2		2.00			-		2.00
New Albany		13		1		14		6.39			0.50		6.89
Other		1		3		4		0.38			1.25		1.63
Total		16		4		20		8.77			1.75		10.52
Development(a)
Antrim		162		9		171		91.53			4.93		96.46
New Albany		12		-		12		0.60			-		0.60
Other		6		-		6		3.95			-		3.95
Total		180		9		189		96.08			4.93		101.01
Year Ended 12/31/05
Exploratory(a)
Antrim		1		1		2		0.20			0.20		0.40
New Albany		-		-		-		-			-		-
Other		3		-		3		1.17			-		1.17
Total		4		1		5		1.37			0.20		1.57
Development(a)
Antrim		136		5		141		101.37			3.40		104.77
New Albany		3		-		3		0.15			-		0.15
Other		-		-		-		-			-		-
Total		139		5		144		101.52			3.40		104.92

(a) An exploratory well is a well drilled either in search of a new, as yet undiscovered, oil or natural gas reservoir or to greatly extend the known limits of a previously discovered reservoir. A development well is a well drilled within the presently proved productive area of an oil or natural gas reservoir, as indicated by reasonable interpretation of available data, with the objective of being completed in that reservoir.

(b) 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.

(c) A dry well is an exploratory or development well that is not a producing well or a well that has either been plugged or has been converted to another use.

Sale of production

We use different strategies for gas sales depending on the location of the field and the local markets. In some locations, we may use proprietary C0₂ reduction units to process our own gas and sell it to nearby local markets. In other cases, we connect to nearby high pressure transmission pipelines. We are not currently aware of any restraints with respect to pipeline availability other than curtailments in existing pipelines that may occur from time to time due to technical difficulties. However, because of the nature of natural gas development, there may be periods of time when pipeline capacity is inadequate to meet our transportation needs. It is often the case that as new development comes on-line, pipelines are near or at capacity before new pipelines are built.

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We entered into a firm delivery gas contract to be effective for the period June 1, 2007, through December 31, 2008, for the delivery of 5,000 mmbtu per day. The contract covers much of our existing Antrim production operated by us.

We also have five other base contracts for the sale of natural gas. We set our firm delivery volume obligation under these contracts on a monthly basis, with the amount of our obligation varying from month to month. As we bring new wells on-line and our production volume increases, we will sell the new production in the spot markets or under the monthly base contracts. We expect that we will usually sell in this fashion, partly through firm gas delivery contracts and partly in the spot markets.

Prices for oil and natural gas fluctuate fairly widely based on supply and demand. Supply and demand are influenced by weather, foreign policy and industry practices. Nonetheless, in light of historical fluctuations in prices, there can be no assurance at what price we will be able to sell our oil and natural gas. It is possible that prices will be low at the time periods in which the wells are most productive, thereby reducing overall returns.

Hedging

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 swap transaction in order to hedge a portion of our production. The purpose of the swap is to provide a measure of stability to our cash flow in meeting financial obligations while operating in a volatile gas market environment. The swap reduces our exposure on the hedged volumes to decreases in commodity prices and limits the benefit we might otherwise receive from any increases in commodity prices on the hedged volumes.

Other properties

On October 4, 2005, we purchased office space in the Copper Ridge Professional Center Five, located in Traverse City, Michigan. Our unit contains approximately 14,645 square feet on the second floor of a three story building, plus common areas and 15 covered parking spaces. We moved our corporate offices into this space on December 5, 2005.

We also own non-oil and natural gas mineral rights in a number of properties, although we do not presently consider them to be material to our business.

Employees

As of September 30, 2007, we had 79 full-time employees and 2 part-time employees. We are not a party to any collective bargaining agreements. We believe that our relations with our employees are good.

Competition and markets

We face competition from other oil and natural gas companies in all aspects of our business, including acquisition of producing properties and oil and natural gas leases, marketing of oil and natural gas, and obtaining goods, services and labor. Many of our competitors have substantially larger financial and other resources than we have. Factors that affect our ability to acquire producing properties include available funds, available information about prospective properties and our limited number of employees. Gathering systems are the only practical method for the intermediate transportation of natural gas. Therefore, competition for natural gas delivery is presented by other pipelines and gas gathering systems. Competition is also presented by alternative fuel sources, including heating oil and other fossil fuels. Renewable energy sources may become more competitive in the future.

The availability of a ready market for and the price of any hydrocarbons produced will depend on many factors beyond our control including, but not limited to, the amount of domestic production and imports of foreign oil and liquefied natural gas, the marketing of competitive fuels, the proximity and capacity of natural gas pipelines, the availability of transportation and other market facilities, the demand for hydrocarbons, the effect of federal and state regulation of allowable rates of production, taxation, the conduct of drilling operations and federal regulation of natural gas. In addition, the restructuring of the natural gas pipeline industry virtually eliminated the gas purchasing activity of traditional interstate gas transmission pipeline buyers. Producers of natural gas have therefore been required to develop new markets among gas marketing companies, end users of natural gas and local distribution companies. All of these factors, together with economic factors in the marketing arena, generally may affect the supply of and/or demand for oil and natural gas and thus the prices available for sales of oil and natural gas.

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Regulatory considerations

Proposals and proceedings that might affect the oil and gas industry are periodically presented to Congress, the Federal Energy Regulatory Commission ("FERC"), the Minerals Management Service ("MMS"), state legislatures and commissions and the courts. We cannot predict when or whether any such proposals may become effective. The natural gas industry is heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, we currently do not anticipate that compliance with existing federal, state and local laws, rules and regulations, will have a material or significantly adverse effect upon our capital expenditures, earnings or competitive position. No material portion of our business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.

Our operations are subject to various types of regulation at the federal, state and local levels. This regulation includes requiring permits for drilling wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used or generated in connection with operations. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of oil and natural gas properties. In addition, state conservation laws sometimes establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and natural gas we can produce from our wells in a given state and may limit the number of wells or the locations at which we can drill.

Currently, there are no federal, state or local laws that regulate the price for our sales of natural gas, natural gas liquids, crude oil or condensate. However, the rates charged and terms and conditions for the movement of gas in interstate commerce through certain intrastate pipelines and production area hubs are subject to regulation under the Natural Gas Policy Act of 1978, as amended. Pipeline and hub construction activities are, to a limited extent, also subject to regulations under the Natural Gas Act of 1938, as amended. While these controls do not apply directly to us, their effect on natural gas markets can be significant in terms of competition and cost of transportation services, which in turn can have a substantial impact on our profitability and costs of doing business. Additional proposals and proceedings that might affect the natural gas and crude oil extraction industry are considered from time to time by Congress, FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective and their effect, if any, on our operations. We do not believe that we will be affected by any action taken in any materially different respect from other crude oil and natural gas producers, gatherers and marketers with whom we compete.

State regulation of gathering facilities generally includes various safety, environmental and in some circumstances, nondiscriminatory take requirements. This regulation has not generally been applied against producers and gatherers of natural gas to the same extent as processors, although natural gas gathering may receive greater regulatory scrutiny in the future.

Our oil and natural gas production and saltwater disposal operations and our processing, handling and disposal of hazardous materials, such as hydrocarbons and naturally occurring radioactive materials ("NORM") are subject to stringent environmental regulation. Compliance with environmental regulations is generally required as a condition to obtaining drilling permits. State inspectors frequently inspect regulated facilities and review records required to be maintained for document compliance. We could incur significant costs, including cleanup costs resulting from a release of hazardous material, third-party claims for property damage and personal injuries, fines and sanctions, as a result of any violations or liabilities under environmental or other laws. Changes in or more stringent enforcement of environmental laws could also result in additional operating costs and capital expenditures.

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Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and natural gas exploration, development and production operations, and consequently may impact our operations and costs. These regulations include, among others, (i) regulations by the Environmental Protection Agency ("EPA"), and various state agencies regarding approved methods of disposal for certain hazardous and non-hazardous wastes; (ii) the Comprehensive Environmental Response, Compensation and Liability Act, and analogous state laws, which regulate the removal or remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (iii) the Clean Air Act and comparable state and local requirements, which may require certain pollution controls with respect to air emissions from our operations; (iv) the Oil Pollution Act of 1990 which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States; (v) the Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and disposal of hazardous wastes; and (vi) state regulations and statutes governing the handling, treatment, storage and disposal of NORM.

A permit from the EPA and the Michigan Department of Environmental Quality or a state regulatory agency (Indiana) must be obtained before we may drill a salt water disposal well. The amount of time required to obtain such a permit varies from state to state, but can take as much as six or more months in Michigan. Since many gas wells can only be produced if a salt water disposal well is available, the salt water disposal well permit requirement may delay the commencement of production.

In the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks of oil or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Michigan and Texas, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we are able to control directly the operations of only those wells for which we act as the operator. Despite our lack of control over wells owned by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributed to us under applicable state, federal or local laws or regulations.

We believe that we are in substantial compliance with all currently applicable environmental laws and regulations. To date, compliance with such laws and regulations has not required the expenditure of any material amount of money, and we do not currently anticipate that future compliance with environmental laws will have a materially adverse effect on our consolidated financial position or results of operations. Since these laws and regulations are periodically amended, however, we are unable to predict the ultimate cost of compliance. To our knowledge, there are currently no material adverse environmental conditions that exist on any of our properties and there are no current or threatened actions or claims by any local, state or federal agency, or by any private landowner against us pertaining to such a condition. Further, we are not aware of any currently existing condition or circumstance that may give rise to such actions or claims in the future.

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MANAGEMENT

The following table sets forth the name, age, and position of each of our executive officers and directors.

Name	Age	Position(s) with the Company
William W. Deneau	63	Director, Chairman and Chief Executive Officer
Ronald E. Huff	52	Director, President and Chief Financial Officer
John V. Miller, Jr.	49	Vice President, Business and Corporate Development
John C. Hunter	56	Vice President, Exploration and Production
Thomas W. Tucker	65	Vice President, Exploration (retired effective 06/30/07)
Richard M. Deneau	61	Director
Gary J. Myles	62	Director
Wayne G. Schaeffer	61	Director
Kevin D. Stulp	51	Director
Earl V. Young	66	Director

Under the Company’s by-laws, the authorized number of directors is set at no fewer than three and no more than ten directors. The Board of Directors currently has seven members. Each member of the Board of Directors serves for a term of one year that expires at the following annual shareholders’ meeting. Each officer serves at the pleasure of the Board of Directors and until a successor has been qualified and appointed, except that the Company has entered into an employment agreement with Ronald E. Huff to serve as the Chief Financial Officer of the Company through June 18, 2008.

To the best of our knowledge, none of our Directors has been convicted in a criminal proceeding, excluding traffic violations or similar misdemeanors, or has been a party to any judicial or administrative proceeding during the past five years, except for matters that were dismissed without sanction or settlement, that resulted in a judgment, decree, or final order enjoining the person from future violations of, or prohibiting activities subject to, federal or state securities laws, or a finding of any violation of federal or state securities laws.

Set forth below is certain biographical information regarding each of our directors and executive officers:

William W. Deneau has served on our Board of Directors and as Chief Executive Officer and Chairman of the Board of Directors since November 1, 2005. Mr. Deneau also served as President until May 30, 2007. Mr. Deneau became an employee of Aurora at the time he sold his interest in Jet/LaVanway Exploration, L.L.C. to Aurora in exchange for Aurora’s stock on April 22, 1997. Since April 1997, Mr. Deneau has been responsible for managing Aurora’s affairs. He became a Director of Aurora on June 25, 1997, and the President of Aurora on July 17, 1997, positions he continues to hold. William W. Deneau is the brother of Richard M. Deneau, another one of our Directors.

Ronald E. Huff has served as our Chief Financial Officer since June 19, 2006 and as a Director since November 21, 2005. Mr. Huff assumed additional responsibilities as President effective May 30, 2007. From December 5, 2005, through June 18, 2006, Mr. Huff served as Chairperson of our Audit Committee. He resigned from the Audit Committee on June 18, 2006. From 2004 until he became our Chief Financial Officer, Mr. Huff served as the Chief Financial Officer and Vice President of Finance for Visual Edge Technology, Inc., a California holding company engaged in acquiring imaging companies. From 1999 to 2004, Mr. Huff was a Principal and Founder of TriMillennium Ventures, LLC, a private equity investment company. From 1986 to 1999, Mr. Huff was an executive at Belden & Blake Corporation serving as Chief Financial Officer and President of this large Appalachian and Michigan Basin exploration and production company.

John V. Miller has served as a Vice President since November 1, 2005, holding positions variously titled as Vice President of Exploration and Production, Vice President of Science and Strategic Planning, and Vice President of Business and Corporate Development. Mr. Miller became an employee of Aurora at the time he sold his interest in Jet/LaVanway Exploration, L.L.C. to Aurora in exchange for Aurora’s stock on April 22, 1997. From April 1997 to the present, he has been the Vice President responsible for overseeing exploration and development activities for Aurora. From June 1997 through October 2005 he served as a Director of Aurora.

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John C. Hunter has served as Vice President of Exploration and Production, since May 30, 2007. Mr. Hunter is a petroleum engineer with over thirty years of oil and gas experience. He has worked for the Company since 2005 as Senior Petroleum Engineer. From 2004 to 2005, Mr. Hunter was Executive Vice President of Wellstream Energy Services providing petroleum engineering consulting services. From 2000 to 2004, Mr. Hunter was President of Terra Drilling Services, LLC and TerraFluids, LLC which provides short radius horizontal drilling services as well as drilling and completion fluids in the United States. From 1995 to 2004, Mr. Hunter was Director of Exploitation of Torch Energy Advisors, Inc. located in Houston, Texas where he managed a staff of 15 employees dedicated to the development of oil and natural gas properties.

Thomas W. Tucker served as a Vice President from November 1, 2005, through his effective retirement date of June 30, 2007, holding positions variously titled as Vice President of Land Development, Vice President of Operations, and Vice President of Exploration. Mr. Tucker became an employee of Aurora at the time he sold his interest in Jet/LaVanway Exploration, L.L.C. to Aurora in exchange for Aurora’s stock on April 22, 1997. From April 1997 to June 30, 2007, he has been the Vice President responsible for overseeing land development activities for Aurora. From June 1997 to October 2005 he served as a Director of Aurora. We have made arrangements with Mr. Tucker to be available in a consulting capacity through December 31, 2007, to assist us on various matters.

Richard M. Deneau has served on our Board of Directors since November 21, 2005. Mr. Deneau served as a Director and President of Anchor Glass Container Corporation (“Anchor”) from 1997 until his retirement in 2004. He was also the Chief Operating Officer of Anchor from 1997 to 2002, and the Chief Executive Officer of Anchor from 2002 until his retirement. Anchor, which was publicly traded and listed on NASDAQ, is the third largest glass container manufacturer in the United States, with annual revenues of about $750 million. When Richard M. Deneau joined Anchor, it was a financially troubled company. He designed and implemented strategies to turn its financial performance around. One of the strategies involved a Chapter 11 bankruptcy filing in April, 2002. The purpose of this filing was to provide assurance to a new investor that all prior claims had been extinguished. Richard M. Deneau is the brother of William W. Deneau, another one of our Directors, our Chairman, and our Chief Executive Officer.

Gary J. Myles has served on our Board of Directors since November 21, 2005. From June 1997 to the present, Mr. Myles has also served as a Director of Aurora. He is currently retired from his primary employment. Prior to his retirement, Mr. Myles served as Vice President and Consumer Loan Manager for Fifth Third Bank of Northern Michigan (previously Old Kent Mortgage Company), a wholly owned subsidiary of Fifth Third Bank (previously Old Kent Financial Corporation). As the Affiliate Consumer Loan Manager, Mr. Myles was based in Traverse City, Michigan, and had full bottom line responsibility for the mortgage and indirect consumer loan departments generating net revenue of $3.5 million annually. Mr. Myles had been with Fifth Third Bank and its predecessor, Old Kent Mortgage Company, since July 1988. Mr. Myles is the chairperson of our Audit Committee and Nominating and Corporate Governance Committee.

Wayne G. Schaeffer joined our Board of Directors on January 19, 2007. Mr. Schaeffer was employed by Citizens Banking Corporation from 1983 until his retirement in June 2005. Positions held with Citizens Banking Corporation include Executive Vice President, Head of Consumer Banking (June 2002 - June 2005) and Executive Vice President of Citizens Banking Corporation and President, Citizens Bank-Southeast Michigan (June 1996 - June 2002).

Kevin D. Stulp has served on our Board of Directors since March 1997. Since August 1995, Mr. Stulp has worked as a consultant with Forte Group, on the board of the Bible League, and is active with various other non-profit organizations and is currently a director of U.S. Silver Corporation, a publicly-traded silver mining company with operations in Wallace, Idaho. From December 1983 to July 1995, Mr. Stulp held various positions with Compaq Computer Corporation, including industrial engineer, new products planner, manufacturing manager, director of manufacturing, and director of worldwide manufacturing reengineering.

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Earl V. Young has served on our Board of Directors since November 21, 2005. From March 2001 to the present, Mr. Young has also served as a Director of Aurora. He is currently President of Earl Young & Associates of Dallas, Texas, which he founded in 1999. Mr. Young is also a Director and chair of the Audit Committee for Diamond Fields International, a Canadian company that is listed on the Toronto Stock Exchange and is a producer of offshore diamonds in Nambia with exploration activity in Sierra Leone and Liberia. Mr. Young is a Director of Madagascar Resources, an Australian public company that is engaged in mineral exploration in Madagascar. Mr. Young is the chairperson of our Compensation Committee.

More detailed biographical information about our directors and executive officers may be found on our website at www.auroraogc.com.

To our knowledge, no director, officer or affiliate of the Company, and no owner of record or beneficial owner of more than five percent (5%) of our securities, or any associate of any such director, officer or security holder is a party adverse to us or has a material interest adverse to us in reference to pending litigation.

BOARD COMMITTEES

A majority of our seven member Board of Directors qualify as independent directors. The following directors are independent directors as defined in Section 121A of the American Stock Exchange Corporate Governance Rules, a non-employee director as defined in Rule 16b-3 under the Securities Exchange Act of 1934, and an outside director as defined under Section 162(m) of the Internal Revenue Code: Gary J. Myles, Wayne G. Schaeffer, Kevin D. Stulp, and Earl V. Young.

We require that all members of our standing Board committees be independent directors. Effective May 18, 2007, our Board committees are as follows:

Audit Committee: Wayne G. Schaeffer (chairman), Gary J. Myles and, Earl V. Young.

Compensation Committee: Gary J. Myles (chairman), Wayne G. Schaeffer, and Kevin D. Stulp.

Nominating Committee: Kevin D. Stulp (chairman), Gary J. Myles and Earl V. Young.

Corporate Governance Committee: Earl V. Young (chairman), Wayne G. Schaeffer and Kevin D. Stulp.

During 2006, our Board of Directors met five times. All of the Directors attended at least 75% of the meetings of the Board of Directors and each committee on which they served.

Our Shareholder Communications with Directors Policy states that the Directors are expected to attend our annual meeting of shareholders each year in person whether or not they are standing for re-election. Each of the then-serving Directors attended the annual meeting held in 2006. We do not have information about Director participation in previous annual meetings.

Audit Committee

We have a separately designated standing Audit Committee established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934, as amended (“Exchange Act”). Members of the Audit Committee currently include Wayne G. Schaeffer, Chairman, Gary J. Myles, and Earl V. Young. During 2006, Kevin D. Stulp also served as a member of the Audit Committee. Each of them is an independent outside director. Two of them, Gary J. Myles and Wayne G. Schaeffer, are financial experts. We have included in the biographical information above a brief summary of their relevant experience.

On February 10, 2006, our Board of Directors adopted an Audit Committee Charter, a copy of which is posted on our website at www.auroraogc.com.

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Among the responsibilities of our Audit Committee are: (i) to appoint our independent auditors and monitor the independence of our independent auditors; (ii) to review our policies and procedures on maintaining accounting records and the adequacy of internal controls; (iii) to review management’s implementation of recommendations made by the independent auditors and internal auditors; (iv) to consider and pre-approve the range of audit and non-audit services performed by independent auditors and fees for such services; and (v) to review our audited financial statements, Management’s Discussion and Analysis of Financial Conditions and Results of Operations, and disclosures regarding internal controls before they are filed with the SEC.

COMPENSATION DISCUSSION AND ANALYSIS

Compensation Committee

Our Compensation Committee is comprised of three independent directors, Gary J. Myles, Chairman, Wayne G. Schaeffer, and Kevin D. Stulp. Each of these directors is an independent director as defined in Section 121A of the American Stock Exchange Corporate Governance Rules, a non-employee director as defined in Rule 16b-3 under the Securities Exchange Act of 1934, and an outside director as defined under Section 162(m) of the Internal Revenue Code.

Our Compensation Committee Charter delegates certain responsibilities to the Compensation Committee, including the following:

· Establish compensation policies that effectively attract, retain and motivate executive officers to successfully lead and manage the company;

· Review and approve corporate goals and objectives relevant to compensation of senior management, evaluate the performance of senior management in light of these goals and objectives, and set the compensation level for senior management based on this evaluation;

· Review, evaluate and approve all compensation of directors and executive officers, including salary adjustments, bonuses, stock awards, stock option grants, warrants, perquisites and other benefits;

· Review at least annually the Chief Executive Officer’s performance in connection with setting compensation;

· Review and make recommendations to the Board of Directors with respect to the adoption, amendment and termination of the company’s compensation plans (such as 401(k) savings, profit sharing, and other retirement plans and employee stock plans), oversee their administration and discharge any duties allocated to the Committee under any such plan;

· Review, evaluate and make recommendations to the Board of Directors with respect to the approval of the employment agreements of executive officers; and

· Review director compensation levels and practices and recommend to the full Board of Directors, from time to time, changes in such compensation levels and practices.

As a matter of practice and procedure, our Compensation Committee makes recommendations to the full Board of Directors for the compensation package for each of our executive officers. The final compensation package for our executive officers is required to be approved by a majority of our independent directors. We receive input from our Chief Executive Officer (“CEO”) about his recommendations for the structure of our executive officer compensation. However, we do not allow any executive officer whose compensation is being set to be present at either the Compensation Committee meeting or the Board of Directors meeting during the time that his compensation is being deliberated about or voted upon.

It is our practice to seek to establish executive compensation at the first Board of Directors meeting of every year. If there are unresolved issues related to executive compensation at the first Board of Directors meeting of the year, executive compensation may be established at later Board of Directors meetings, and any compensation adjustments from the prior year may be applied retroactively to the beginning of the year. To the extent that there are options awarded for a year to existing executive officers, we will tie the exercise price to the closing price at which our stock is traded on the first day of the Board of Directors meeting at which the option awards are approved. To the extent that we hire new executive officers and award them stock options as a signing bonus, the exercise price of the options will be the closing price at which our stock is traded on the first day of the following calendar quarter.

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General Objectives of Compensation Program

Our Compensation Committee Charter states that the Committee’s objective is to develop a compensation system that is competitive with our peers and encourages both short-term and long-term performance in a manner beneficial to us and our operations. Our compensation philosophy will vary among the executive officers, depending upon variables such as previous history with the company, number of shares of company stock owned, the impact of peer group comparison, and whether recruitment is a factor under the circumstances. We do not believe that a single approach or even a single objective is appropriate with respect to all executive officers. If an executive officer is also a director, it is our practice to compensate him only as an executive officer. He will not participate in the compensation awarded to the non-employee directors.

Compensation of our Chief Executive Officer, President and Vice Presidents

Objectives

Our CEO and our two Vice Presidents joined us upon closing of the merger between Cadence Resources Corporation and Aurora on October 31, 2005. Prior to the merger closing, they were the management team for Aurora. As a result of this management change upon closing the merger, our approach to executive officer compensation is in transition from that typical of a privately held growth stage company to that more typical of a publicly traded company.

For the year 2006, our objective in establishing the compensation for our CEO and Vice Presidents was to provide a fair compensation that would reward the extra effort we anticipated to be required during the year as a result of the October 31, 2005 merger. We knew that there would be a substantial learning curve through which they would have to guide the company as they took the company to the next level. We also had a need at that time to preserve cash. We were aware that our executive compensation was not as high as our peer group for publicly traded companies, but we felt that we needed to take some time to review our compensation structure before implementing significant changes.

As we entered 2007, we have continued to work on developing our compensation philosophy. We have been working with consultants to help us develop our philosophy for executive officer and director compensation. Accordingly, our primary objective for the year 2007 is to maintain a fair compensation level while we continue to work on developing a more comprehensive compensation philosophy.

Our Compensation Committee has also asked our CEO to work with a compensation consultant to develop a comprehensive compensation plan for all employees other than the executive officers. We expect that once our comprehensive compensation plan is developed, our compensation philosophy for executive officers will tie into the larger overall plan.

Elements of Executive Compensation

Base Salary. Unless a pre-existing employment contract requires otherwise, it is our practice to re-evaluate base salary for our executive officers each year. To assist us, we have retained the services of a compensation consulting firm that has provided us with data regarding compensation for peer executive officers within our industry. In general, our philosophy is to pay a base salary that is fair in the sense of being competitive enough in the market place to attract and retain our executive officers, given the circumstances of each individual involved, but no more. Our philosophy is not to match our peers, but to determine what is fair compensation under the circumstances. For the year 2006, we paid our CEO a base salary of $140,000 per year, and our two Vice Presidents each a base salary of $125,000 per year.

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We will generally not increase or decrease our base salary compensation levels materially unless there is a material change in our financial and market performance. We will generally look at modest annual increases as a means of making up for inflationary cost of living increases and to provide some modest merit-based increase for work done during the prior year.

Annual Performance Bonus. Our approach to the use of annual performance bonuses will vary from year to year. We do not have a formal incentive bonus plan tied to predetermined performance benchmarks in place for our executive officers for the year 2007. However, we have recently awarded stay bonuses and retention bonuses to some of our executive officers as more fully described below.

Stock Options. We use stock options from time to time to serve as a long-term incentive to keep our employees' performance aligned with our overall corporate goals. Because of the tax preferred treatment of incentive stock options, we evaluate the tax benefits of incentive stock options when evaluating compensation for our executive officers. In the past, we have not taken into account the effect of stock options on our financial statements when we determine whether or not to award stock options to our executive officers. This may change in the future.

In 2006, we awarded our CEO an option to purchase 200,000 shares of our common stock vesting over three years with 60,000 shares vesting on December 31, 2006, 70,000 shares vesting on December 31, 2007, and 70,000 shares vesting on December 31, 2008. This award was intended to provide additional compensation in acknowledgement of our CEO’s work in closing the merger in 2005, and to serve as a longer term incentive to lead us in such a fashion as to improve our stock value over time. We have not awarded our CEO any new stock options during 2007.

In 2006, we awarded each of our two Vice Presidents an option to purchase 40,000 shares of our common stock. These awards were vested on the date of grant. These awards were intended to provide additional compensation in acknowledgement of their work in closing the merger in 2005, and to serve as a longer term incentive to lead us in such a fashion as to improve our stock value over time. We have not awarded our two Vice Presidents any stock options in 2007.

Stock Awards. In addition to the issuance of stock options, we also have used, and from time to time expect to continue to use, stock awards as an element of executive compensation. This determination will be made on a case-by-case basis. For the year 2007, we have not made any separate stock awards to our CEO or our two Vice Presidents.

Other Types of Compensation. Except as provided below, we do not have in place at this time any other types of long-term incentive compensation or special executive benefits not provided to all of our employees on the same terms. Our philosophy at this time is to maintain a fairly simple executive compensation structure.

Compensation of our Chief Financial Officer

We hired our Chief Financial Officer in June 2006 under a two-year contract. Our primary motivation when we negotiated this contract was immediate recruitment. Under this contract, our Chief Financial Officer receives a base salary of $200,000 per year held constant during the term of the contract. This contract does not provide for an annual or other cash performance bonus or stock option award.

This contract provides that so long as our Chief Financial Officer continues to serve as an employee through June 18, 2008, on January 1, 2009, we will grant him 500,000 shares of our common stock. He may also receive this stock award if his employment terminates before June 18, 2008 upon the happening of certain events, such as termination without just cause, death, disability and a change of control. These triggers were negotiated prior to his acceptance of our offer of employment, and were selected based upon what was necessary to get him to accept our offer. Because our Chief Financial Officer does not currently have a sizable equity position in the Company similar to our other executive officers, we wanted to align his interests in a significant way with all other shareholders in the Company.

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Equity Ownership Guidelines and Requirements

We do not require non-director executive management to own our equity. As described below, Directors are required to own a nominal amount of our stock within a specified period of time. This requirement applies to executive officers who are also Directors.

Our Insider Trading Policy prohibits all insiders, including executive officers and directors, from trading in any interest or position relating to our future stock prices, such as puts, calls and short sales. We have encouraged our executive officers who desire to trade in our stock to establish 10b5-1 Plans in order to minimize the risk of trading on non-public information.

Recent Contractual Arrangements

On September 19, 2007, we announced that we had retained an investment banker to assist the Board of Directors in evaluating strategic alternatives. These alternatives, among other things, may include revisions to our strategic plan, asset divestitures, operating partnerships, identifying additional capital sources, or a sale, merger, or other business combination. We recognize that the possibility of a change in control may exist and it is in our best interest to assure that we maintain dedicated key employees to provide significant services through the evaluation process. The following arrangements have been approved for certain key officers and employees.

Stay Bonus. On September 18, 2007, our Board of Directors approved a stay bonus arrangement to encourage employees to remain employed by us through any possible change in control. For purposes of this arrangement, “change in control” means any transaction or occurrence (including a sale of stock or a merger) where our shareholders before the transaction or occurrence own less than 50% of our voting shares after the transaction or occurrence or there is a sale or disposition of a majority of our assets.

The stay bonus arrangement provides that if a change in control occurs on or before September 1, 2008, and employees remain continuously employed with us through such change of control, employees are then eligible for a stay bonus in the amount of 50% of their then current annual base salary. We will pay this stay bonus less applicable withholdings and taxes upon the occurrence of a change in control. Certain of our officers are covered by this arrangement and their potential stay bonuses are estimated on their current salaries as follows: (i) Ronald E. Huff (President and Chief Financial Officer) $100,000; (ii) John V. Miller (Vice President) $67,500; (iii) John C. Hunter (Vice President) $66,000; and (iv) Lorraine M. King (Former Chief Financial Officer) $62,500.

Change of Control Agreements. On October 19, 2007, the Board of Directors approved a change in control arrangement to encourage certain key officers and employees to remain employed by us through any potential change in control. The change in control agreement provides for the employment of the certain key officers and employees during a specified period following a change of control and provides certain benefits in the event that the key officer or employee’s employment is terminated during such period other than for cause or by the key officer or employee for good reason.

For purposes of this arrangement, “change in control” is defined in the change in control agreement to cover various transactions or occurrences resulting in a change in our stock or asset ownership.

The change of control agreement provides that during the two-year period, the key officer or employee will (i) have a position and duties commensurate to those of the officer prior to the change of control, (ii) perform his or her services at a location within a 35-mile radius from the previous work site before the change in control, and (iii) receive an annual base salary at least equal to the employee’s annual base salary prior to a change in control unless a reduction occurs on a proportional basis simultaneously with a Company-wide reduction in senior management salaries.

In the event of a covered termination during the two-year period following a change of control, the arrangement provides for (i) the payment of an amount equal to either one or two times the employee’s annual salary as specified in each employee’s individual agreement, (ii) the provision for medical and dental benefits for up to 24 months following the date of termination, and (iii) benefits continuation substantially similar to those to which the employee was entitled prior to the date of termination.

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Certain of our officers are covered by this arrangement and their specified lump sum payments in the event of a termination are as follows: (i) John C. Hunter (Vice President) two times his annual base salary, and (ii) Lorraine M. King (Former Chief Financial Officer) one times her annual base salary.

Retention Bonus. Our Board of Directors has approved a retention bonus arrangement to encourage certain key officers and employees to remain employed with us through the completion of our review of potential strategic alternatives. The Board of Directors recognizes that certain key officers and employees will have increased responsibilities and duties during the evaluation of strategic alternatives and will contribute significantly to the process. The aggregate retention bonus consists of four payments over an 8-month period beginning in late October 2007 through late April 2008. The key officers and employees must remain continuously employed with us as well as remain in good standing on the scheduled payment dates. As of October 24, 2007, certain of our officers accepted this arrangement and their potential retention bonuses are estimated as follows: (i) Ronald E. Huff (President and Chief Financial Officer), $100,000; (ii) John C. Hunter (Vice President), $80,000; (iii) John V. Miller, Jr. (Vice President), $40,000; and (iv) Lorraine M. King (former Chief Financial Officer), $25,000.

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EXECUTIVE COMPENSATION

On November 1, 2005, our prior management team was replaced by the Aurora management team. As part of the merger, we changed from a September 30 to a December 31 fiscal year-end. Our financial results for 2005 include 12 months of Aurora operations and two months (November and December 2005) of operations of Cadence Resources Corporation. We are disclosing executive compensation in the same fashion below. The information below shows compensation paid by Aurora to the executives listed below for the 12 months ended December 31, 2005 and 2004, and compensation paid by Cadence Resources Corporation (now Aurora Oil & Gas Corporation) for the 12 months ended December 31, 2006 and the months of November and December 2005.

The following four tables set forth information regarding our Chief Executive Officer, Chief Financial Officer, and our remaining two executive officers of the Company.

SUMMARY COMPENSATION TABLE

Name and Principal Position	Year		Salary ($)			Bonus ($)		Stock Awards ($)			Option Awards ($)			All Other Compen-sation ($)			Total ($)
William W. Deneau		2006		140,000			28,000		-			196,974	(a)		2,450	(b)		367,424
President, Chief		2005		140,000	(c)		-		-			-			-			140,000
Executive Officer		2004		90,000			-		-			-			-			90,000
Ronald E. Huff		2006		105,400	(d)		-		566,521	(e)		-			2,000	(b)		673,921
Chief Financial		2005		2,500	(d)		-		-			-			-			2,500
Officer		2004		-			-		-			-			-			-
John V. Miller, Jr.		2006		125,000			26,250		-			64,332	(a)		1,875	(b)		217,457
Vice President		2005		125,000	(c)		-		-			-			-			125,000
		2004		90,000			-		-			-			-			90,000
Thomas W. Tucker		2006		125,000			26,250		-			64,332	(a)		-			215,582
Vice President		2005		125,000	(c)		-		-			-			-			125,000
		2004		90,000			-		-			-			-			90,000
Lorraine M. King		2006		125,000	(f)		-		-			108,610	(a)		-			233,610
Chief Financial		2005		125,000			-		116,400	(g)		4,465			-			245,865
Officer (resigned		2004		65,000			25,000		-			3,301			-			93,301
as CFO effective 6/19/2006)

(a) The assumptions used to calculate value in accordance with FAS 123R may be found in Note 10 “Common Stock Options” of our financial statements provided in our 12/31/06 Form 10-KSB which was filed on March 15, 2007.

(b) These reflect our company match to a 401(K) defined contribution plan.

(c) Some of the executive officers received additional cash compensation during 2005, but this was payment of deferred salaries for the years 2000 and 2001 that had been recorded, but not paid. This includes an additional cash payment of $47,244 for Mr. Deneau, $26,667 for Mr. Miller and $50,000 for Mr. Tucker.

(d) Mr. Huff became our chief financial officer on June 19, 2006. We paid him a salary in the amount of $90,900 (annual salary of $200,000 per year) for services rendered from the period June 19, 2006 through December 31, 2006. Mr. Huff served as a director throughout the entire year of 2006. We paid him $14,500 for director services through June 18, 2006, including compensation for his services as chairman of our audit committee. We do not pay our executive officers separate compensation for serving as a director. Accordingly, Mr. Huff did not receive separate compensation for his service as a director from June 19, 2006 through the end of 2006. The salary paid to Mr. Huff in 2005 was related exclusively to his services as a director.

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(e) In connection with hiring Mr. Huff to serve as our Chief Financial Officer, on June 19, 2006, we agreed to award Mr. Huff a stock bonus in the amount of 500,000 shares of common stock on January 1, 2009, so long as he remains employed by us through June 18, 2008. The total value of this award is $2,110,000 based on the $4.22 per share price at which our stock was trading on June 19, 2006. Because of the two-year vesting requirement, we are prorating the compensation expense associated with this award over the vesting period.

(f) Effective June 19, 2006, Ms. King resigned as Chief Financial Officer. We continue to employ her as Treasurer.

(g) This reflects an award of 30,000 shares on December 8, 2005. The closing price at which our stock traded on that date was $3.88 per share.

The following table sets forth the grants of plan-based awards to our executive officers during the year 2006.

GRANTS OF PLAN-BASED AWARDS

Name	Grant Date		Date of Board Action		Stock Awards No. of Shares of Stock		Option Awards No. of Shares of Stock Underlying Options		Exercise Price of Option Award		Closing Market Price on Grant Date		Grant Date Fair Value of Stock and Option Awards
William W. Deneau(a)		05/19/06		12/08/05		-		200,000	$	3.62	$	4.70	$	399,800
Ronald E. Huff(b)		06/19/06		06/19/06		500,000		-		-	$	4.22	$	2,110,000
John V. Miller, Jr.(c)		03/16/06		03/16/06		-		40,000	$	5.50	$	5.50	$	64,332
Thomas W. Tucker(c)		03/16/06		03/16/06		-		40,000	$	5.50	$	5.50	$	64,332
Lorraine M. King(c) (former		03/16/06		03/16/06		-		60,000	$	5.50	$	5.50	$	108,610
CFO)

(a) The grant date is the date that we had an equity incentive plan in place with sufficient capacity to issue these options and an effective S-8 registration statement for these options. The exercise price is the fair market value on November 21, 2005, the date our new Board of Directors was impaneled after the October 31, 2005, merger, calculated using the average closing stock price over the preceding 30 trading days. The option award granted to Mr. Deneau vests as follows: 60,000 shares on December 31, 2006; 70,000 shares on December 31, 2007; and 70,000 shares on December 31, 2008.

(b) On June 19, 2006, we entered into an employment agreement with Ronald E. Huff relating to his service as our Chief Financial Officer. This agreement provides for a term of two years and an annualized salary of $200,000 per year. We have also agreed to award Mr. Huff a stock bonus in the amount of 500,000 shares of common stock on January 1, 2009, so long as Mr. Huff remains employed by us through June 18, 2008, which will require us to record $2,110,000 in stock-based compensation expense over the contract period. If Mr. Huff’s employment is terminated prior to this date without just cause or if we undergo a change in control, Mr. Huff will nonetheless be awarded the full 500,000 shares. If Mr. Huff’s employment is terminated prior to June 18, 2008 due to death or disability, he will receive a prorated stock award. As part of his employment arrangement, Mr. Huff forfeited the option to purchase 200,000 shares that he was previously awarded by the Company in return for his service as a director. Mr. Huff will not be eligible to participate in any annual bonus plan or other additional long-term incentive award during the term of the Employment Agreement.

(c) All of the option awards depicted on the foregoing table, other than options awarded to Mr. Deneau, were fully vested upon issuance.

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The following table sets forth information on exercised options and unvested stock awards held by our executive officers as of December 31, 2006.

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

Name	No. of Shares Underlying Unexercised Options - No. Exercisable		No. of Shares Underlying Unexercised Options - No. Unexercisable		Option Exercise Price		Option Expiration Date		No. of Shares That Have Not Vested		Market Value of Shares That Have Not Vested
William W. Deneau		60,000		140,000	$	3.62		11/11/10		-		-
Ronald E. Huff		-		-		-		-		500,000	$	1,605,000
John V. Miller, Jr.		40,000		-	$	5.50		03/16/11		-		-
Thomas W. Tucker		40,000		-	$	5.50		03/16/11		-		-
Lorraine M. King (former CFO)		20,000 60,000		- -	$ $	1.75 5.50		10/18/15 03/16/11		- -		- -

The following table sets forth the options exercised by our executive officers during 2006, and stock awards held by our executive officers that vested during 2006.

OPTION EXERCISES AND STOCK VESTED

Name	No. of Shares Acquired on Exercise		Value Realized on Exercise		No. of Shares Acquired on Vesting		Value Realized on Vesting
William W. Deneau(a)		0		-		0		-
Ronald E. Huff		0		-		0		-
John V. Miller, Jr.(a)		0		-		0		-
Thomas W. Tucker(a)		0		-		0		-
Lorraine M. King		140,000	$	515,900		0		-
(former CFO)

(a) In December 2006, Mr. Deneau, Mr. Miller and Mr. Tucker rescinded option exercises for 600,000 shares each. The option exercise price of $249,000 was returned to each of these officers and, in exchange, each officer surrendered 600,000 shares of common stock. These options expired in 2006.

COMPENSATION OF DIRECTORS

The table below sets forth the compensation we paid to our non-employee directors during 2006.

Name	Fees Earned or Paid in Cash		Value of Option Awards			Total
Howard Crosby	$	3,000		0(a	)	$	3,000
Richard M. Deneau	$	17,500	$	196,974(b	)	$	214,474
Gary J. Myles	$	17,500	$	196,974(c	)	$	214,474
Kevin D. Stulp	$	17,500	$	196,974(d	)	$	214,474
Earl V. Young	$	25,000	$	196,974(e	)	$	221,974

(a) Howard Crosby resigned as our director on June 6, 2006. Although he was granted an option to purchase 200,000 shares of our common stock on May 19, 2006, the option was unvested in its entirety on the date of his resignation, and therefore was forfeited immediately.

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(b) At December 31, 2006, Richard M. Deneau owned options to purchase an aggregate of 200,000 shares of our common stock, 60,000 of which are vested and 140,000 of which are unvested.

(c) At December 31, 2006, Gary J. Myles owned options to purchase an aggregate of 359,998 shares of our common stock, 219,998 of which are vested, and 140,000 of which are unvested.

(d) At December 31, 2006, Kevin D. Stulp owned options to purchase an aggregate of 250,000 shares of our common stock, 110,000 of which are vested, and 140,000 of which are unvested.

(e) At December 31, 2006, Earl V. Young owned options to purchase an aggregate of 333,332 shares of our common stock, 193,332 of which are vested, and 140,000 of which are unvested.

For 2006, our standard compensation arrangement for service as a director was as follows:

· Option to purchase 200,000 shares of our common stock; vesting 60,000 shares on December 31, 2006, 70,000 shares on December 31, 2007, and 70,000 shares on December 31, 2008.

· Cash fee of $1,000 per Board of Directors meeting attended in person, with additional payments of $1,000 per day for each travel day from the Director’s place of residence to the location of the Board of Directors meeting, up to a total of two additional days in addition to the date of the meeting.

· Cash fee of $500 for participation in each telephonic Board of Directors meeting.

· Cash fee of $1,000 for each committee meeting attended in person.

· Cash fee of $500 for participating in each telephonic committee meeting.

· Annual retainer of $10,000 for the Audit Committee chairperson.

Our Board of Directors has adopted a policy requiring each director to own at least 20,000 shares of our common stock. For new directors, this requirement must be satisfied within one year of joining our Board of Directors. This requirement applies to all directors, including those who are employees and those who are not employees.

PRINCIPAL AND SELLING SECURITY HOLDERS

The following table sets forth, as of September 30, 2007, certain information regarding the ownership of voting securities of the Company by each shareholder known by the management of the Company to be (i) the beneficial owner of more than 5% of our outstanding common stock, (ii) our directors, (iii) our current executive officers and (iv) all executive officers and directors as a group. Except as otherwise reflected in the notes below, the Company believes that the beneficial owners of the common stock listed below, based on information furnished by such owners, have sole investment and voting power with respect to such shares.

Unless otherwise specified, the address of each of the persons set forth below is in care of Aurora Oil & Gas Corporation, 4110 Copper Ridge Drive, Suite 100, Traverse City, Michigan, 49684.

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Name and Address of Beneficial Owners(a)	Amount and Nature of Beneficial Ownership(b)			Percent of Outstanding Shares
FMR Corp.(c)		14,919,444			15	%
82 Devonshare Street
Boston, Massachusetts 02109
Nathan A. Low Roth IRA and affiliates		8,586,409(d	)		8	%
641 Lexington Avenue
New York, New York 10022
Crestview Capital Master, LLC		5,819,500(e	)		6	%
95 Revere Drive, Suite A
Northbrook, Illinois 60062
CCM Master Qualified Fund		4,994,453(f	)		5	%
One North Wacker Drive, Suite 4725
Chicago, Illlinois 60606
William W. Deneau		3,714,814(g	)		4	%
Thomas W. Tucker (retired 6/30/07)		3,167,016(h	)		3	%
John V. Miller, Jr.		2,717,430(i	)		3	%
Kevin D. Stulp		587,500(j	)		*
Earl V. Young		476,204(k	)		*
Gary J. Myles		368,798(l	)		*
Richard M. Deneau		80,000(m	)		*
Ronald E. Huff		20,000(n	)		*
Wayne G. Schaeffer		20,000(o	)		*
John C. Hunter		79,400(p	)		*
All executive officers and directors as a group (10 persons)		11,231,162(q	)		12	%

* Less than 1%

(a) Addresses are only given for holders of more than 5% of outstanding common stock who are not executive officers or directors.

(b) A person is deemed to be the beneficial owner of a security if such person has or shares the power to vote or direct the voting of such security or the power to dispose or direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities if that person has the right to acquire beneficial ownership within 60 days of the date of this chart.

(c) Based on Schedule 13G/A filed with the Securities and Exchange Commission (“SEC”) on February 14, 2007, FMR Corp., through its wholly-owned subsidiary Fidelity Management & Research Company (“Fidelity”), an investment advisor registered under Section 203 of the Investment Advisors Act of 1940, is the beneficial owner of 14,590,844 shares of common stock. Edward C. Johnson III and members of his family form a controlling group with respect to FMR Corp. Accordingly, FMR Corp. and Edward C. Johnson III have the sole power to dispose of 14,590,844 shares of common stock. They do not, however, have voting power, which instead resides with the Board of Trustees of the investment companies that are managed by Fidelity. Fidelity Management Trust Company, a wholly-owned subsidiary of FMR Corp. and a bank, is the beneficial owner of 15,200 shares of common stock, and FMR Corp and Edward C. Johnson III have the sole dispositive power and sole power to vote or direct the voting of the 15,200 shares of common stock beneficially owned by Fidelity Management Trust Company. Pyramis Global Advisors Trust Company (“Pyramis”), an indirect wholly-owned subsidiary of FMR Corp. and a bank, is the beneficial owner of 313,400 shares of common stock. FMR Corp and Edward C. Johnson III have the sole dispositive power over the 313,400 shares of common stock beneficially owned by Pyramis, and the sole power to vote or to direct the voting of 275,900 shares of common stock beneficially owned by Pyramis.

(d) Based on information included in an amendment to Schedule 13D/A filed with the SEC on February 27, 2006, Nathan A. Low has the sole power to vote or direct the vote of, and the sole power to direct the disposition of, the shares held by the Nathan A. Low Roth IRAs and the shares held by him individually. Although Nathan A. Low has no direct voting or dispositive power over the 828,643 shares of common stock held by the Nathan A. Low Family Trust or the 100,000 shares of common stock held in individual trusts for the Neufeld children, he may be deemed to beneficially own those shares because his wife, Lisa Low, is the trustee of the Nathan A. Low Family Trust and custodian for the Neufeld children. Therefore, Nathan A. Low reports shared voting and dispositive power over 928,643 shares of common stock.

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(e) Based on information included in an amendment to Schedule 13G/A filed with the SEC on June 26, 2006, Crestview Capital Master LLC is the beneficial owner of 5,819,500 shares of common stock. Messrs. Stewart Flink, Robert Hoyt and Daniel Warsh, share the sole dispositive power and the sole power to vote or direct the voting of the 5,819,500 shares beneficially owned by Crestview Capital Master, LLC.

(f) Based on Schedule 13G filed with SEC for the period ended June 30, 2007, 4,994,453 shares of common stock were deemed to be beneficially owned by CCM Master Qualified Fund, Ltd., Coghill Capital Management, L.L.C., and Clint D. Coghill. Mr. Coghill is the managing member of Coghill Capital Management, L.L.C., an entity which serves as the investment manager of CCM Master Qualified Fund, Ltd. CCM Master Qualified Fund, Ltd., Coghill Capital Management, L.L.C., and Clint D. Coghill share voting power and dispositive power to vote or direct the voting of the 4,994,453 shares beneficially owned by them.

(g) Includes options currently exercisable for 60,000 shares of common stock; 3,272,000 shares of common stock held by the Patricia A. Deneau Trust; 360,146 shares of common stock held by the Denthorn Trust; 20,000 shares of common stock held by White Pine Land Services, Inc.; and 2,668 shares of common stock held by Circle D, Ltd. (shared investment interest). Does not include an option to purchase 140,000 shares of common stock vesting as follows: 70,000 shares on January 1, 2008; and 70,000 shares on January 1, 2009.

(h) Includes 1,567,774 shares of common stock held by the Sandra L. Tucker Trust; 1,454,377 shares of common stock held by the Thomas W. Tucker Trust; 2,668 shares of common stock held by Circle D, Ltd. (shared investment interest); and options currently exercisable for 40,000 shares of common stock.

(i) Includes 1,000,000 shares of common stock held by Miller Resources, Inc.; 1,648,976 shares of common stock owned by Circle M, LLC; 10,000 shares of common stock held by spouse; 2,668 shares of common stock held by Circle D, Ltd. (shared investment interest); 5,000 shares of common stock held by John Miller Jr. Trust; and options currently exercisable for 40,000 shares of common stock.

(j) Includes options currently exercisable for 110,000 shares of common stock; 2,750 shares of common stock owned by the Kevin Dale Stulp IRA; and 1,750 shares of common stock owned by the Kevin and Marie Stulp Charitable Remainder Unitrust of which Mr. Stulp is a co-trustee. Does not include an option to purchase 140,000 shares of common stock vesting as follows: 70,000 shares on January 1, 2008; and 70,000 shares on January 1, 2009.

(k) Includes options currently exercisable for 193,332 shares of common stock. Does not include an option to purchase 140,000 shares of common stock vesting as follows: 70,000 shares on January 1, 2008; and 70,000 shares on January 1, 2009.

(l) Includes 144,466 shares of common stock held by the Gary J. Myles & Rosemary Myles Inter Vivos Trust; and options currently exercisable for 193,332 shares of common stock. Does not include an option to purchase 140,000 shares of common stock vesting as follows: 70,000 shares on January 1, 2008; and 70,000 shares on January 1, 2009.

(m) Includes options currently exercisable for 60,000 shares of common stock. Does not include an option to purchase 140,000 shares of common stock vesting as follows: 70,000 shares on January 1, 2008; and 70,000 shares on January 1, 2009.

(n) Does not include 500,000 shares of common stock to be awarded on January 1, 2009, subject to vesting requirements.

(o) Does not include an option to purchase 140,000 shares of common stock vesting as follows: 70,000 shares on February 23, 2008; and 70,000 shares on February 23, 2009.

(p) Includes 2,400 shares of common stock held by son and options currently exercisable for 65,000 shares of common stock. Does not include an option to purchase 40,000 shares of common stock vesting as follows: 30,000 shares on March 1, 2008; 5,000 shares on May 19, 2008; and 5,000 shares on May 19, 2009.

(q) Includes options currently exercisable for a total of 761,664 shares of common stock.

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Selling security holders

We issued to the selling security holders the common stock and the warrants to purchase common stock that are covered by this prospectus pursuant to a private placement in January 2005. This prospectus relates to the resale from time to time of up to a total of 8,900,000 shares of our common stock acquired by the certain selling security holders identified in this prospectus either directly in the January private placement or pursuant to the exercise of warrants purchased in the January private placement. We filed a registration statement, of which this prospectus constitutes a part, in order to permit the selling security holders to resell to the public the shares of our common stock in connection with the January 2005 private placement.

The following table sets forth the names of the selling security holders, the number of shares of common stock beneficially owned by the selling security holders, the number of shares of common stock being offered by the selling security holders, the number of shares of common stock each selling security holder will beneficially own if the security holder sells all of the shares being registered and the selling security holder’s percentage ownership of our common stock if all the shares in the offering are sold. The shares being offered hereby are being registered to permit public secondary trading, and the selling security holders may offer all or part of the shares for resale from time to time. However, the selling security holders are under no obligation to sell all or any portion of such shares nor are the selling security holders obligated to sell any shares immediately under this prospectus. To prevent dilution to the selling security holders, the following numbers may change because of adjustments to reflect stock splits, stock dividends, or similar events involving our common stock.

None of the selling security holders have, nor within the past three years have had, any position, office, or other material relationship with us or any of our predecessors or affiliates, other than as a greater than 5% shareholder, except that Nathan A. Low, through his controlled entity, Sunrise Securities Corporation, performed institutional investor relations services for us and acted as a finder of investors in various private placements in which we have previously engaged.

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Selling Security Holders	Shares of Common Stock Beneficially Owned Prior to Offering*		Shares of Common Stock to be Sold*		Beneficial Ownership After Offering if all Shares are Sold*		Percent of Class Owned After Offering if all Shares are Sold**
Crestview Capital Master, LLC(1)		5,819,500		3,680,000		2,139,500		2.1	%
Nathan Low Family Trust, DTD 4/12/96(2)		928,643		720,000		208,643		0.2	%
Bear Stearns, as Custodian for Nathan A. Low Roth IRA(2)		7,657,766		400,000		7,257,766		7.1	%
Ruth Low		538,259		480,000		58,259		***
Coghill Capital(3)		3,829,620		640,000		3,189,620		3.1	%
Cordillera Fund L.P.(4)		800,000		800,000		0		-
Enable Growth Partners LP(5)		480,000		480,000		0		-
Michael Weiss		180,000		100,000		80,000		***
Don Sanders		320,000		320,000		0		-
Sanders Opportunity Fund (Inst) LP(6)		493,646		493,646		0		-
Sanders Opportunity Fund LP(6)		154,354		154,354		0		-
Sanders 1998 Children’s Trust(6)		240,000		240,000		0		-
Don Weir and Julie E. Weir		160,000		160,000		0		-
Ben T. Morris		40,000		40,000		0		-
Fredrick Saalwachter(7)		40,000		40,000		0		-
George L. Ball		40,000		40,000		0		-
John Malanga and Jodi Malanga(8)		32,000		32,000		0		-
Bruce McMaken(9)		40,000		40,000		0		-
Mike Chadwick		40,000		40,000		0		-
Totals		21,833,788		8,900,000		12,933,788		12.5	%

* This information is provided as of November 1, 2005, except to the extent that we were able to update it based on a Schedule 13D or Schedule 13G filing made by the selling security holder after that date. We have, however, revised our footnotes below to reflect exercises of warrants that have occurred since November 1, 2005. Since this registration statement became effective, many of the shares included in the registration statement have been sold. Except in cases where a Schedule 13D or Schedule 13G have been filed, we are not able to track exactly how many shares have been sold to date under the registration statement, or how many shares may have subsequently been acquired by the selling security holders. We are therefore presenting the information in the first three columns as of the time this registration statement became effective, except in the cases where a Schedule 13D or Schedule 13G filing reflect different information.

** The percent of class information is based upon a total of 101,679,458 shares of common stock outstanding. However, as reflected in the previous footnote, the beneficial ownership used to calculate the percent of class is based upon the ownership at the time this registration statement became effective, except in those situations in which a Schedule 13D or Schedule 13G have since been filed, in which case the calculation is based on those filings.

*** Less than 0.1%.

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(1) Based on a Schedule 13G filed with the SEC on June 23, 2006, Crestview Capital Partners, LLC controls Crestview Capital Master, LLC, and the power to vote or dispose of our shares beneficially owned by Crestview Capital Master, LLC is shared by Stewart Flink, Robert Hoyt and Daniel Warsh, each of whom disclaims beneficial ownership of our shares.

(2) See footnote (d) above under the heading "Principal Shareholders").

(3) Based on Schedule 13G filed with the SEC on February 14, 2006, Clint D. Coghill is the managing member of Coghill Capital, and shares the power to vote and dispose of these shares with CCM Master Qualified Fund, Ltd. and Coghill Capital Management, L.L.C.

(4) We have been informed that James Andrew is the controlling person at Cordillera Fund, L.P.

(5) We have been informed that Brendan O'Neil is the controlling person of Enable Growth Partners LP. Shares of common stock beneficially owned and to be sold includes warrants to purchase 240,000 shares of our common stock.

(6) We have been informed that Don A. Sanders is the controlling person of Sanders Opportunity Fund (Inst.) LP, Sanders Opportunity Fund LP, and Sanders 1998 Children's Trust.

(7) Shares of common stock beneficially owned and to be sold includes warrants to purchase 20,000 shares of our common stock.

(8) Shares of common stock beneficially owned and to be sold included warrants to purchase 16,000 shares of our common stock.

(9) Shares of common stock beneficially owned and to be sold includes warrants to purchase 20,000 shares of our common stock.

RELATED PARTY TRANSACTIONS

In connection with the December 2005 through February 2006 exercise of certain warrants that had previously been issued by the Company and Aurora in January 31, 2005 transactions, we paid a commission to Sunrise Securities Corporation, an affiliate of Nathan A. Low, who is a greater than 5% holder of our common stock, in the amount of $1,534,697. This entire amount was used by Mr. Low to exercise certain outstanding warrants to purchase 1,469,860 shares of our common stock.

William W. Deneau, John V. Miller, Jr. and Thomas W. Tucker, each of whom is one of our executive officers, are involved as equity owners in numerous corporations and limited liability companies that are active in the oil and natural gas business and in some cases, participate in the same wells and fields that we participate in. They also own miscellaneous overriding royalty interests in wells in which we have an interest. During 2006, our Nominating and Corporate Governance Committee asked that these executive officers divest themselves of all such interests for which we serve as operator. That divesture was accomplished by the end of 2006.

In order to replace the collateral pledged to Northwestern Bank for our revolving line of credit, on December 21, 2005, The Denthorn Trust, which is controlled by William W. Deneau, executed a Commercial Guaranty of our obligation on the Northwestern Bank revolving line of credit, and a Commercial Pledge Agreement pursuant to which The Denthorn Trust has pledged to Northwestern Bank 306,450 shares of our common stock to secure payment of our indebtedness. Also on December 21, 2005, the Patricia A. Deneau Trust, DTD 10/12/95, which is controlled by William W. Deneau, executed a Commercial Guaranty and a Commercial Pledge Agreement, pursuant to which it pledged 2,944,800 shares of our common stock to Northwestern Bank to secure payment of our indebtedness.

Mr. Hunter has been instrumental in certain projects associated with the Company’s New Albany shale play. Over a series of agreements with the Company, Mr. Hunter (controlling member of Venator Energy, LLC) has acquired 1.25% working interest in certain leases. The leases cover approximately 132,600 acres (1,658 net) in certain counties located in Indiana. The 1.25% carried working interest shall be effective until development costs exceed $30 million. Thereafter, participation may continue as a standard 1.25% working interest owner. The Company is entitled to recovery of 100% of development costs (plus interest at a rate of 6.75% per annum compounded annually) from 85% of the net operating revenue generated from oil and gas production developed directly or indirectly in the area of mutual interest covered by the agreement. As of June 30, 2007, there is no production associated with this working interest and development costs were approximately $12.0 million.

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Effective July 1, 2004, Aurora Energy, Ltd., (“AEL”), entered into a Fee Sharing Agreement with Mr. Hunter as compensation for bringing Bluegrass Energy Enhancement Fund, LLC (“Bluegrass”) and AEL together for the development of the 1500 Antrim and Red Run Projects in Michigan. At this time, AEL and Bluegrass have discontinued leasing activities in both projects. In the 1500 Antrim project, there are 23,989.41 acres. Mr. Hunter's carried working interest share of 0.8333% is approximately 199.95 net acres. The carried working interest relates to the first 55 wells that are drilled in the area of mutual interest. Thereafter, Mr. Hunter would pay his proportionate share of working interest expenses. Currently, there are no producing wells. The Red Run project contains 12,893.64 acres. Mr. Hunter's carried working interest share of 0.8333% is approximately 107.44 net acres. The carried working interest relates to the first 55 wells that are drilled in the area of mutual interest. Thereafter, Mr. Hunter would pay his proportionate share of working interest expenses. Currently, there are 3 wells permitted for the Red Run project and one well was temporarily abandoned in June 2007.

Thomas W. Tucker retired effective June 30, 2007. The Company has signed a consulting arrangement with Mr. Tucker to be available through December 31, 2007, to assist the Company on various matters.

It is probable that on occasion, we will find it necessary or appropriate to deal with other entities in which Messrs. Deneau and Miller have an interest. From time to time, we may also enter into transactions in which our directors have an interest. Our Corporate Governance Committee Charter requires this Committee to review and approve all related party transactions between the Company and its executive officers and directors.

PLAN OF DISTRIBUTION

The selling security holders may, from time to time, sell any or all of their shares of common stock on any stock exchange, market, or trading facility on which the shares are traded or in private transactions. These sales may be at fixed or negotiated prices. The selling security holders may use any one or more of the following methods when selling shares:

· ordinary brokerage transactions and transactions in which the broker-dealer solicits purchasers;

· block trades in which the broker-dealer will attempt to sell the shares as agent but may position and resell a portion of the block as principal to facilitate the transaction;

· purchases by a broker-dealer as principal and resale by the broker-dealer for its account;

· an exchange distribution in accordance with the rules of the applicable exchange

· privately negotiated transactions;

· short sales;

· broker-dealers may agree with the selling security holders to sell a specified number of such shares at a stipulated price per share;

· a combination of any such methods of sale; and

· any other method permitted pursuant to applicable law.

The selling security holders may also sell shares under Rule 144 under the Securities Act, if available, rather than under this prospectus.

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The selling security holders may also engage in short sales against the box, puts and calls, and other transactions in our securities or derivatives of our securities and may sell or deliver shares in connection with these trades. However, selling security holders may not engage in short sales before this registration statement becomes effective.

Broker-dealers engaged by the selling security holders may arrange for other brokers-dealers to participate in sales. Broker-dealers may receive commissions or discounts from the selling security holders (or, if any broker-dealer acts as agent for the purchaser of shares, from the purchaser) in amounts to be negotiated. The selling security holders do not expect these commissions and discounts to exceed what is customary in the types of transactions involved. Any profits on the resale of shares of common stock by a broker-dealer acting as principal might be deemed to be underwriting discounts or commissions under the Securities Act. Discounts, concessions, commissions, and similar selling expenses, if any, attributable to the sale of shares will be borne by a selling security holder. The selling security holders may agree to indemnify any agent, dealer, or broker-dealer that participates in transactions involving sales of the shares, if liabilities are imposed on that person under the Securities Act.

The selling security holders may from time to time pledge or grant a security interest in some or all of the shares of common stock owned by them and, if they default in the performance of their secured obligations, the pledges or secured parties may offer and sell the shares of common stock from time to time under this prospectus after we have filed an amendment to this prospectus under Rule 424(b)(3) or other applicable provision of the Securities Act of 1933 amending the list of selling security holders to include the pledge, transferee, or other successors in interest as selling security holders under this prospectus.

The selling security holders also may transfer the shares of common stock in other circumstances, in which case the transferees, pledges, or other successors in interest will be the selling beneficial owners for purposes of this prospectus and may sell the shares of common stock from time to time under this prospectus after we have filed an amendment to this prospectus under Rule 424(b)(3) or other applicable provision of the Securities Act of 1933 amendment the list of selling security holders to include the pledge, transferee, or other successors in interest as selling security holders under this prospectus.

The selling security holders and any broker-dealers or agents that are involved in selling the shares of common stock may be deemed to be “underwriters” within the meaning of the Securities Act in connection with such sales. In such event, any commissions received by such broker-dealers or agents and any profit on the resale of the shares of common stock purchased by them may be deemed to be underwriting commissions or discounts under the Securities Act. The selling security holders have advised us that they have acquired their securities in the ordinary course of business and that they have not entered into any agreements, understandings, or arrangements with any underwriters or broker-dealers regarding the sale of their shares of common stock, nor is there an underwriter or coordinating broker acting in connection with a proposed sale of shares of common stock by any selling security holder. If the selling security holders use this prospectus for any sale of the shares of common stock, they will be subject to the prospectus delivery requirements of the Securities Act.

We are required to pay all fees and expenses incident to the registration of the shares of common stock. We have agreed to indemnify the selling security holders against certain losses, claims, damages, and liabilities, including liabilities under the Securities Act.

The anti-manipulation rules of Regulation M under the Securities Exchange Act of 1934 may apply to sales of our common stock and activities of the selling security holders.

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DESCRIPTION OF SECURITIES

Our authorized capital stock consists of 250,000,000 shares of common stock, par value $0.01 per share and 20,000,000 shares of preferred stock, par value $0.01 per share. As of September 30, 2007, we had 101,679,456 shares of common stock issued and outstanding.

Common Stock

The holders of our common stock are entitled to one vote for each share held of record on all matters submitted to a vote of shareholders. Accordingly, holders of a majority of the shares of our common stock entitled to vote in any election of directors may elect all of the directors standing for election. Holders of common stock are entitled to receive ratably such dividends as may be declared by the board out of funds legally available therefor. In the event of our liquidation, dissolution or winding up, holders of common stock are entitled to share ratably in the assets remaining after payment of liabilities. Holders of our common stock have no preemptive, conversion or redemption rights. All of the outstanding shares of common stock are fully paid and non-assessable.

Holders

As of September 30, 2007, there were 527 holders of record for our common stock, although we believe that there are additional beneficial owners of our common stock who own their shares in “street name.”

Preferred Stock

Our board of directors may, without shareholder approval, establish and issue shares of one or more classes or series of preferred stock having the designations, number of shares, dividend rates, liquidation preferences, redemption provisions, sinking fund provisions, conversion rights, voting rights and other rights, preferences and limitations that our board may determine. Our board may authorize the issuance of preferred stock with voting, conversion and economic rights senior to the common stock so that the issuance of preferred stock could adversely affect the market value of the common stock. The creation of one or more series of preferred stock may adversely affect the voting power or other rights of the holders of common stock. The issuance of preferred stock, while providing flexibility in connection with possible acquisitions and other corporate purposes, could, among other things and under some circumstances, have the effect of delaying, deferring or preventing a change in control without any action by shareholders. Our board of directors has authorized the issuance of 2,500,000 shares of Class A Preferred Shares. As of June 30, 2007, there were no remaining shares of our Class A Preferred Shares outstanding.

No other classes or series of preferred stock are currently authorized or outstanding.

Stock Certificates

Our bylaws permit each shareholder to elect whether to hold our stock as an uncertificated security or in the form of a paper stock certificate. Shareholders holding uncertificated securities will receive a written information statement summarizing their holdings. We participate in the Direct Registration System through our transfer agent.

Warrants

The warrants being registered in connection with the January Private Placement are exercisable at $1.75 per share and expire on January 31, 2009. The warrants may be exercised in whole or in part, subject to the limitations provided in the warrants. Any warrant holders who do not exercise their warrants prior to the conclusion of the exercise period will forfeit the right to purchase the shares of common stock underlying the warrants and any outstanding warrants will become void and be of no further force or effect. If at any time while any of the warrants are outstanding we issue common stock or securities convertible into common stock to any person at a price per share of common stock less than the exercise price of the warrants, the exercise price of the warrants will be reduced pursuant to a formula as provided in the warrant. In addition, in the event of a merger, consolidation, or sale of all or substantially all of our assets, the holder of the warrant has the right to receive a warrant substantially similar to the warrant or, at the option of the holder of the warrant, an amount in cash equal to the value of the warrant. If a dividend is declared on our common stock, the exercise price of the warrant will be reduced in accordance with the terms of the warrant and the number of shares of common stock the warrant is exercisable for will be proportionately increased. If we were to offer any securities to its holders of common stock as a class, the holder of the warrant would be entitled to purchase such number of securities as if the warrant holder were a holder of common stock.

68

Holders of the warrants have no voting rights of a shareholder, no liquidation preference, and no dividends will be declared on the warrants.

Transfer Agent and Registrar

Our transfer agent and registrar is Mellon Investor Services.

Securities Authorized For Issuance Under Equity Compensation Plans

In October 1997, Aurora adopted a 1997 Stock Option Plan pursuant to which it was authorized to issue compensatory options to purchase up to 1,000,000 shares of common stock. Prior to the merger closing, Aurora had issued options to purchase a total of 580,000 shares of Aurora’s common stock under this plan, which upon closing the merger, converted into the right to acquire up to 1,160,000 shares of our common stock. Because of the merger, no further awards can be made under this plan.

In 2001, Aurora’s board of directors and shareholders approved the adoption of an Equity Compensation Plan for Non-Employee Directors. This plan provided that each non-employee director is entitled to receive options to purchase 100,000 shares of Aurora’s common stock, issuable in increments of options to purchase 33,333 shares each year over a period of three years, so long as the director continues in office. Prior to the merger closing, Aurora had issued options to purchase a total of 309,997 shares of Aurora common stock under this plan, which upon closing the merger converted to the right to acquire 619,994 shares of our common stock. Because of the merger, no further awards can be made under this plan.

In 2004, our board of directors adopted a 2004 Equity Incentive Plan. Our shareholders approved this plan, also in 2004. This plan provides for the grant of options or restricted shares for compensatory purposes for up to 1,000,000 shares of common stock. The number of shares issued or subject to options issued under this plan totaled 910,500. Although we do not intend to make any further awards under this plan, this plan currently continues to exist.

In March 2006, our board of directors adopted, and in May 2006 our shareholders approved, the 2006 Stock Incentive Plan. This Plan provides for the award of options or restricted shares for compensatory purposes for up to 8,000,000 shares. As of June 30, 2007, we had awarded restricted stock and options to purchase restricted stock in a total amount of 2,742,500 shares, leaving 5,257,500 shares available for future awards.

We have awarded compensatory options and warrants on an individualized basis in addition to awards under our 2004 Equity Incentive Plan. Aurora has also issued compensatory options and warrants on an individualized basis in addition to its 1997 Stock Option Plan and Equity Compensation Plan for Non-Employee Directors.

69

The following chart sets forth certain information as of June 30, 2007, regarding the shares of our common stock (i) issuable upon exercise of options or warrants granted as compensation for services; and (ii) available for grant under existing plans.

Plan Category	No. of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights			Weighted Average Exercise Price of Outstanding Options, Warrants and Rights		No. of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities in the First Column of this Table)
Equity compensation plans approved by security holders		3,364,164		$	2.99		5,257,500
Equity compensation plans and awards not approved by security holders		86,280(a	)		1.69		-
Total		3,450,444		$	2.96		5,257,500

(a) These options and warrants were issued pursuant to the following plans:

Warrants to purchase 56,000 shares (these are Aurora conversion shares originally issued to purchase 28,000 shares of Aurora common stock) were issued to Nathan A. Low and his designees in compensation for investment banking services rendered.

Options to purchase 30,280 shares were issued in two separate individualized compensation arrangements with executive officers and/or directors not pursuant to a formal plan.

Shares Eligible For Future Sale

Our shares of common stock that are eligible for future sale may have an adverse effect on the price of our stock. At June 30, 2007, we had 101,412,966 shares of common stock outstanding. Of this amount, 11,702,580 shares (approximately 11.5% of our outstanding shares prior to the close of this offering) are subject to lock-up and may not be sold through October 31, 2008.

We have two shelf registration statements that are currently effective, which together have registered almost 20.6 million shares of common stock for resale. This includes approximately 296,000 shares issuable upon exercise of certain outstanding warrants and options, with the balance being shares that are already issued. We are maintaining the effectiveness of these registration statements because of registration rights agreements provided in the financings received by us and Aurora on January 31, 2005.

On June 30, 2007, we had options and warrants to purchase 6,746,444 shares of common stock outstanding, and we had still available 5,257,500 shares for issuance under our 2006 Stock Incentive Plan.

Upon completion of this offering, we will have outstanding an aggregate of 101,679,456 shares of common stock, assuming no exercise of outstanding options and warrants. All of the shares sold in this offering will be freely tradable without restriction or further registration under the Securities Act except for shares, if any, which may be acquired by our “affiliates” as that term is defined in Rule 144 under the Securities Act. Persons who may be deemed to be affiliates generally include individuals or entities that control, are controlled by, or are under common control with, us and may include our directors and officers as well as our significant shareholders.

In general, under Rule 144 as currently in effect, a person who has beneficially owned shares of our common stock for at least one year is entitled to sell within any three-month period a number of shares that does not exceed the greater of:

· 1% of the number of shares of our common stock then outstanding, which will equal approximately 1,016,795 shares immediately after this offering; and

· the average weekly trading volume of our common stock on AMEX during the four calendar weeks preceding the filing of a notice on Form 144 with respect to such sale.

70

Sales under Rule 144 are also subject to manner of sale provisions and notice requirements and to the availability of current public information about us. Under Rule 144(k), a person who has not been one of our affiliates at any time during the 90 days preceding a sale, and who has beneficially owned the shares proposed to be sold for at least two years, is entitled to sell those shares without complying with the manner of sale, public information, volume limitation or notice provisions of Rule 144.

Anti-Takeover Provisions

Utah law, our articles of incorporation and our bylaws permit our board of directors to issue undesignated preferred stock. This ability may enable our board of directors to render more difficult or discourage an attempted change of control of us by means of a merger, tender offer, proxy contest, or otherwise. For example, if in the due exercise of its fiduciary obligations, the board of directors were to determine that a takeover proposal is not in our best interest, the board of directors could cause shares of preferred stock to be issued without shareholder approval in one or more private offerings or other transactions that might dilute the voting or other rights of the proposed acquirer, or insurgent shareholder or shareholder group. These provisions are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors. We believe that the benefits of increased protection of our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging such proposals because negotiations of such proposals could result in an improvement of their terms.

LEGAL MATTERS

The validity of the shares of common stock offered in this prospectus will be passed upon for us by Fraser Trebilcock Davis & Dunlap, P.C., Lansing, Michigan.

EXPERTS

Our consolidated financial statements for the years ended December 31, 2006 and December 31, 2005 have been audited by Rachlin Cohen & Holtz LLP, an independent registered public accounting firm, as indicated in their accompanying report. These financial statements and accompanying report are included in this prospectus in reliance on the authority of Rachlin Cohen & Holtz LLP as an expert in auditing and accounting.

The reference to (and inclusion of) the reports of Data & Consulting Services, Division of Schlumberger Technology Corporation, referred to in this prospectus as Schlumberger Holditch, with respect to estimates of proved reserves of oil and natural gas located in Michigan and Indiana, and the reference to (and inclusion of) reports of acquired proved reserves estimated by Netherland, Sewell & Associates, Inc. and Ralph E. Davis Associates, Inc., is made in reliance upon the authority of these firms as experts with respect to such matters.

CHANGE IN INDEPENDENT AUDITORS

On March 23, 2007, after the completion of the audit of our financial statements for the years ended December 31, 2006 and 2005, the Company dismissed Rachlin Cohen & Holtz LLP as its independent auditors. The report of Rachlin Cohen & Holtz LLP on the Company’s financial statements for the years ended December 31, 2006 and 2005, contained no adverse opinion or disclaimer of opinion and was not qualified or modified as to uncertainty, audit scope, or accounting principles. In connection with its audit for the years ended December 31, 2006 and 2005, there have been no disagreements with Rachlin Cohen & Holtz LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Rachlin Cohen & Holtz LLP, would have caused them to make reference thereto in their report on the financial statements for such years except as described in the following paragraph:

As described under Item 3 of the Company’s Form 10-QSB/A for the quarter ended March 31, 2006 (as filed on October 31, 2006), Rachlin Cohen & Holtz LLP advised the Company and the Company disclosed that it had a material weakness resulting from a deficiency in internal controls relating to the lack of accounting recognition given to the stock option grants authorized and approved by the Board of Directors in March 2006, which resulted in (a) the financial statements being modified to account for all of the stock option grants in accordance with the applicable provisions of Statement of Financial Accounting Standards No. 123(R) and (b) remedial actions being taken by the Company. In addition, as described under Item 3 of the Company’s Form 10-QSB/A for the quarter ended June 30, 2006 (as filed on October 31, 2006), the Company validated the remedial actions taken to correct the material weakness in connection with the reporting of stock option compensation.

71

The decision to change firms was approved by our Audit Committee of the Board of Directors.

The Company engaged Weaver and Tidwell L.L.P. as its new independent auditors effective March 23, 2007, and we have relied upon Weaver and Tidwell L.L.P. as an expert in auditing and accounting from that date.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form SB-2 under the Securities Act covering the securities offered by this prospectus. This prospectus, which constitutes a part of that registration statement, does not contain all of the information that you can find in that registration statement and its exhibits. Certain items are omitted from this prospectus in accordance with the rules and regulations of the SEC. For further information about us and the common stock offered by this prospectus, reference is made to the registration statement and the exhibits filed with the registration statement. Statements contained in this prospectus and any prospectus supplement as to the contents of any contract or other document referred to are not necessarily complete and in each instance such statement is qualified by reference to each such contract or document filed as part of the registration statement. We are subject to the information and reporting requirements of the Exchange Act , and are therefore required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read any materials we file with the SEC free of charge at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Copies of all or any part of these documents may be obtained from such office upon the payment of the fees prescribed by the SEC. The public may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the site is www.sec.gov. The registration statement, including all exhibits thereto and amendments thereof, has been filed electronically with the SEC.

You should rely only on the information provided in this prospectus, any prospectus supplement or as part of the registration statement filed on Form SB-2 of which this prospectus is a part, as such registration statement is amended and in effect with the SEC. We have not authorized anyone else to provide you with different information. We are not making an offer to sell these securities in any state where the offer is not permitted. You should not assume that the information in this prospectus, any prospectus supplement or any document incorporated by reference is accurate as of any date other than the date of those documents.

72

FINANCIAL STATEMENTS

INDEX TO FINANCIAL STATEMENTS

	Page
Aurora Oil & Gas Corporation Consolidated Financial Statements
for the years ended December 31, 2006 and 2005
Report of Independent Registered Public Accounting Firm		F-ii
Consolidated Financial Statements
Balance Sheets		F1-F2
Statements of Operations		F-3
Statements of Shareholders’ Equity		F-4
Statements of Cash Flows		F5-F6
Notes to Financial Statements		F7-F28
Supplemental Oil and Gas Information (unaudited)		F29-F32
Aurora Oil & Gas Corporation Unaudited Condensed Consolidated Financial Statements
for the Six Months Ended June 30, 2007 and 2006		F33
Unaudited Condensed Consolidated Financial Statements
Balance Sheet		F34-F35
Statements of Operations		F-36
Statement of Shareholders’ Equity		F-37
Statements of Cash Flows		F38-F39
Notes to Financial Statements		F40-F51

F-i

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Aurora Oil & Gas Corporation and Subsidiaries

Traverse City, Michigan

We have audited the accompanying consolidated balance sheets of Aurora Oil & Gas Corporation and Subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Aurora Oil & Gas Corporation and Subsidiaries as of December 31, 2006, and 2005, and the results of their operations and their cash flows for each of the years then ended in conformity with accounting principles generally accepted in the United States.

As discussed in Note 3 to the consolidated financial statements, the Company changed the manner in which it accounts for share-based payments in 2006.

RACHLIN COHEN & HOLTZ LLP

Miami, Florida

March 13, 2007

F-ii

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
	December 31,			December 31,
	2006			2005
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,735,396		$	11,980,638
Accounts receivable
Oil and natural gas sales		4,082,231			2,409,675
Joint interest owners		3,079,715			4,380,606
Notes receivable
Related party		-			35,720
Other		341,698			208,626
Drilling advances		1,408,860			-
Prepaid expenses and other current assets		264,024			240,242
Short-term derivative instruments		3,552,060			-
Total current assets		14,463,984			19,255,507
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, using full cost accounting:
Proved properties		121,178,499			39,643,003
Unproved properties		41,847,526			37,279,889
Properties held for sale		8,896,568			-
Less: accumulated depletion and amortization		(10,628,438	)		(7,962,138	)
Total oil and natural gas properties, net		161,294,155			68,960,754
Pipelines		4,881,240			-
Other property and equipment		5,093,777			3,723,918
Less: accumulated depreciation		(753,789	)		(113,780	)
Total property and equipment, net		170,515,383			72,570,892
OTHER ASSETS:
Long-term derivative instruments		1,668,573			-
Deposits on purchase of oil and natural gas properties		-			3,206,102
Goodwill		19,373,264			15,973,346
Intangibles (net of accumulated amortization of
$2,946,250 and $1,407,083, respectively)		2,008,750			3,197,917
Other investments		985,706			1,855,977
Debt issuance costs (net of accumulated amortization
of $892,535 and $79,096, respectively)		2,363,898			723,993
Other		1,007,634			38,411
Total other assets		27,407,825			24,995,746
TOTAL ASSETS	$	212,387,192		$	116,822,145

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

F-1

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,			December 31,
	2006			2005
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	5,701,464		$	5,489,657
Accrued exploration, development, and leasehold costs		11,587,850			1,980,922
Short-term bank borrowings		542,788			6,210,000
Current portion of obligations under capital leases		8,868			8,823
Current portion of note payable - related party		-			69,833
Current portion of note payable - other		161,774			-
Current portion of mortgage payable		95,828			72,877
Drilling advances		19,383			-
Deposit on sale of oil and natural gas properties		-			3,509,319
Total current liabilities		18,117,955			17,341,431
LONG-TERM LIABILITIES:
Obligations under capital leases, net of current portion		8,228			2,262
Asset retirement obligation		1,331,893			-
Notes payable		118,547			-
Mortgage payable		3,079,470			2,792,600
Senior secured credit facility		10,000,000			-
Mezzanine financing		40,000,000			40,000,000
Total long-term liabilities		54,538,138			42,794,862
Total liabilities		72,656,093			60,136,293
COMMITMENTS, CONTINGENCIES and SUBSEQUENT EVENT (Notes 11 and 16)
REDEEMABLE CONVERTIBLE PREFERRED STOCK:
Authorized 20,000,000 shares; outstanding none
and 34,984 shares, respectively		-			59,925
SHAREHOLDERS' EQUITY:
Common stock, $.01 par value; authorized 250,000,000
shares; issued and outstanding 101,412,966 shares
and 61,536,261, respectively		1,014,130			615,363
Additional paid-in capital		138,105,626			58,670,698
Accumulated other comprehensive income		5,220,633			-
Accumulated deficit		(4,609,290	)		(2,660,134	)
Total shareholders' equity		139,731,099			56,625,927
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	212,387,192		$	116,822,145

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

F-2

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2006			2005
REVENUES:
Oil and natural gas sales	$	21,591,811		$	6,743,444
Pipeline transportation and marketing		1,179,431			-
Field service and sales		125,611			-
Interest and other		220,592			666,850
Total revenues		23,117,445			7,410,294
EXPENSES:
Production taxes		877,319			506,635
Production and lease operating expense		6,278,131			1,587,205
Pipeline operating expense		643,963			-
Field services expense		90,913			-
General and administrative expense		7,531,718			3,435,507
Oil and natural gas depletion and amortization		2,681,290			767,511
Other assets depreciation and amortization		2,083,191			308,647
Interest expense		4,573,785			1,307,370
Taxes, other		250,884			29,651
Total expenses		25,011,194			7,942,526
LOSS BEFORE MINORITY INTEREST		(1,893,749	)		(532,232	)
MINORITY INTEREST IN (INCOME)
LOSS OF SUBSIDIARIES		(50,898	)		15,960
NET LOSS	$	(1,944,647	)	$	(516,272	)
NET LOSS PER COMMON SHARE-BASIC AND DILUTED	$	(0.02	)	$	(0.01	)
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING - BASIC AND DILUTED		82,288,243			40,622,000

Supplemental Information

Net loss for the years ended December 31, 2006, and 2005, included stock-based compensation expense of $2,206,801 and none, respectively, under Statement of Financial Accounting Standards No. 123 (revised 2004). See Note 3 “Common Stock Options” for additional information.

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

F-3

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

	Year Ended December 31,
	2006						2005
	Shares			Amount			Shares		Amount
COMMON STOCK:
Balance, beginning		61,536,261		$	615,363			13,775,933	$	13,776
Cashless exercise of stock options and warrants		3,280,105			32,801			245,068		2,451
Conversion of redeemable convertible preferred stock to common stock		34,984			349			298,050		298
Issuance of stock in private placement, net of commissions and fees		-			-			4,972,200		4,972
Exercise of stock options prior to merger		-			-			10,000		10
Issuance of stock in connection with the merger between Cadence and Aurora		-			-			39,592,510		567,431
Exercise of stock options and warrants		15,823,457			158,235			2,642,500		26,425
Issuance of stock in connection with public equity offering		19,600,000			196,000			-		-
Issuance of stock in connection with an acquisition		1,378,299			13,783			-		-
Issuance of stock to officers and directors in lieu of compensation		90,000			900
Issuance of stock to related parties in lieu of commission relating to exercise of warrants		1,469,860			14,699			-		-
Rescission of stock option exercises by certain officers		(1,800,000	)		(18,000	)		-		-
Balance, end		101,412,966		$	1,014,130			61,536,261	$	615,363
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning					58,670,698					8,183,025
Cashless exercise of stock options and warrants					(32,801	)				(2,451	)
Conversion of redeemable convertible preferred stock to common stock					59,576					148,727
Issuance of stock in private placement, net of commissions and fees					-					11,020,028
Exercise of stock options prior to merger					-					7,490
Issuance of stock in connection with merger between Cadence and Aurora					-					35,706,179
Stock-based compensation					2,663,814					-
Exercise of stock options and warrants					18,143,714					3,607,700
Issuance of stock in connection with public equity offering					54,309,807					-
Issuance of stock in connection with an acquisition					4,686,217					-
Issuance of stock to officers and directors in lieu of compensation					348,300					-
Issuance of stock to related party in lieu of commission relating to exercise of warrants					(14,699	)				-
Rescission of stock option exercises by certain officers					(729,000	)				-
Balance, end				$	138,105,626				$	58,670,698
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Balance, beginning					-					-
Unrealized gains on derivative instruments					7,903,933					-
Recognition of gain on derivative instruments					(2,683,300	)				-
Balance, end				$	5,220,633					-
ACCUMULATED DEFICIT:
Balance, beginning					(2,660,134	)				(2,099,522	)
Dividends accrued on redeemable convertible preferred stock					(4,509	)				(44,340	)
Net loss					(1,944,647	)				(516,272	)
Balance, end					(4,609,290	)				(2,660,134	)
TOTAL SHAREHOLDERS' EQUITY				$	139,731,099				$	56,625,927

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

F-4

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,944,647	)	$	(516,272	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		4,764,481			1,076,158
Amortization of debt issuance costs		813,715			79,096
Accretion of asset retirement obligation		74,097			-
Stock-based compensation		2,206,801			-
Equity loss of other investments and other		329,902			116,372
Changes in operating assets and liabilities, net of effects of merger and acquisitions:
Accounts receivable		532,765			(3,827,537	)
Drilling advance, net		(1,389,477	)		(387,175	)
Prepaid expenses		(66,173	)		41,634
Other assets		(1,052,297	)		-
Accounts payable and accrued liabilities		(2,024,632	)		1,025,606
Net cash provided by (used in) operating activities		2,244,535			(2,392,118	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and natural gas properties		(42,048,099	)		(29,087,260	)
Leasehold expenditures, net		(26,837,697	)		(18,283,002	)
Acquisition of oil and natural gas properties		(24,011,335	)		-
Sale of oil and natural gas properties		11,489,456			11,504,428
Acquisitions/additions for pipeline, property and equipment		(4,111,780	)		(4,523,706	)
Additions in other investments		(855,070	)		(485,741	)
Other, net		56,788			36,314
Net cash acquired in merger		-			957,020
Net cash used in investing activities		(86,317,737	)		(39,881,947	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net short-term bank borrowings (payments)		(5,775,628	)		5,860,000
Advances on senior secured credit facility		60,000,000			-
Payments on senior secured credit facility		(50,000,000	)		-
Advances on mezzanine financing		-			30,000,000
Advances (payments) on mortgage obligations		(73,205	)		2,865,477
Payments of financing fees on credit facilities		(2,452,786	)		(508,542	)
Distributions to minority interest members		-			(805,000	)
Net proceeds from sales of common stock		54,505,807			14,666,625
Net proceeds from exercise of options and warrants		17,554,949			-
Dividends paid on preferred stock		(20,250	)		(44,340	)
Other, net		89,073			(2,959,099	)
Net cash provided by financing activities		73,827,960			49,075,121
Net (decrease) increase in cash and cash equivalents		(10,245,242	)		6,801,056
Cash and cash equivalents, beginning of the period		11,980,638			5,179,582
Cash and cash equivalents, end of the period	$	1,735,396		$	11,980,638

F-5

 

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31,
2006	2005

NONCASH FINANCING AND INVESTING ACTIVITIES:
Oil and natural gas properties asset retirement obligation	$	1,257,796	$	-
Accrued exploration and development costs on oil and natural gas properties		11,161,730		1,464,032
Accrued leasehold costs		426,120		516,890
Properties acquired in connection with Cadence merger in exchange for equity
—Oil and natural gas properties, net		-		14,647,614
—Intangibles and goodwill		-		20,578,346
—Other investments		-		1,701,238
Field service acquisition through common stock issuance including $600,000 of unproven leasehold		4,686,217		-
Pipeline acquisition, transfer of investment to pipeline assets		1,100,973		-
Oil and natural gas properties capitalized stock-based compensation		457,013		-
SUPPLEMENTAL INFORMATION OF INTEREST PAID:
Cash paid for interest	$	7,286,611	$	2,215,745

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

F-6

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS

Effective May 11, 2006, Cadence Resources Corporation (“Cadence”) and its wholly owned subsidiaries (collectively, the “Company”) amended its articles of incorporation to change its name to Aurora Oil & Gas Corporation (“AOG”). The Company is an oil and natural 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, the Company (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. See Note 2 “Merger with Aurora Energy, Ltd.” for complete discussion of the merger.

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 a portion of the existing production, the Company 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 five 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 the obligation varying from month to month or day to day. As new wells come online and production volume increases, new production will be sold 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. MERGER WITH AURORA ENERGY, LTD.

On October 31, 2005, the Company (formerly Cadence) acquired 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 the Company, 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.

F-7

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The definitive merger agreement was executed on January 31, 2005, whereby Cadence agreed to acquire 100% of the outstanding stock and options of Aurora. Consideration in this transaction consisted of the issuance of two shares of common stock of Cadence for every one share of outstanding stock of Aurora and the issuance of two options for the purchase of stock in Cadence for each option outstanding of Aurora. The purchase price was $41,546,351 determined as follows:

Fair value of Cadence’s common stock outstanding at January 31, 2005(a)	$	33,951,817
Fair value of Cadence’s stock options outstanding at January 31, 2005		536,210
Fair value of Cadence’s warrants outstanding at January 31, 2005		7,058,324
Total purchase price	$	41,546,351

(a) The $33,951,817 was computed as 20,702,327 shares of Cadence common stock multiplied by $1.64, the market price of Cadence common stock as of January 31, 2005, the date of the definitive merger agreement.

In recording the acquisition of Cadence, the following table summarizes the estimated fair value of the assets acquired and the liabilities assumed at the date of acquisition. The Company obtained third-party valuations of certain tangible and intangible assets acquired from Cadence.

Net working capital, adjusted for Cadence operating activity from date of definitive merger agreement to October 31, 2005	$	4,679,078
Oil and natural gas properties and property and equipment, net		14,647,614
Investments		1,503,832
Other mineral properties		197,406
Noncompete agreements		3,265,000
Proprietary business relationships		1,340,000
Goodwill		15,973,346
Redeemable convertible preferred stock		(59,925	)
	$	41,546,351

The following unaudited condensed pro forma results of operations reflect the pro forma combination of Aurora and Cadence as if the combination had occurred at the beginning of fiscal year 2005 compared with the historical results of operations of Aurora for the same period.

	2005
	Historical			Pro Forma
Oil and natural gas revenues	$	6,743,444		$	8,821,869
Production expenses		(2,093,840	)		(2,846,316	)
Net operating revenues		4,649,604			5,975,553
Net loss	$	(516,272	)	$	(4,293,053	)
Net loss per common share - basic and diluted	$	(0.01	)	$	(0.07	)
Weighted average number of common shares outstanding - basic and diluted		40,622,000			58,108,000

NOTE 3. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

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

F-8

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As a result of the reverse acquisition discussed in Note 2 “Merger with Aurora Energy, Ltd.,” 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 financial statements from the date of acquisition. The common stock per share information in the consolidated financial statements for the year ended December 31, 2005, and related notes have been retroactively adjusted to give effect to the reverse merger on October 31, 2005.

Use of Estimates

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

Reclassifications

Certain amounts in the prior year financial statements have been reclassified to conform to current year presentations.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an initial maturity of 3 months or less to be cash equivalents. The Company’s bank accounts periodically exceed federally insured limits. As of December 31, 2006, cash in excess of FDIC limits amounted to approximately $3,123,000. The Company maintains its deposits with high quality financial institutions and, accordingly, believes its credit risk exposure associated with cash is remote.

Accounts Receivable and Credit Policy

Accounts receivable generally consist of amounts due from the sale of oil and natural gas products and from working interest partners for their proportionate share of expenses related to certain oil and natural gas projects. The Company regularly assesses the collectibility of accounts receivable and accrues an allowance when it is believed that a receivable may not be collected. The allowance for doubtful accounts was $79,030 and $0 at December 31, 2006, and 2005, respectively.

The Company extends credit, primarily in the form of uncollateralized oil and natural gas sales and joint interest owner's receivables, to various companies in the oil and natural gas industry which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within the industry and may accordingly impact the Company’s overall credit risk. However, the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which the Company extends credit. Oil and natural gas sales to the primary customer were approximately 62% and 56% of total oil and natural gas sales for the years ended December 31, 2006, and 2005, respectively.

Oil and Natural Gas Properties

The Company utilizes the full cost method of accounting for oil and natural gas properties. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration, and development activities of oil and natural gas, including costs of unsuccessful exploration and overhead charges directly related to acquisition, exploration, and development activities, are capitalized. The Company is currently participating in oil and natural gas exploration and development projects in the Antrim shale of Michigan and the New Albany shale of southern Indiana and western Kentucky. Thus, all capitalized costs of oil and natural gas properties considered proven, are amortized on the unit-of-production method using estimates of proven reserves. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and natural gas properties unless the sale represents a significant portion of oil and natural gas properties and the gain or loss significantly alters the relationship between capitalized costs and proven reserves.

F-9

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Capitalized costs of oil and natural gas properties may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proven reserves plus the lower of cost or fair value of unproven properties. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net cash flows is computed by applying year-end prices of oil and natural gas to estimated future production of proved oil and natural gas reserves as of year end less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.

Asset Retirement Obligation

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.” 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.

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

The change in the ARO for the year ended December 31, 2006, is as follows:

	2006
Beginning balance	$	812,634
Liabilities incurred		719,229
Liabilities settled		(123,809	)
Accretion expense		74,097
Revisions of estimated liabilities		(150,258	)
Ending balance	$	1,331,893

F-10

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pipeline, Other Property and Equipment

Pipeline, other property, and equipment are recorded at original cost and depreciated using the straight-line method over the estimated useful lives. Major improvements, replacements, and renewals are capitalized while ordinary maintenance and repairs are expensed as incurred. Long-lived assets, other than oil and natural gas properties, are evaluated annually for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses for the years ended December 31, 2006, and 2005. A summary of the pipeline, other property, and equipment for years ended December 31, 2006, and 2005, are as follows:

	2006			2005			Useful Life in Years
Land	$	78,000		$	-			N/A
Buildings		3,552,392			3,165,382			40
Furniture and fixtures		328,173			265,115			5-10
Office equipment		65,781			39,579			5
Computer equipment		234,782			148,601			5
Software		188,434			85,070			3-5
Vehicles and other equipment		646,215			20,171			5
Total other property and equipment		5,093,777			3,723,918
Less accumulated depreciation		(341,198	)		(113,780	)
Other property and equipment, net	$	4,752,579		$	3,610,138
Pipelines	$	4,881,240		$	-			15
Less accumulated depreciation		(412,591	)		-
Pipelines, net	$	4,468,649		$	-

Other Investments

The Company uses the equity method of accounting for investments in entities in which the Company has an ownership interest between 20% and 50% and exercises significant influence. Under the equity method of accounting, the Company’s proportionate share of the investees’ net income or loss is included in the results of operations as other income. A summary of the other investments for the years ended December 31, 2006, and 2005, are as follows:

	2006		2005
Investments in unconsolidated subsidiaries:
Hudson Pipeline & Processing Co., LLC	$	-	$	1,224,995
GeoPetra Partners, LLC		721,596		344,502
Mineral properties		197,406		197,406
Other		66,704		89,074
	$	985,706	$	1,855,977

Goodwill

Goodwill represents the excess of the purchase price over the fair value of net assets acquired. The Company follows SFAS No. 142, “Goodwill and Other Intangible Assets,” which requires that goodwill and intangible assets with indefinite useful lives not to be amortized but written down, as needed, based on an impairment test that must occur at least annually or sooner if an event occurs or circumstances change that would more likely than not result in an impairment loss. The amount of goodwill impairment, if any, is measured on projected discounted future operating cash flows using a 10% discount rate. Future impairment of goodwill could result if the Company’s estimated future operating cash flows are not achieved. No impairment loss was recorded for the years ended December 31, 2006, and 2005, respectively.

F-11

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Intangible Assets

Acquired intangible assets, which consist of noncompete agreements, pending patents, and proprietary business relationships, are recorded at fair value or cost and amortized on a straight-line basis using estimated useful lives of 3 to 6 years. A summary of amortization expense over the next 5 years is as follows:

2007	$	1,551,667
2008		194,584
2009		66,666
2010		66,666
2011		66,667
Thereafter		62,500
	$	2,008,750

Revenue Recognition

Oil and natural gas revenue is recognized as income as production is extracted and sold. Revenues from service contracts are recognized ratably over the term of the contract.

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 year ended December 31, 2006, the Company recorded stock-based compensation of $2,663,814 under the 2006 Stock Incentive Plan, 2004 Equity Incentive Plan, and 1997 Stock Option Plan (as described in Note 10 “Common Stock Options”), as well as a certain employment agreement (as described in Note 11 “Contingencies and Commitments”). Of that amount, $2,206,801 has been included in general and administrative expense on the consolidated statement of operations and $457,013 has been capitalized in oil and natural gas properties. The impact on future net income is estimated to be approximately $3,411,000 recognized over the applicable requisite service period of approximately 3 years.

F-12

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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 year ended December 31, 2005:

	2005
Net loss	$	(516,272	)
Deduct total stock-based compensation expense determined under fair value based method for all awards, net of related tax effects		(298,745	)
Pro forma net loss	$	(815,017	)
Loss per share—basic and diluted
As reported	$	(0.01	)
Pro forma	$	(0.02	)

Income Taxes

The Company has adopted the provisions of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (“SFAS No. 109”). Under the asset and liability method of SFAS No. 109, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted income tax rates to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Under SFAS No. 109, the effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Comprehensive Income (Loss)

Comprehensive income (loss) is comprised of net income and other comprehensive income. Other comprehensive income includes income resulting from derivative instruments designated as hedging transactions. The details of comprehensive income (loss) are as follows:

	Years Ended December 31,
	2006			2005
Net Loss	$	(1,944,647	)	$	(516,272	)
Other comprehensive income:
Unrealized gains on derivative instruments		7,903,933			-
Recognition of gains on derivative instruments		(2,683,300	)		-
		5,220,633			-
Comprehensive Income (Loss)	$	3,275,986		$	(516,272	)

Income (Loss) Per Share

Basic net income (loss) per common share is computed based on the weighted average number of common shares outstanding during each period. Diluted net income (loss) per common share is computed based on the weighted average number of common shares outstanding plus other dilutive securities, such as stock options, warrants, and redeemable convertible preferred stock. During the years ended December 31, 2006, and 2005, stock options, warrants, and redeemable convertible preferred stock were excluded in the computation of diluted loss per share because their effect of assumed exercises or conversions was anti-dilutive.

F-13

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 remeasurement 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. The adoption did not have an impact on the Company’s consolidated financial statements.

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 adoption did not have an impact on the Company’s consolidated financial statements.

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 derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. This Interpretation is effective for fiscal years beginning after December 15, 2006. Management believes the adoption of this standard will not have a material impact on the Company’s consolidated financial statements.

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. FASB 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. The provisions of FASB 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 statements.

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

In September 2006, the SEC issued Staff Accounting Bulletin No. 108 (“SAB 108”). Due to diversity in practice among registrants, SAB 108 expresses the SEC staff’s views regarding the process by which misstatements in financial statements are evaluated to determine whether financial statement restatement is necessary. SAB 108 is effective for fiscal years ending after November 15, 2006. SAB 108 did not have a material impact on the Company’s consolidated financial statements.

F-14

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 swaps is to provide a measure of stability to the Company’s cash flow in meeting financial obligations while operating in a volatile natural gas market environment. The derivative 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.

The Company recognizes all derivative instruments as assets or liabilities in the balance sheet at fair value. The accounting treatment for changes in fair value, as specified in SFAS No. 133 “Accounting for Derivative Investments and Hedging Activities,” is dependent upon whether or not a derivative instrument is designated as a hedge. For derivatives designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in Accumulated Other Comprehensive Income on the accompanying balance sheet until the hedged item is recognized in earnings as natural gas revenue. If the hedge has an ineffective portion, that particular portion of the gain or loss would be immediately reported in earnings. The following natural gas swap contracts were in place at December 31, 2006:

Period	Natural Gas Volume per Day		Fixed Price per mmbtu		Fair Value Asset
April 2006—March 2007		5,000 mmbtu	$	8.59	$	1,055,835
April 2007—December 2008		5,000 mmbtu	$	9.00		4,164,798
					$	5,220,633

For the year ended December 31, 2006, the Company has recognized in Accumulated Other Comprehensive Income net unrealized gains of $7,903,933 on the swap contracts that have been designated as cash flow hedges on forecasted sales of natural gas. In addition, for the year ended December 31, 2006, the Company recognized $2,683,300 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.

On January 29, 2007, the Company entered into a costless collar contract for 2,000 mmbtu per day with a ceiling price of $9.00 per mmbtu and a floor price of $7.55 per mmbtu for the period from April 1, 2007 through December 31, 2008.

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 natural 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%.

F-15

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The total purchase price for the Hudson Properties and HPPC was approximately $27,600,000. North also acquired an additional 2.5% membership interest in HPPC effective January 1, 2006, which increased the membership interest to 93.60%.

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 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 natural gas leases from Wabash Energy Partners, L.P. for a purchase price of $11,840,000. The Company was required to deposit into escrow for the seller $3,200,000.

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. Pursuant to the terms of this sales agreement, $3,500,000 was placed in escrow by New Albany on behalf of the Company as a deposit until the closing in February 2006.

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) fourteen gross wells with working interest ranging from 22.5% to 45%; (2) 4,480 (1,657 net) acres; and (3) various pipelines and facilities. The effective date of the sale was July 1, 2006.

2006 - Crossroads Project, Henry, Ohio

Effective 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 $251,225 for disposition costs but will receive future pipeline revenue over the life of the project.

2006 - Bach

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 1-year lock-up period. In addition, the Company entered into 5-year employment agreements with two principals of Bach who agreed not to compete during their employment and for a period of 1 year following termination of their employment.

F-16

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. In addition, the Company retained a 5% carried working interest in the first 50 wells drilled by El Paso Corporation.

2005/2006 - GeoPetra Partners, LLC Investment

In June 2005, the Company acquired a 33% 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 natural gas properties and interest and entities which hold such properties and interests; (ii) areas to be explored and developed for the production of oil and natural gas; and (iii) providing consultation, advice, and recommendations to the members of GeoPetra in connection with other oil and natural 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 December 31, 2006, the Company had contributed $1,192,987 to GeoPetra with net operating losses of $471,391 resulting in an investment balance of $721,596.

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 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’s common stock under his control. The interest rate under the revolving line of credit is Wall Street prime (8.25% and 7.25% at December 31, 2006 and 2005, respectively) with interest payable monthly in arrears. Principal is payable at the expiration of the revolving line of credit agreement. Northwestern Bank has extended the expiration date to October 15, 2007. Northwestern Bank also provides letters of credit for the drilling program (as described in Note 11 “Commitments and Contingencies”). Interest expense on the Northwestern Bank revolving line for the years ended December 31, 2006, and 2005, were $283,163 and $37,326, respectively. As of March 2, 2007, the Company had no outstanding borrowings under this credit facility.

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.

Short-Term Bank Borrowings - Bach

On October 6, 2006, the Company entered into a $175,100 revolving line of credit agreement with Northwestern Bank for general corporate purposes covering the Bach activities. This line of credit is secured by all of Bach’s personal property owned or hereafter acquired. The interest rate under the revolving line of credit is Wall Street prime (8.25% at December 31, 2006) with interest payable monthly in arrears. Principal is payable at the expiration of the revolving line of credit agreement. The expiration date is October 1, 2007. Interest expense for the year ended December 31, 2006, was $2,166.

F-17

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Mortgage and Notes Payable - Bach

The following information details the loans assumed and entered into in connection with the Bach acquisition:

Description of Loan	Date of Loan		Maturity Date		Interest Rate			Principal Amount		2006 Interest Expense
Mortgage payable on building		10/06/06		10/15/09		6.00	%	$	383,026	$	5,352
Notes payable
Vehicles		10/06/06		10/01/10		7.50	%		95,087
Equipment		10/06/06		09/01/07		5.50	%		16,700
Vehicles		12/18/06		12/20/09		7.25	%		70,118
Total notes payable								$	181,905	$	1,816

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 guaranties of three of the Company’s officers. The payment schedule is monthly interest only for the first 3 months starting on November 1, 2005, and, beginning on February 1, 2006, principal and interest in 32 monthly payments of $21,969 with one principal and interest payment of $2,733,994 on October 1, 2008. The interest rate is 6.5% per year. The maturity date is October 1, 2008. Interest expense for the year ended December 31, 2006, and 2005, was $192,814 and $15,732, respectively.

Mezzanine Financing

On December 8, 2005, the Company entered into an Amended Note Purchase Agreement to increase its 5-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.

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).

F-18

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As additional consideration to induce TCW to enter into the mezzanine facility, the Company provided an affiliate of TCW an overriding royalty interest in certain of 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 4%, subject to certain adjustments.

For the years ended December 31, 2006, and 2005, interest incurred for the mezzanine credit facility was $4,714,861, and $2,171,389, respectively. As of March 2, 2007, the Company had total borrowings of $40 million under this credit facility.

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 semiannual reserve report may result in an increase or decrease in credit availability. The security for this facility is a first lien position in certain Michigan Antrim assets; a guarantee from Aurora; and a guarantee from the Company secured by a pledge of its stock in Aurora. This facility matures the earlier of January 31, 2010, or 91 days prior to the maturity of the mezzanine credit facility, unless the Company elects to terminate the commitment earlier pursuant to the terms of the senior secured credit facility.

This facility provides for borrowings tied to BNP’s prime rate (or, if higher, the federal funds effective rate plus 0.5%) or LIBOR-based rate plus 1.25% to 2.0% depending on the borrowing base utilization, as selected by the Company. The borrowing base utilization is the percentage of the borrowing base that is drawn under the senior secured credit facility from time to time. As the borrowing base utilization increases, the LIBOR-based interest rates increase under this facility. For the year ended December 31, 2006, interest incurred was $2,323,732. As of March 2, 2007, the Company had total borrowings of $25 million under this credit facility.

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.

On September 22, 2006, the Company agreed that BNP could establish a syndication thereby allowing various financial institutions to participate under the senior secured credit facility. In addition, effective December 21, 2006, the senior secured credit facility was amended to eliminate the interest coverage ratio covenant for the fiscal quarter ending December 31, 2006, and to modify the 2007 fiscal quarters’ interest coverage ratio covenants.

The senior secured credit facility contains, among other things, a number of financial and nonfinancial 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).

F-19

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Maturities of Debt

Aggregate maturities of long-term debt at December 31, 2006, are as follows:

2007	$	817,485
2008		2,769,517
2009		50,406,497
2010		22,004
Total	$	54,015,503

The Company has incurred deferred financing fees of approximately $406,000 from BNP and approximately $2,850,000 from TCW. These financing fees are being amortized on a straight-line basis over the remaining terms of each debt obligation. Amortization expense is estimated to be $0.8 million per year through 2009.

The Company capitalizes interest on debt related to expenditures made in connection with exploration and development projects that are not subject to the full cost amortization pool. Interest is capitalized only for the period that exploration activities are in progress, Interest is capitalized using a weighted average interest rate based on the outstanding borrowing, and cost of equity of the Company. Capitalized interest was $3,896,645 and $1,146,084 for the years ended December 31, 2006 and 2005, respectively.

NOTE 8. SHAREHOLDERS’ EQUITY

Redeemable Convertible Preferred Stock

On April 23, 2001, the Company’s board of directors authorized 20,000,000 shares of preferred stock with a par value of $0.01 per share and rights and preferences to be determined. During 2003, the Company issued 34,984 shares of its Class A preferred stock to investors at prices ranging from $1.50 to $2.00 per share for aggregate proceeds of $59,925. The shares were convertible to common stock at a price of $1.50 to $2.00 per share under certain terms and conditions. The shares carried a preferred dividend of 15% per annum. In 2006, the shareholders converted all of the 34,984 shares of redeemable convertible preferred stock into common stock.

Common Stock

2005

The Company sold 4,972,200 shares of common stock to unrelated third parties at $2.50 per share in the first quarter of 2005. Total net proceeds from the sale of these shares, after commissions and fees, amounted to $11,025,000. In connection with the sale of these shares, together with the sale of certain common stock by Cadence at that same time, an affiliate of one of the Company’s major shareholders was paid a commission of approximately $976,000 and was issued a warrant to purchase 1,821,000 shares of common stock for services rendered as the placement agent in the transaction. Included in accounts payable at December 31, 2005, is a balance of $50,000 due to this affiliate.

The Company issued 10,000 shares of common stock to a director upon the exercise of options at a price of $0.75 per share.

As a result of the reverse merger, Aurora’s shareholders’ equity reflects the following transactions:

The total outstanding Aurora shares, at the effective date of the merger, of 19,056,183 were in the 2 for 1 exchange.

F-20

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 

Cadence returned 600,000 shares to treasury stock for 300,000 shares it held in Aurora at the time of merger which became 600,000 shares in the 2 for 1 exchange. This is reflected as a reduction to Aurora’s equity.

The total outstanding Cadence shares, at the effective date of the merger, of 21,136,327 were added to Aurora’s equity.

The Company issued 2,642,500 shares of common stock upon the exercise of certain options and warrants at prices ranging from $1.25 to $1.75 per share.

During the last quarter of 2005, certain option and warrant holders exercised their options and warrants under the cashless exercise provision within their options and warrants. This resulted in the issuance of 245,068 shares of the Company’s stock. In December 2005, an additional 2,160,000 shares were issued for cash proceeds of $2,916,000.

2006

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 6-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 20,573,422 shares were issued during the year ended December 31, 2006, representing 15,823,457 shares issued for cash proceeds of $18,301,949, and 4,749,965 shares issued pursuant to cashless exercises of the applicable and other warrants or options. In December 2006, three officers of the Company rescinded option exercises for 600,000 shares each. The option exercise price of $249,000 was returned to each of these officers and in exchange each officer surrendered 600,000 shares of common stock.

In February 2006, a special meeting of the shareholders was held where they voted to increase the number of authorized shares of common stock from 100,000,000 to 250,000,000.

In 2006, a total of 34,984 shares of redeemable convertible preferred stock were converted into 34,984 shares of common stock.

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, 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.

In October 2006, upon the acquisition of the assets of Bach Enterprises, Inc. and its affiliates, 1,378,299 of unregistered common shares were issued. Of the shares issued, 500,000 shares have been placed in an escrow for one year as security for any indemnity obligation resulting from a breach of any representation or warranty in the purchase agreement.

The Company closed on the public offering of 16 million shares on November 7, 2006, and received net proceeds of approximately $44.4 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.

F-21

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Common Stock Warrants

The following table provides information related to stock warrant activity for the years ended December 31:

	2006			2005
	Number of Shares Underlying Warrants			Number of Shares Underlying Warrants
Outstanding at the beginning of the period		19,697,500			-
Granted		-			2,402,000
Assumed upon merger:
2 for 1 exchange of Aurora warrants		-			2,402,000
Cadence warrants		-			17,498,500
Exercised under early exercise program		(13,182,625	)		-
Exercised		(3,589,871	)		(2,596,677	)
Forfeitures and other adjustments		(845,504	)		(8,323	)
Outstanding at the end of the period		2,079,500			19,697,500

As of December 31, 2006, these common stock warrants had an average remaining contractual life of 1.88 years and weighted average exercise price per share of $1.71.

NOTE 9. INCOME TAXES

Income tax expense (benefit) for the years ended December 31 consists of the following:

	2006			2005
Current taxes	$	-		$	-
Deferred taxes		1,862,000			175,500
Less: change in valuation allowance		(1,862,000	)		(175,500	)
Net income tax expense (benefit)	$	-		$	-

The effective income tax rate for the years ended December 31 differs from the U.S. federal statutory income tax rate due to the following:

	2006			2005
Federal statutory income tax rate	$	(661,000	)	$	(175,500	)
Adjustment of estimated income tax provision of prior years(a)		2,523,000			-
Change in valuation allowance		(1,862,000	)		175,500
Net income tax expense (benefit)	$	-		$	-

(a)Adjustment of estimated income tax provision of prior year is due primarily to intangible costs that were expensed in prior year calculation but capitalized and amortized in tax return.

F-22

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The components of the deferred tax assets and liabilities as of December 31 are as follows:

	2006			2005
Deferred tax assets:
Net operating loss carryover	$	11,661,000		$	12,324,600
Stock options		928,000			-
Section 1231 carryover		-			146,900
Capital loss carryover		33,000			66,000
Less valuation allowance		(530,000	)		(2,391,700	)
Deferred tax assets, net		12,092,000			10,145,800
Deferred tax liabilities:
Excess assigned acquisition value		(4,339,000	)		(4,339,000	)
Intangible drilling costs and other		(7,753,000	)		(5,806,800	)
Deferred tax liabilities, net		(12,092,000	)		(10,145,800	)
Net deferred tax assets (liabilities)	$	-		$	-

The Company has net operating loss carryforwards available to offset future federal taxable income of approximately $34,297,000, which expire from 2010 through 2026. Included in this amount is a premerger net operating loss carryforward incurred by Cadence of approximately $16,900,000. The valuation allowance decreased by approximately $1,862,000 and $175,500 as of December 31, 2006, and 2005, respectively. Due to the net operating loss carryforwards, no income tax expense was recorded in 2006 and 2005.

NOTE 10. COMMON STOCK OPTIONS

Stock Option Plans

In October 1997, Aurora adopted a 1997 Stock Option Plan pursuant to which it was authorized to issue compensatory options to purchase up to 1,000,000 shares of common stock. The 1997 Stock Option Plan provides that the total number of shares of common stock of Aurora which may be granted as options shall not exceed 10% of the outstanding shares of the Company as of December 31 of each year for the following year. Aurora issued options to purchase a total of 580,000 shares of Aurora's common stock under this plan which, upon closing the merger, converted into the right to acquire up to 1,160,000 shares of common stock. The maximum term of options granted is 10 years. Because of the merger, no further awards will be made under this plan.

In 2001, Aurora's board of directors and shareholders approved the adoption of an Equity Compensation Plan for Non-Employee Directors. This plan provided that each nonemployee director is entitled to receive options to purchase 100,000 shares of Aurora's common stock, issuable in increments of options to purchase 33,333 shares each year over a period of 3 years, so long as the director continues in office. Prior to the merger closing, Aurora had issued options to purchase a total of 309,997 shares of Aurora common stock under this plan which, upon closing the merger, converted to the right to acquire 619,994 shares of our common stock. Because of the merger, no further awards will be made under this plan.

In 2004, Cadence’s board of directors adopted, and the shareholders approved, a 2004 Equity Incentive Plan. This plan provides for the grant of options or restricted shares for compensatory purposes for up to 1,000,000 shares of common stock. The number of shares issued or subject to options issued under this plan total 910,500. The maximum term of options granted is 10 years. The Company does not currently intend to make any further awards under this plan, the plan continues to exist, and the Company may decide to use it in the future.

F-23

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In March 2006, the Company’s board of directors adopted, and, in May 2006, shareholders approved, the 2006 Stock Incentive Plan. This Plan provides for the award of options or restricted shares for compensatory purposes for up to 8,000,000 shares. 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) of the Company, consultants, and nonemployee directors of the Company and to provide incentives for such persons to exert maximum efforts for the success of the Company and its affiliates. The maximum term for options granted is 10 years.

Activity related to the stock option plans referenced above was as follows for the years ended December 31, 2006, and 2005:

	2006			2005
Options outstanding at beginning of period		1,804,994			943,994
Options granted		2,727,500			146,000
Assumed upon merger:
2 for 1 exchange of Aurora options		-			490,000
Cadence options		-			400,000
Options exercised		(592,732	)		(195,000	)
Options forfeited and other adjustments		(507,266	)		20,000
Options outstanding at end of period		3,432,496			1,804,994

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		4.1	%		4	%
Expected years until exercise		2.5-6.0			10
Expected stock volatility		41	%		41	%
Dividend yield		0	%		0	%

All Stock Options

In addition, Cadence awarded compensatory options and warrants totaling 30,280 on an individualized basis that was considered outside the awards issued under its 2004 Equity Incentive Plan. Aurora also issued compensatory options and warrants totaling 1,400,000 on an individualized basis that was considered outside the awards issued under its 1997 Stock Option Plan and Equity Compensation Plan for Non-Employee Directors. Activity with respect to all stock options is presented below for the years ended December 31, 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		2,727,500			3.89		156,000			3.32
Assumed upon merger:
2 for 1 exchange of Aurora options		-			-		2,856,664			-
Cadence options		-			-		1,124,349			1.79
Options exercised		(3,800,926	)		0.67		(357,500	)		1.20
Forfeitures and other adjustments		(512,266	)		3.65		(31,709	)		0.43
Options outstanding at end of period		4,862,776		$	2.23		6,448,468		$	0.72
Exercisable at end of period		2,775,609		$	1.01
Weighted average fair value of options granted during the period	$	3.85

F-24

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 December 31, 2006, was approximately $6,577,000 and the intrinsic value of the options exercisable at December 31, 2006, was approximately $6,440,000. The intrinsic value of the options exercised during the year ended December 31, 2006, was approximately $4,647,000.

The weighted average remaining life by exercise price as of December 31, 2006, is summarized below:

Range of Exercise Prices	Outstanding Shares		Weighted Average Life		Exercisable Shares		Weighted Average Life
$0.25 - $0.38		749,996		3.7		749,996		3.7
$0.50 - $0.75		1,440,000		2.1		1,440,000		2.1
$1.25 - $1.75		352,000		7.7		352,000		7.7
$2.23 - $3.55		453,280		7.0		80,280		2.6
$3.62		1,000,000		3.9		-		-
$4.45 - $4.70		667,500		8.9		13,333		5.1
$5.19 - $5.54		200,000		4.9		140,000		4.2
$0.25 - $5.54		4,862,776		4.6		2,775,609		3.4

NOTE 11. COMMITMENTS AND CONTINGENCIES

Environmental Risk

Due to the nature of the oil and natural gas business, the Company is exposed to possible environmental risks. The Company manages its exposure to environmental liabilities for both properties it owns as well as properties to be acquired. The Company has historically not experienced any significant environmental liability and is not aware of any potential material environmental issues or claims at December 31, 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 natural gas wells. The existing letters of credit have been issued by Northwestern Bank of Traverse City, Michigan, and are secured only by a Reimbursement and Indemnification Commitment issued by the Company, together with a right of setoff against all of the Company’s deposit accounts with Northwestern Bank. At December 31, 2006, letters of credit in the amount of $1,116,100 were outstanding to the Michigan Supervisor of Wells.

F-25

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Employment Agreement

Effective June 19, 2006, the Company hired Ronald E. Huff to serve as Chief Financial Officer of the Company. The Company has entered into a 2-year Employment Agreement with Mr. Huff, providing for an annual salary of $200,000 per year and an award of a stock bonus in the amount of 500,000 shares of the Company’s common stock on January 1, 2009, so long as he remains employed by the Company through June 18, 2008, which requires the Company to record approximately $2.1 million in stock-based compensation expense over the contract period. If his employment with the Company is terminated prior to this date without just cause or if the Company undergoes a change in control, he will nonetheless be awarded the full 500,000 shares. If his employment is terminated prior to June 18, 2008, due to death or disability, he will receive a prorated stock award. Mr. Huff forfeited the option to purchase 200,000 shares that he was previously awarded for his service as a director of the Company. Mr. Huff remains a director of the Company.

Expiration of Pending Acquisition

On May 9, 2006, North signed a letter of intent with a third party to acquire oil and natural 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 were 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. Based upon further evaluation, the Company allowed the letter of intent to expire and does not intend to pursue the acquisition.

NOTE 12. RELATED PARTY TRANSACTIONS

William Deneau, Thomas Tucker, and John Miller, who are officers , are all involved as equity owners in numerous corporations and limited liability companies that are active in the oil and natural gas business. They also own miscellaneous overriding royalty interests in wells in which the Company has an interest but are operated by unrelated third parties. During 2006, these officers divested themselves of all interests for which the Company served as operator.

On September 7, 2004, the Patricia A. Deneau Trust, DTD 10/12/95, borrowed $100,000 from an Aurora subsidiary to purchase shares of Aurora common stock from an Aurora shareholder. This trust is controlled by William W. Deneau. The loan was evidenced by an unsecured demand promissory note bearing interest at the rate of 4.5% per year. The promissory note has been repaid in full as of May 2006. The shares purchased by the trust were subsequently sold by the trust to a company employee.

Kevin D. Stulp, a director, owns a 33 1/3% working interest in ten wells drilled and operated by TN Oil Company (six of which are dry). The Company owns 650,000 shares of TN Oil Company at a cost of $65,000, which represents approximately a 14% equity interest in TN Oil Company.

In order to replace the collateral pledged to Northwestern Bank for the revolving line of credit, on December 21, 2005, The Denthorn Trust, which is controlled by William W. Deneau, executed a Commercial Guaranty of the Company’s obligation on the Northwestern Bank revolving line of credit, and a Commercial Pledge Agreement pursuant to which The Denthorn Trust has pledged to Northwestern Bank 306,450 shares of our common stock to secure payment of the Company’s indebtedness. Also on December 21, 2005, the Patricia A. Deneau Trust, DTD 10/12/95, which is controlled by William W. Deneau, executed a Commercial Guaranty and a Commercial Pledge Agreement, pursuant to which it pledged 2,944,800 shares of our common stock to Northwestern Bank to secure payment of the Company’s indebtedness. (See Note 7 “Debt.”)

F-26

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 

At the time of the merger, Aurora had a lease for office and storage space from South 31, L.L.C. William W. Deneau and Thomas W. Tucker each owned one-third of South 31, L.L.C. Rent was paid through December 31, 2005, on a lease extending through March 31, 2007. After the Company moved the corporate offices in early December 2005, the Company no longer had a need for the space in the South 31, L.L.C. property. The Company entered into a Settlement Agreement and Mutual Release with South 31, L.L.C. pursuant to which a payment was made to South 31, L.L.C. in the amount of $65,250 on January 27, 2006, and South 31, L.L.C. released the Company from any further obligation on the lease. The Company currently maintains a month-to-month storage lease with South 31, L.L.C. for $600 per quarter.

NOTE 13. RETIREMENT BENEFITS

401(k) Plan

Effective May 1, 2006, the Company established a qualified retirement plan referred to as the 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 12 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 nonelective contributions to the Plan. Company-provided contributions are subject to certain vesting schedules. For the year ended December 31, 2006, the Company contributed $42,350 as a discretionary matching contribution.

2007 Incentive Bonus Plan

The Company has adopted an incentive bonus plan for the year 2007. The incentive bonus plan is available to all full-time employees, excluding officers and employees of subsidiaries. The bonus will be up to 10% of eligible employees’ compensation during the year 2007 if certain objectives are met.

NOTE 14. 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 natural 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 depletion amounted to $8,896,568 at December 31, 2006, of which $7,202,622 is proved and $1,693,946 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 natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The Company has evaluated the proved reserves of these properties (1,046 mmcfe as of December 31, 2006) 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.

F-27

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 

NOTE 15. FOURTH QUARTER ADJUSTMENTS

During the fourth quarter of 2006, the Company modified its approach to estimating capitalized interest. The Company’s original accounting approach was to estimate capitalized interest by identifying specific assets to specific debt. Thus, if debt was not drawn down in a month, no interest was capitalized. However, applicable accounting principles and related guidance provide that the debt need not be specific debt incurred on the asset. Therefore, a company may capitalize interest cost even though the entire development or construction cost of the asset was paid in cash, so long as the company has incurred some form of cost of capital. This change in estimate resulted in additional $3.2 million of capitalized interest for the entire fiscal year which was recorded in the fourth quarter; of this amount, $1.9 million related to prior quarters.

During the fourth quarter of 2006, the Company modified its approach to estimating oil and natural gas depreciation, depletion and amortization (“DD&A”). The Company’s original accounting approach was to amortize all capitalized costs of oil and natural gas properties considered proven developed, on the unit-of-production method using estimates of proven developed reserves. However, applicable accounting principles and related guidance provides that capitalized costs of oil and natural gas properties can be amortized on a unit-of-production method based on all proved oil and natural gas reserves. As of December 31, 2006, all of the Company’s proven reserves were evaluated by an independent petroleum engineering group which resulted in a 89 bcfe increase in proved reserves associated with the full cost pool. This change in estimate from proven developed reserves to proven reserves as well as an updated reserve report resulted in a reduction of $ 2.7 million in oil and natural gas depreciation, depletion and amortization.

NOTE 16. SUBSEQUENT EVENT

On February 7, 2007, the Company entered into a Purchase and Sale Letter Agreement to sell to Harvest Energy, LLC all of the Company’s interest in various developed and undeveloped oil and natural gas properties located in Lane and Ness Counties in the State of Kansas for approximately $1.0 million. As of December 31, 2006, the properties included two net wells and approximately 23,110 net acres. This transaction closed on March 9, 2007.

F-28

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL

GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES

(Unaudited) 

Supplemental Reserve Information. The following information presents estimates of our proved oil and natural gas reserves. The Company retained the service of an independent petroleum consultant (Data & Consulting Services, Division of Schlumberger Technology Corporation) to estimate its proved natural gas reserves at December 31, 2006, and 2005. Included in the tables that follow are proved oil and natural gas reserves located in Michigan that were acquired as a separate property acquisition early in 2006 and proved oil and natural gas reserves acquired in conjunction with the reverse merger with Cadence Resources Corporation effective October 31, 2005. These acquired proved reserves were estimated by Netherland, Sewell & Associates, Inc. and Ralph E. Davis Associates, Inc., respectively. Crude oil and natural gas reserves at December 31, 2006, and 2005, were estimated under the Securities and Exchange Commission (“SEC”) reporting standards.

Estimates of Proved Reserves	Oil (mbbl)			Natural Gas (mmcf)
Proved reserves as of December 31, 2004	-			34,949
Revisions of previous estimates		6			5,382
Purchases of minerals in place		103			1,572
Extensions and discoveries		-			22,107
Production		(10	)		(688	)
Proved reserves as of December 31, 2005		99			63,322
Revisions of previous estimates		(40	)		4,880
Purchases of minerals in place		-			22,843
Extensions and discoveries		45			65,095
Production(a)		(23	)		(2,511	)
Sales of minerals in place		-			(665	)
Proved reserves as of December 31, 2006		81			152,964
Proved developed reserves:
December 31, 2005		70			45,205
December 31, 2006		54			82,580

(a)Production for 2006 does not reflect 142 mcfe of production the Company received in association with certain non-operated wells excluded in the year end reserve report.

The following table summarizes the weighted average year-end prices (net of basis adjustments) used to estimate reserves in accordance with SEC guidelines.

	2006		2005
Natural gas (per mmbtu)	$	5.84	$	9.89
Oil (per barrel)	$	57.81	$	56.41

Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Natural Gas Reserves

The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on crude oil and natural gas reserve and production volumes estimated by the Company’s independent reserve engineers. It may be useful for certain comparison purposes but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.

F-29

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL

GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES

(Unaudited) 

The future cash flows presented below are computed by applying year-end prices to year-end quantities of proved crude oil and natural gas reserves. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved reserves based on year-end costs and assuming continuation of existing economic conditions. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions. Such decision are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions are considered more representative of a range of possible economic conditions that may be anticipated.

The following table sets forth the Standardized Measure of Discounted Future Net Cash Flows from projected production of the Company’s crude oil and natural gas reserves for the years ended December 31, 2006, and 2005.

	2006			2005
Future gross revenues (1)	$	884,186,810		$	632,058,720
Future production costs (2)		(378,345,360	)		(182,710,406	)
Future development costs (2)		(37,324,420	)		(15,073,590	)
Future net cash flows before income taxes	$	468,517,030		$	434,274,724
Future income tax expense (3)		(83,566,133	)		(101,521,160	)
Future net cash flows after income taxes	$	384,950,897		$	332,753,564
Discount at 10% per annum		(254,489,076	)		(179,885,324	)
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	$	130,461,821		$	152,868,240

(1) Crude oil and natural gas revenues are based on year-end prices with adjustments for changes reflected in existing contracts. There is no consideration for future discoveries or risks associated with future production of proved reserves.

(2) Based on economic conditions at year-end. Does not include administrative, general, or financing costs.

(3) Future income taxes are computed by applying the statutory tax rate to future net cash flows reduced by the tax basis of the properties, the estimated permanent differences applicable to future oil and natural gas producing activities, and tax carryforwards.

F-30

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL

GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES

(Unaudited) 

Changes in Standardized Measure of Discounted Future Cash Flows

The following table sets forth the changes in Standardized Measure of Discounted Future Net Cash Flows for the years ended December 31, 2006, and 2005.

	2006			2005
Beginning balance	$	152,868,240		$	32,159,710
Revisions to reserves proved in prior years:
Net change in prices and production costs		(113,774,170	)		85,425,515
Net changes in future development costs		(802,360	)		6,299,524
Net changes due to revisions in quantity estimates		3,484,229			33,335,739
Net change in accretion of discount		19,950,751			(66,761,600	)
Other		(15,976,530	)		38,137,602
Total revisions to reserves provided in prior years		(107,118,080	)		96,436,780
New discoveries and extensions, net of future development and production costs		62,343,872			76,487,826
Purchases of minerals in place		23,605,950			11,834,500
Sales of oil and natural gas produced, net of production costs		(4,756,826	)		(4,696,416	)
Previously estimated development costs incurred		(14,436,361	)		-
Net change in income taxes		17,955,026			(59,354,160	)
Net change in standardized measure of discounted cash flows		(22,406,419	)		120,708,530
Ending balance	$	130,461,821		$	152,868,240

Capitalized Costs Related to Oil and Natural Gas Producing Activities

The following table sets forth the capitalized costs relating to the Company’s natural gas and crude oil producing activities at December 31, 2006, and 2005.

	2006			2005
Proved properties	$	128,381,121		$	39,643,003
Unproved properties		43,541,472			37,279,889
Total oil and natural gas properties		171,922,593			76,922,892
Less accumulated depreciation, depletion, and amortization		(10,628,438	)		(7,962,138	)
Oil and natural gas properties—net	$	161,294,155		$	68,960,754

Costs Incurred in Oil and Natural Gas Producing Activities

The acquisition, exploration, and development costs disclosed in the following table are in accordance with definitions in SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” Acquisition costs include costs incurred to purchase, lease, or otherwise acquire property. Exploration costs include exploration expenses, additions to exploration wells in progress, and depreciation of support equipment used in exploration activities. Development costs include additions to production facilities and equipment, additions to development wells in progress and related facilities, and depreciation of support equipment and related facilities used in development activities.

F-31

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL

GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES

(Unaudited) 
 

The following table sets forth capitalized costs incurred related to the Company’s oil and natural gas activities for the years ended December 31, 2006, and 2005.

	2006			2005
Property acquisition costs
Proved	$	24,011,335		$	22,763,734
Unproved		27,554,145			19,607,099
Exploration		8,347,848			781,586
Development		46,575,829			29,707,367
Total costs incurred(a)		106,489,157			72,859,786
Sales of oil and natural gas properties		(11,489,456	)		(11,504,428	)
Total	$	94,999,701		$	61,355,358

(a)Total costs incurred include (i) capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $1.3 million and $0 million for years ended December 31, 2006, and 2005, respectively, and (ii) interest expense on unproven properties of $3.9 million and $1.1 million for years ended December 31, 2006, and 2005, respectively. Certain non-cash transactions are included as follows: (1) 2006 asset retirement obligation and capitalized stock compensation of $1.3 million and $0.45 million, respectively, (2) net transfer of $0.31 million from 2005 deposits to 2006 oil and natural gas properties, and (3) the 2005 fair market value of properties received from Cadence in the merger valued at $22.4 million.

Results of Operations

The following table sets forth the results of operations related to natural gas activities for the Company for the years ended December 31, 2006, and 2005.

	2006			2005
Oil and natural gas sales	$	21,591,811		$	6,743,444
Production and lease operating costs		(7,155,450	)		(2,093,840	)
Depreciation and depletion		(2,681,290	)		(767,511	)
Results of producing activities	$	11,755,071		$	3,882,093

These results of operations do not include a provision for income taxes due to the net operating loss carryforward available to offset taxable income during both 2006 and 2005.

F-32

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2007, and 2006

F-33

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

	June 30, 2007
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	720,498
Accounts receivable
Oil and natural gas sales		4,982,887
Joint interest owners		1,004,172
Notes receivable		-
Prepaid expenses and other current assets		817,825
Short-term derivative instruments		2,201,716
Total current assets		9,727,098
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, using full cost accounting:
Proved properties		142,200,610
Unproved properties		54,200,686
Properties held for sale		-
Less: accumulated depletion and amortization		(12,151,898	)
Total oil and natural gas properties, net		184,249,398
Pipelines		5,019,906
Other property and equipment		5,400,816
Less: accumulated depreciation		(1,114,508	)
Total property and equipment, net		193,555,612
OTHER ASSETS:
Long-term derivative instruments		560,718
Goodwill		19,373,264
Intangibles (net of accumulated amortization of $3,722,085 and $2,946,250, respectively)		1,232,915
Other investments		901,268
Debt issuance costs (net of accumulated amortization of $1,329,051 and $892,535, respectively)		2,054,648
Other		994,035
Total other assets		25,116,848
TOTAL ASSETS	$	228,399,558

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

F-34

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

(continued)

	June 30, 2007
	(Unaudited)
LIABILITIES AND SHARE HOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	5,635,186
Accrued exploration, development, and leasehold costs		3,294,213
Short-term bank borrowings		1,418,615
Current portion of obligations under capital leases		6,561
Current portion of note payable—other		100,768
Current portion of mortgage payable		100,008
Drilling advances		565,891
Total current liabilities		11,121,242
LONG-TERM LIABILITIES:
Obligations under capital leases, net of current portion		4,984
Asset retirement obligation		989,885
Notes payable		163,402
Mortgage payable		3,028,733
Senior secured credit facility		35,000,000
Mezzanine financing		40,000,000
Total long-term liabilities		79,187,004
Total liabilities		90,308,246
Minority interest in net assets of subsidiaries		85,828
COMMITMENTS, CONTINGENCIES AND SUBSEQUENT EVENT (Note 9 and Note 11 )
SHAREHOLDERS’ EQUITY
Common stock, $0.01 par value; authorized 250,000,000 shares; issued and outstanding 101,589,456 shares and 101,412,966 shares, respectively		1,015,895
Additional paid-in capital		139,347,287
Accumulated other comprehensive income		2,762,434
Accumulated deficit		(5,120,132	)
Total shareholders’ equity		138,005,484
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	228,399,558

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

F-35

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Six Months Ended June 30
	2007			2006
REVENUES:
Oil and natural gas sales	$	12,532,005		$	10,941,220
Pipeline transportation and marketing		286,932			242,299
Field service and sales		249,602			-
Interest and other		474,758			181,631
Total revenues		13,543,297			11,365,150
EXPENSES:
Production taxes		566,969			445,825
Production and lease operating expense		4,126,700			2,853,374
Pipeline operating expense		177,802			137,484
Field services expense		200,096			-
General and administrative expense		4,233,701			3,242,713
Oil and natural gas depletion and amortization		1,523,460			2,010,383
Other assets depreciation and amortization		1,142,104			1,013,783
Interest expense		2,050,403			3,564,154
Taxes (refunds), other		(53	)		29,361
Total expenses		14,021,182			13,297,077
INCOME (LOSS) BEFORE MINORITY INTEREST		(477,885	)		(1,931,927	)
MINORITY INTEREST IN INCOME OF SUBSIDIARIES		(32,957	)		(17,919	)
NET INCOME (LOSS)	$	(510,842	)	$	(1,949,846	)
NET INCOME (LOSS) PER COMMON SHARE —BASIC	$	(0.01	)	$	(0.03	)
—DILUTED
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING —BASIC		101,602,875			70,265,281
—DILUTED

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

F-36

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Unaudited)

	Six Months Ended June 30,
	2007						2006
COMMON STOCK:	Shares			Amount			Shares		Amount
Balance, beginning		101,412,966		$	1,014,130			61,536,261	$	615,363
Cashless exercise of stock options and warrants		78,158			782			3,280,105		32,801
Conversion of redeemable convertible preferred stock to common stock		-			-			23,334		233
Exercise of stock options and warrants		173,332			1,733			15,565,457		155,655
Issuance of stock to officers and directors in lieu of compensation		-			-			90,000		900
Issuance of stock to related parties in lieu of commission relating to exercise of warrants		-			-			1,469,860		14,699
Adjustment to stock ledger		(75,000	)		(750	)		-		-
Balance, ending		101,589,456			1,015,895			81,965,017		819,651
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning					138,105,626					58,670,698
Cashless exercise of stock options and warrants					(782	)				(32,801	)
Conversion of redeemable convertible preferred stock to common stock					-					39,768
Costs of equity offerings					(10,096	)				-
Stock-based compensation					1,335,523					757,442
Exercise of stock options and warrants					63,266					17,988,794
Issuance of stock to officers and directors in lieu of compensation					-					348,300
Issuance of stock to related party in lieu of commission relating to exercise of warrants					-					(14,699	)
Adjustment to stock ledger					(146,250	)				-
Balance, ending					139,347,287					77,757,502
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Balance, beginning					5,220,633					-
Changes in fair value of derivative instruments					(1,099,949	)				1,754,365
Recognition of gain on derivative instruments					(1,358,250	)				(792,350	)
Balance, ending					2,762,434					962,015
ACCUMULATED DEFICIT:
Balance, beginning					(4,609,290	)				(2,660,134	)
Dividends accrued on redeemable convertible preferred stock					-					(4,295	)
Net loss					(510,842	)				(1,949,846	)
Balance, end					(5,120,132	)				(4,614,275	)
TOTAL SHAREHOLDERS’ EQUITY				$	138,005,484				$	74,924,893

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

F-37

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

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

F-38

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited-continued)

		Six Months Ended June 30,
		2007			2006
NONCASH FINANCING AND INVESTING ACTIVITIES:
Oil and natural gas properties asset retirement obligation	$	(370,842	)	$	976,340
Accrued exploration and development costs on oil and natural gas properties		2,945,868			1,716,283
Accrued leasehold costs		348,345			427,859
Pipeline acquisition, transfer of investment to pipeline assets		-			1,100,973
Oil and natural gas properties capitalized stock-based compensation		133,767			365,293
Conversion of redeemable convertible preferred stock to common stock		-			40,001
Conversion of accounts receivable to long-term notes receivable		26,349			60,000
Vehicle purchase through financing		94,407			-
Common stock received in connection with the sale of mining claims		56,885			-
SUPPLEMENTAL INFORMATION OF INTEREST AND INCOME TAXES PAID:
Interest, net of amount capitalized of $1,857,689 and $646,977, respectively	$	1,352,151		$	2,783,248
Income taxes		107,700			5,463

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

F-39

 

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS

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

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

The Company’s revenue, profitability, and future rate of growth are substantially dependent on prevailing prices of natural gas and oil. Historically, the energy markets have been very volatile, and it is likely that oil and natural gas prices will continue to be subject to wide fluctuations in the future. A substantial or extended decline in natural gas and oil prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows, and access to capital and on the quantities of natural gas and oil reserves that can be economically produced.

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

Basis of Presentation

The financial information included herein is unaudited which has been derived from our audited consolidated financial statements as of December 31, 2006. Such information includes all adjustments (consisting solely of normal recurring adjustments), which are, in the opinion of management, necessary for a fair presentation of financial position, results of operations, and cash flows for the interim periods. The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year.

Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission. These condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in our Annual Report on Form 10-KSB for the year ended December 31, 2006.

F-40

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Reclassifications

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

Principles of Consolidation

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

Use of Estimates

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

Asset Retirement Obligation

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

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

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

F-41

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

Derivative Instruments

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

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

Period	Type of Contract		Natural Gas Volume per Day		Price per mmbtu		Fair Value Asset (Liability)
April 2007—December 2008		Swap		5,000 mmbtu	$	9.00	$	2,481,798
April 2007—December 2008		Collar		2,000 mmbtu	$	7.55/$ 9.00		129,597
January 2009—December 2009		Swap		7,000 mmbtu	$	8.72		72,968
January 2010—March 2011		Swap		7,000 mmbtu	$	8.68		78,071
Total Estimated Fair Value							$	2,762,434

For the six months ended June 30, 2007, the Company has recognized in Comprehensive Income changes in fair value of $(1,099,949) on the contracts that have been designated as cash flow hedges on forecasted sales of natural gas. See “Comprehensive Income (Loss)” found in this note section. For the six months ended June 30, 2007, and 2006, the Company recognized $1,358,250 and $792,350, respectively, in net gains from hedging activities included in oil and natural gas revenues.

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

F-42

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Financial Instruments

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

Stock-Based Compensation

On January 1, 2006, the Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R), to account for stock-based employee compensation. Among other items, SFAS No. 123R eliminates the use of Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and the intrinsic value method of accounting and requires companies to recognize the cost of employee services received in exchange for stock-based awards based on the grant date fair value of those awards in their financial statements. The Company elected to use the modified prospective method for adoption, which requires compensation expense to be recorded for all unvested stock options beginning in the first quarter of adoption. For stock-based awards granted or modified subsequent to January 1, 2006, compensation expense, based on the fair value on the date of grant, will be recognized in the financial statements over the vesting period. The Company utilizes the Black-Scholes option pricing model to measure the fair value of stock options. To the extent compensation cost relates to employees directly involved in oil and natural gas exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expenses. See Note 8 “Common Stock Options” which fully describes the Company’s stock-based compensation plans.

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

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

Comprehensive Income (Loss)

Comprehensive income (loss) is comprised of net income and other comprehensive income. Other comprehensive income includes income resulting from derivative instruments designated as hedging transactions. The details of comprehensive income (loss) are as follows for the periods indicated:

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

F-43

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Income (Loss) Per Share

Basic net income (loss) per common share is computed based on the weighted average number of common shares outstanding during each period. Diluted net income (loss) per common share is computed based on the weighted average number of common shares outstanding plus other dilutive securities, such as restricted stock grants, stock options, warrants, and redeemable convertible preferred stock. For the three months ended June 30, 2007, the effect of stock options representing 2,395,780 common shares were excluded from the calculation of diluted earnings per share as their inclusion would have been antidilutive because the exercise price of the options was greater than the average market price of the common stock during the period. All dilutive securities were excluded in the computation of diluted loss per share for all other periods because their effect of assumed exercises or conversions was anti-dilutive and, accordingly, basic and dilutive weighted average shares are the same.

NOTE 3. RECENT ACCOUNTING PRONOUNCEMENTS

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

NOTE 4. ACQUISITIONS AND DISPOSITIONS

2007 - Mining Claims

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

2007 - Kansas Project

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

NOTE 5. OIL AND NATURAL GAS PROPERTIES HELD FOR SALE

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

F-44

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6. DEBT

Short-Term Bank Borrowings

The Company has a $5.0 million revolving line of credit agreement with Northwestern Bank for general corporate purposes. As of June 30, 2007, our total borrowing capacity available under this facility was $3.6 million. To secure this line of credit, two trusts controlled by an executive officer pledged certain shares of the Company’s common stock under his control. The interest rate under the revolving line of credit is Wall Street prime (8.25% at June 30, 2007, and 2006, respectively) with interest payable monthly in arrears. Principal is payable at the expiration of the revolving line of credit agreement. Northwestern Bank has extended the expiration date to October 15, 2007. Northwestern Bank also provides letters of credit for the drilling program (as described in Note 9 “Commitments and Contingencies”). Interest expense on the Northwestern Bank revolving line for the six months ended June 30, 2007, and 2006, was $6,882 and $178,454, respectively.

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

On October 6, 2006, Bach entered into a $175,100 revolving line of credit agreement with Northwestern Bank for general company purposes. Effective April 16, 2007, Northwestern Bank increased the borrowing capacity under the revolving line of credit to $0.5 million. This line of credit is secured by all of Bach’s personal property owned or hereafter acquired and is non-recourse to the Company. The interest rate under the revolving line of credit is Wall Street prime (8.25% at June 30, 2007) with interest payable monthly in arrears. Principal is payable at the expiration of the revolving line of credit agreement. The expiration date is October 1, 2007. Interest expense for the six months ended June 30, 2007, was $1,343.

Mortgage and Notes Payable - Bach

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

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

Mortgage Payable

On October 4, 2005, the Company entered into a mortgage loan from Northwestern Bank in the amount of $2,925,000 for the purchase of an office condominium and associated interior improvements. The security for this mortgage is the office condominium real estate. The payment schedule is monthly interest only for the first 3 months starting on November 1, 2005, and, beginning on February 1, 2006, principal and interest in 32 monthly payments of $21,969 with one principal and interest payment of $2,733,994 on October 1, 2008. The interest rate is 6.5% per year. The maturity date is October 1, 2008. As of June 30, 2007, the principal amount outstanding was $2,754,154. Interest expense for the six months ended June 30, 2007, and 2006, was $69,336 and $99,734, respectively.

F-45

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note Payable - Directors and Officers Insurance

On November 13, 2006, the Company entered into a financing agreement with AICCO, Inc. to finance the insurance premium related to director and officer liability insurance coverage in the amount of $184,230. A monthly payment of $15,807 is required beginning November 30, 2006, through August 1, 2007. The interest rate is 7.01% per year. As of June 30, 2007, the principal amount outstanding was $31,342. Interest expense for the six months ended June 30, 2007, $2,273.

Mezzanine Financing

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

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

As part of the mezzanine credit facility, the Company provided an affiliate of TCW an overriding royalty interest in certain properties to be drilled or developed in the Counties of Alcona, Alpena, Charlevoix, Cheboygan, Montmorency, and Otsego in the State of Michigan. The overriding royalty interest is 4%, subject to certain adjustments.

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

Senior Secured Credit Facility

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

F-46

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

This facility provides for borrowings tied to BNP’s prime rate (or, if higher, the federal funds effective rate plus 0.5%) or LIBOR-based rate plus 1.25% to 2.0% depending on the borrowing base utilization, as selected by the Company. The borrowing base utilization is the percentage of the borrowing base that is drawn under the senior secured credit facility from time to time. As the borrowing base utilization increases, the LIBOR-based interest rates increase under this facility. As of June 30, 2007, interest on the borrowings had a weighted average interest rate of 7.125%. For the six months ended June 30, 2007, and 2006, interest and fees incurred for the senior secured credit facility was $979,235 and $1,106,397, respectively.

The senior secured credit facility contains, among other things, a number of financial and non-financial covenants relating to restricted payments (as defined), loans or advances to others, additional indebtedness, incurrence of liens, a prohibition on the Company’s ability to prepay the mezzanine credit facility, geographic limitations on operations to the United States, and maintenance of certain financial and operating ratios, including current ratio and specified coverage ratios (collateral coverage and proved developed producing reserves coverage ratios). Effective December 21, 2006, the senior secured credit facility was amended to eliminate the interest coverage ratio covenant for the fiscal quarter ending December 31, 2006, and to modify the 2007 fiscal quarters’ interest coverage ratio covenants.

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

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

The Company has incurred deferred financing fees of approximately $406,000 from BNP and approximately $2,850,000 from TCW. The deferred financing fees are being amortized on a straight-line basis over the remaining terms of each debt obligation. Amortization expense is estimated to be $0.8 million per year through 2009. Amortization expense was $446,790 and $383,146 for the six months ended June 30, 2007, and 2006, respectively. In addition, the Company incurs various annual fees associated with unused commitment and agency fees. These annual fees are recorded to interest expense.

The Company capitalizes interest on debt related to expenditures made in connection with exploration and development projects that are not subject to the full cost amortization pool. Interest is capitalized only for the period that exploration activities are in progress. Interest is capitalized using a weighted average interest rate based on the outstanding borrowing, and cost of equity of the Company. Capitalized interest was $1,857,689 and $646,977 for the six months ended June 30, 2007, and 2006, respectively.

F-47

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7. SHAREHOLDERS’ EQUITY

Common Stock

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

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

In February and March 2007, 93,332 common stock options were exercised by various Company directors under the existing stock option plans at an exercise price of $0.375 per share. The Company received $35,000 in conjunction with these exercises.

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

Common Stock Warrants

The following table provides information related to stock warrant activity for the six months ended June 30, 2007:

	Number of Shares Underlying Warrants			Weighted Average Exercise Price			Weighted Average Contract Life in Years
Outstanding at the beginning of the period		2,079,500		$	1.71			1.98
Granted		-			-
Exercised		(78,158	)		(1.25	)		0.24
Forfeitures and other adjustments		(49,342	)		(1.25	)		0.24
Outstanding at the end of the period		1,952,000		$	1.74			1.59

NOTE 8. COMMON STOCK OPTIONS

As of June 30, 2007, the Company maintains four stock option plans that are fully described in Note 8 “Common Stock Options” in the Company’s Annual Report on Form 10-KSB for the year-ended December 31, 2006. These stock option plans provide for the award of options or restricted shares for compensatory purposes. The purpose of these plans is to promote the interests of the Company by aligning the interests of employees (including directors and officers who are employees), consultants, and non-employee directors of the Company and to provide incentives for such persons to exert maximum efforts for the success of the Company and its subsidiaries.

The following table provides activity for the stock option plans referenced above for the six months ended June 30, 2007:

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

F-48

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

All Stock Options

In addition, the Company has awarded compensatory options and warrants totaling 1,430,280 on an individualized basis that was considered outside the awards issued under its existing stock option plans. The following table provides activity with respect to all stock options awarded for the six months ended June 30, 2007:

	Number of Shares Underlying Options			Weighted Average Exercise Price		Aggregate Intrinsic Value(a)
Options outstanding at beginning of period		4,862,776		$	2.23
Options granted		185,000			3.35
Options exercised		(173,332	)		0.38
Forfeitures and other adjustments		(80,000	)		5.03
Options outstanding at end of period		4,794,444		$	2.30	$	3,339,505
Exercisable at end of period		3,139,775		$	1.55	$	3,339,505
Weighted average fair value of options granted during period	$	1.20

(a) The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option. The intrinsic value of the options exercised during the six months ended June 30, 2007, was approximately $304,000.

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

Period to be Recognized	2007		2008		2009		2010		Total Unrecognized Compensation Expense
1st Quarter	$	-	$	428,053	$	31,996	$	1,146
2nd Quarter		-		360,689		14,664		-
3rd Quarter		587,474		117,728		5,194		-
4th Quarter		547,100		97,844		2,893		-
Total	$	1,134,574	$	1,004,314	$	54,747	$	1,146	$	2,194,781

F-49

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

NOTE 9. COMMITMENTS AND CONTINGENCIES

Environmental Risk

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

Letters of Credit

For each salt water disposal well drilled in the State of Michigan, the Company is required to issue a letter of credit to the Michigan Supervisor of Wells. The Supervisor of Wells may draw on the letter of credit if the Company fails to comply with the regulatory requirements relating to the locating, drilling, completing, producing, reworking, plugging, filling of pits, and clean up of the well site. The letter of credit or a substitute financial instrument is required to be in place until the salt water disposal well is plugged and abandoned. For drilling natural gas wells, the Company is required to issue a blanket letter of credit to the Michigan Supervisor of Wells. This blanket letter of credit allows the Company to drill an unlimited number of natural gas wells. The existing letters of credit have been issued by Northwestern Bank of Traverse City, Michigan, and are secured only by a Reimbursement and Indemnification Commitment issued by the Company, together with a right of setoff against all of the Company’s deposit accounts with Northwestern Bank. At June 30, 2007, letters of credit in the amount of $1,056,100 were outstanding to the Michigan Supervisor of Wells.

Employment Agreement

Effective June 19, 2006, the Company hired Ronald E. Huff to serve as Chief Financial Officer of the Company. The Company has entered into a 2-year Employment Agreement with Mr. Huff, providing for an annual salary of $200,000 per year and an award of a stock bonus in the amount of 500,000 shares of the Company’s common stock on January 1, 2009, so long as he remains employed by the Company through June 18, 2008, which requires the Company to record approximately $2.1 million in stock-based compensation expense over the contract period. If his employment with the Company is terminated prior to this date without just cause or if the Company undergoes a change in control, he will nonetheless be awarded the full 500,000 shares. If his employment is terminated prior to June 18, 2008, due to death or disability, he will receive a prorated stock award. Mr. Huff forfeited the option to purchase 200,000 shares that he was previously awarded for his service as a director of the Company. Mr. Huff remains a director of the Company.

Equipment Sale - Leaseback Agreement

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

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fry Well Loss

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

NOTE 10. RELATED PARTY TRANSACTION

Effective May 30, 2007, the board of directors named John C. Hunter as Vice President of Exploration and Production. He has worked for AOG since 2005 as Senior Petroleum Engineer. Prior to that, Mr. Hunter was instrumental in certain projects associated with the Company’s New Albany shale play. Over a series of agreements with the Company, Mr. Hunter (controlling member of Venator Energy, LLC) has acquired 1.25% working interest in certain leases. The leases cover approximately 132,600 acres (1,658 net) in certain counties located in Indiana. The 1.25% carried working interest shall be effective until development costs exceed $30 million. Thereafter, participation may continue as a standard 1.25% working interest owner. The Company is entitled to recovery of 100% of development costs (plus interest at a rate of 6.75% per annum compounded annually) from 85% of the net operating revenue generated from oil and gas production developed directly or indirectly in the area of mutual interest covered by the agreement. As of June 30, 2007, there is no production associated with this working interest and development costs were approximately $12.0 million.

Effective July 1, 2004, Aurora Energy, Ltd., (“AEL”), entered into a Fee Sharing Agreement with Mr. Hunter as compensation for bringing Bluegrass Energy Enhancement Fund, LLC (“Bluegrass”) and AEL together for the development of the 1500 Antrim and Red Run Projects in Michigan. At this time, AEL and Bluegrass have discontinued leasing activities in both projects. In the 1500 Antrim project, there are 23,989.41 acres. Mr. Hunter's carried working interest share of 0.8333% is approximately 199.95 net acres. The carried working interest relates to the first 55 wells that are drilled in the area of mutual interest. Thereafter, Mr. Hunter would pay his proportionate share of working interest expenses. Currently, there are no producing wells. The Red Run project contains 12,893.64 acres. Mr. Hunter's carried working interest share of 0.8333% is approximately 107.44 net acres. The carried working interest relates to the first 55 wells that are drilled in the area of mutual interest. Thereafter, Mr. Hunter would pay his proportionate share of working interest expenses. Currently, there are 3 wells permitted for the Red Run project and one well was temporarily abandoned in June 2007.

NOTE 11. SUBSEQUENT EVENT

On July 30, 2007, the Company purchased from Horizontal Systems, Inc. its working interest in various undeveloped oil and natural gas leases located in Knox County, Indiana for approximately $1.2 million pursuant to a Sale and Assignment of Oil and Gas Interests Agreement. The properties included 25% working interest in one well and approximately 9,642 net acres.

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APPENDIX A

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used in this prospectus.

bbl.  Stock tank barrel, or 42 U.S. gallons liquid volume, used in this prospectus in reference to crude oil or other liquid hydrocarbons.

bcf.  Billion cubic feet of natural gas.

bcfe.  Billion cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

Biogenic gas.  Gas produced by methanogenic bacteria or microbes. Predominately methane gas with <1% higher chain hydrocarbons.

btu or British thermal unit.  The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Casing.  Steel pipe used in wells to seal off fluids from the bore hole and to prevent the walls of the hole from sloughing off or caving. There may be several strings of casing in a well, one inside the other.

Completion.  The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Compression.  Process of taking a gas or compressible fluid from a low pressure to a higher pressure.

Developed acreage.  The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well.  A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Dewatering.  The system whereby brine water is removed from the well in order to allow the gas/oil to be released. Pumping mechanisms are usually used for this process. New wells may have great amounts of water, which must first be removed. As water is removed, gas/oil production usually increases.

Drilling locations.  Total gross locations specifically quantified by management to be included in the Company’s multi-year drilling activities on existing acreage. The Company’s actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.

Dry well.  A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Exploratory well.  A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

Field.  An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Finding and development costs.  Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Formation.  An identifiable layer of rocks named after its geographical location and dominant rock type.

A-1

Gross acres, gross wells or gross reserves.  The total acres, wells, or reserves as the case may be, in which a working interest is owned.

Lease.  A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land.

Leasehold.  Mineral rights leased in a certain area to form a project area.

mbbls.  Thousand barrels of crude oil or other liquid hydrocarbons.

mcf.  Thousand cubic feet of natural gas.

mcf/d.  mcf per day.

mcfe.  Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

mmbbls.  Million barrels of crude oil or other liquid hydrocarbons.

mmbtu.  Million British Thermal Units.

mmcf.  Million cubic feet of natural gas.

mmcf/d.  mmcf per day.

mmcfe.  Million cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

mmcfe/d.  mmcfe per day.

Net acres, net wells, or net reserves.  The sum of the fractional working interest owned in gross acres, gross wells, or gross reserves, as the case may be.

Overriding royalty interest.  Is similar to a basic royalty interest except that it is created out of the working interest. For example, an operator possesses a standard lease providing for a basic royalty to the lessor or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil and gas produced. The 7/8 in this case is the 100% working interest the operator owns. This operator may assign his working interest to another operator subject to a retained 1/8 overriding royalty. This would then result in a basic royalty of 1/8, an overriding royalty of 1/8 and a working interest of 3/4. Overriding royalty interest owners have no obligation or responsibility for developing and operating the property. The only expenses borne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable.

Pay zone.  The geologic formation where the gas/oil is located.

PDP.  Proved developed producing.

Play/Trend.  A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.

Plugging and abandonment.  Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Present value of future net revenues (PV-10).  The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such a general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

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PV-10.  Present value of future net revenues.

Production.  Natural resources, such as oil or gas, taken out of the ground.

Productive well.  A well that is found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Project.  A targeted development area where it is probable that commercial gas can be produced from new wells.

Prospect.  A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed non-producing reserves.  Proved developed reserves that are shut-in or otherwise not producing.

Proved developed producing reserves.  Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves.  The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable from known reservoirs under current economic and operating conditions, operating methods, and government regulations.

Proved undeveloped reserves.  Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Rat-hole.  An additional well bore drilled below the pay zone, usually for the purpose of collecting water and pumping water to the surface in a manner which keeps a fluid level below the pay zone.

Recompletion.  The process of re-entering an existing well bore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reserves.  Oil, gas and gas liquids thought to be accumulated in known reservoirs.

Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible nature gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Salt water disposal well.  A well into which salt water and other liquid substances are pumped for disposal purposes.

Schlumberger Holditch.  Schlumberger Technology Corporation, formerly known as Schlumberger Holditch & Associates.

Shale.  A clastic (gr. Klastos, “broken”) rock composed of predominantly clay-sized particles consisting of clay minerals, quartz and other minerals. Often found as thin layered organic rock rich in hydrocarbon deposits.

Shut-in.  A well that has been capped (having the valves locked shut) for an undetermined amount of time. This could be for additional testing, could be to wait for pipeline or processing facility, or a number of other reasons.

Standardized measure.  The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

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Successful.  A well is determined to be successful if it is producing natural gas, dewatering, or awaiting hookup, but not abandoned or plugged.

Undeveloped acreage.  Lease acreage on which wells have not been drilled or completed to appoint that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Well bore.  The hole of the well starting at the surface of the earth and descending downward to the bottom of the hole.

Working interest.  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

A-4

8,900,000 Shares

Common Stock

PROSPECTUS

We have not authorized any dealer, salesperson, or any other person to give any information or to represent anything not contained in this prospectus. You must not rely on any unauthorized information. This prospectus does not offer to sell or buy any shares in any jurisdiction where it is unlawful. The information in this prospectus is current as of October 31, 2007

PART II INFORMATION

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM. 24  INDEMNIFICATION

Limitation of Liability of Directors, Officers and Others.

In accordance with Utah law, our articles of incorporation eliminate or limit the liability of a director to the corporation or to its shareholders for monetary damages for any action taken or any failure to take any action as a director, except liability for (a) the amount of a financial benefit received by a director to which he is not entitled; (b) an intentional infliction of harm on the corporation or the shareholders; (c) specified unlawful distributions; or (d) an intentional violation of criminal law.

In addition, in Utah, unless a corporation’s articles of incorporation provide otherwise:

1. An officer of the corporation is entitled to mandatory indemnification and is entitled to apply for court-ordered indemnification, to the same extent as a director of the corporation;

2. The corporation may indemnify and advance expenses to an officer, employee, fiduciary or agent of the corporation to the same extent as to a director; and

3. A corporation may also indemnify and advance expenses to an officer, employee, fiduciary or agent who is not a director to a greater extent, if not inconsistent with public policy, and if provided for by its articles of incorporation, bylaws, general or specific action of its board of directors, or contract.

Our officers and directors are accountable to us as fiduciaries, which mean they are required to exercise good faith and fairness in all dealings affecting us. In the event that a shareholder believes the officers and/or director shave violated their fiduciary duties to us, the shareholder may, subject to applicable rules of civil procedure, be able to bring a class action or derivative suit to enforce the shareholder’s rights, including rights under certain federal and state securities laws and regulations to recover damages from and require an accounting by management, shareholders who have suffered losses in connection with the purchase or sale of their interest in Aurora Oil  & Gas Corporation in connection with such sale or purchase, including the misapplication by any such officer or director of the proceeds from the sale of these securities, may be able to recover such losses from us.

ITEM. 25  OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION

The following table sets forth the estimated expenses in connection with the issuance and distribution of the securities covered by this registration statement, other than underwriting discounts and commissions. All of the expenses will be borne by the Company, except as otherwise indicated.

Registration fee	$	-0-
Fees and expenses of accountants		9,000.00
Fees and expenses of legal counsel		5,000.00
Fees and expenses of engineers		1,000.00
Printing and engraving expenses		10,000.00
Miscellaneous expenses		1,000.00
Total	$	26,000.00

ITEM 26.  RECENT SALES OF UNREGISTERED SECURITIES

At the time of issuance, each investor or recipient of unregistered securities described below was either an accredited investor or a sophisticated investor. Each investor had access to our most recent Form 10-KSB, all quarterly and periodic reports filed subsequent to such Form 10-KSB and our most recent proxy materials.

We issued 21,959,922 shares of our common stock to various holders of our outstanding warrants and options during the period from late December 2005 through early February 2006. With respect to some of these warrant and option exercises, we reduced the exercise price for a limited period of time in order to encourage their early exercise. 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. In connection with certain of these warrant exercises, we paid a commission to Sunrise Securities Corporation, an affiliate of Nathan Low (a shareholder of Cadence) in the amount of $1,534,697. This entire amount was used by Mr. Low to exercise certain of our outstanding warrants, which are included in the foregoing total of shares issued in warrant and option exercises. Of the 21,959,922 shares issued, 5,756,149 shares were registered for issuance by the Company in the S-4 Registration Statement declared effective by the SEC on September 22, 2005, and the remaining 16,203,773 shares were issued pursuant to the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended.

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During the period from April 1, 2006 through June 30, 2006, we issued 345,000 shares of our common stock to various holders of our outstanding options. Some of the option exercises were paid for with cash, and some were exercised using a net issue election pursuant to which some option shares were forfeited to pay for the shares issued. We also issued 90,000 shares of common stock to two directors and one officer as compensation under our 2006 Stock Incentive Plan. Of the 435,000 shares issued, 175,000 shares were issued pursuant to the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended, and the balance were issued pursuant to an effective registration statement.

On October 6, 2006, we issued 1,378,299 shares of unregistered common stock to Richard Bach and Robin Bach as partial consideration for our purchase of all of the assets of Bach Enterprises, Inc. and certain assets of Bach Energy, LLC. The number of shares issued was based on a purchase value of $4,700,000 divided by $3.41 per share, which was the average of the closing price for the Company’s common stock for the 30-day calendar period immediately preceding October 6, 2006, the closing date for the acquisitions of assets. We paid an additional $200,000 in cash for these assets.

On December 29, 2006, one of our directors, Kevin D. Stulp exercised a warrant that was issued to him on March 1, 2002, to purchase 100,000 shares of our common stock at an exercise price of $0.75 per share for a total exercise price of $75,000.

The shares issued in both of the foregoing transactions were issued in reliance on the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended. All of the investors are accredited investors as that term is defined in Section 501 of Regulation D. There were no commissions paid on these transactions.

We did not repurchase any of our outstanding equity securities during the quarter ended December 31, 2006. We did, however, agree to the rescission of three previously exercised options, and return the exercise price. In January 2006, three of our executive officers, William W. Deneau, John V. Miller, Jr., and Thomas W. Tucker, each exercised an option to purchase 600,000 shares of our common stock at an exercise price of $0.415 per share for a total exercise price of $249,000. In December 2006, these option exercises were rescinded, and we returned the $249,000 exercise price to each of Mr. Deneau, Mr. Miller and Mr. Tucker.

During the period from January 1, 2007, through September 30, 2007, we issued 78,158 shares of our common stock pursuant to an exercise of a warrant dated April 2, 2004, to purchase 127,500 shares of common stock. This exercise was made pursuant to a net issue election and the balance of the shares under the warrant was forfeited. The shares issued pursuant to the warrant exercise were issued in reliance on the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended.

ITEM 27. EXHIBITS

3.1(1)	Restated Articles of Incorporation of Aurora Oil & Gas Corporation.
3.2	By-Laws of Aurora Oil & Gas Corporation. (filed as an Exhibit 3.2 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)
5.1	Opinion of Fraser Trebilcock Davis & Dunlap, P.C.
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.)

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10.2	Securities Purchase Agreement between Cadence Resources Corporation and the investors signatory thereto, dated January 31, 2005 (filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on February 2, 2005, and incorporated herein by reference.)
10.3(2)	Asset Purchase Agreement with Nor Am Energy, L.L.C., Provins Family, L.L.C. and O.I.L. Energy Corp. dated January 10, 2006.
10.4	Note Purchase Agreement between Aurora Antrim North, L.L.C. et al. and TCW Asset Management Company, dated August 12, 2004 (filed as an Exhibit to our Form S-4 registration statement filed with the SEC on May 13, 2005, and incorporated herein by reference.)
10.5	First Amended and Restated Note Purchase Agreement between Aurora Antrim North, L.L.C. et al. and TCW Asset Management Company, dated December 8, 2005 (filed as an Exhibit to our Annual Report on Form 10-KSB for the fiscal year ended September 30, 2005 filed with the SEC on December 29, 2005 and incorporated herein by reference.)
10.6(2)	First Amendment to First Amended and Restated Note Purchase Agreement between Aurora Antrim North, L.L.C., et al., and TCW Asset Management Company, dated January 31, 2006.
10.7	Amended and Restated Credit Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent and the Lenders Party hereto. (filed as an Exhibit 10.7 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)
10.8	Intercreditor and Subordination Agreement among, BNP Paribas, et al., TCW Asset Management Company, and Aurora Antrim North, L.L.C., dated January 31, 2006 (replaced and filed as Exhibit 10.26 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007, and incorporated herein by reference).
10.9(2)	Promissory Note from Aurora Energy, Ltd. to Northwestern Bank dated January 31, 2006.
10.10(2)	Confirmation from BNP Paribas to Aurora Antrim North, L.L.C., dated February 22, 2006 relating to gas sale commitment.
10.11	2006 Stock Incentive Plan. (filed as Exhibit 99.1 to our Form S-8 Registration Statement filed with the SEC on May 15, 2006 and incorporated herein by reference.)
10.12(1)	Employment Agreement with Ronald E. Huff dated June 19, 2006.
10.13(1)	Letter Agreement with Bach Enterprises dated July 10, 2006. This Agreement is confidential and has been filed separately with the SEC.
10.14(1)	First Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated July 14, 2006.
10.15(1)	The Denthorn Trust Commercial Guaranty of obligations to Northwestern Bank.
10.16(1)	William W. Deneau Commercial Guaranty of obligations to Northwestern Bank.
10.17(1)	The Denthorn Trust Commercial Pledge Agreement to Northwestern Bank.
10.18(3)	LLC Membership Interest Purchase Agreement dated October 6, 2006 relating to Kingsley Development Company, L.L.C.
10.19(3)	Asset Purchase Agreement with Bach Enterprises, Inc., et al., dated October 6, 2006.
10.20(3)	Promissory Note from Aurora Energy, Ltd. to Northwestern Bank dated October 15, 2006.
10.21(3)	Form of indemnification letter agreement between Aurora Oil & Gas Corporation and Rubicon Master Fund.
10.22(3)	Patricia A. Deneau Trust Commercial Guaranty of obligations to Northwestern Bank.
10.23(3)	Patricia A. Deneau Trust Commercial Pledge Agreement to Northwestern Bank.
10.24	Second Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated December 21, 2006. (filed as an Exhibit 10.24 to our Annual Report on Form 10-KSB for the fiscal year ended December 31, 2006, filed with the SEC on March 15, 2007 and incorporated herein by reference.)
10.25	Third Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated June 20, 2007. (filed as an Exhibit 10.25 to our Form 10-Q for the period ended June 30, 2007, filed with the SEC on August 9, 2007 and incorporated herein by reference.)
10.26	Intercreditor Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent and the Lenders Party hereto. (Replaced Exhibit 10.8 Intercreditor and Subordination Agreement among, BNP Paribas, et al., TCW Asset Management Company, and Aurora Antrim North, L.L.C., dated January 31, 2006.) (filed as an Exhibit 10.26 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)

II-3

10.27	Second Lien Term Loan Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent and the Lenders Party hereto. (filed as an Exhibit 10.27 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)
21	Subsidiaries of Aurora Oil & Gas Corporation.
23.1	Consent of Ralph E. Davis Associates, Inc.
23.2	Consent of Schlumberger Technology Corporation.
23.3	Consent of Netherland, Sewell & Associates, Inc.
23.4	Consent of Rachlin Cohen & Holtz LLP.
23.5	Awareness of Weaver and Tidwell, L.L.P.
23.6	Consent of Fraser Trebilcock Davis & Dunlap, P.C. (included in Exhibit 5.1).

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

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

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

ITEM 28.  UNDERTAKINGS

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the small business issuer pursuant to the foregoing provisions, or otherwise, the small business issuer has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the small business issuer of expenses incurred or paid by a director, officer or controlling person of the small business issuer in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the small business issuer will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

For determining any liability under the Securities Act, the small business issuer will treat the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the small business issuer under Rule 424(b)(1), or (4) or 497(h) under the Securities Act (§§230.424(b)(1), (4) or 230.497(h)), as part of this registration statement as of the time the Commission declared it effective.

For determining any liability under the Securities Act, the small business issuer will treat each post-effective amendment that contains a form of prospectus as a new registration statement for the securities offered in the registration statement, and that offering of the securities at that time as the initial bona fide offering of those securities.

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SIGNATURES

In accordance with the requirements of the Securities Act of 1933, the Registrant certifies that it has reasonable grounds to believe that it meets all of the requirements of filing on Form SB-2 and authorized this Form SB-2 Registration Statement to be signed on its behalf by the undersigned, in the city of Traverse City, State of Michigan, on this 31st day of October, 2007.

AURORA OIL & GAS CORPORATION
By:	/s/ William W. Deneau
	William W. Deneau, Chairman, Director, and Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, this Form SB-2 Registration Statement has been signed by the following persons in the capacities and on the dates indicated:

Signature	Title	Date
/s/ William W. Deneau  William W. Deneau	Chairman, Chief Executive Officer, and Director (Principal Executive Officer)	October 31, 2007
/s/ Ronald E. Huff Ronald E. Huff	President, Chief Financial Officer and Director (Principal Financial Officer and Principal Accounting Officer)	October 31, 2007
/s/ Kevin D. Stulp Kevin D. Stulp	Director	October 31, 2007
/s/ Richard M. Deneau Richard M. Deneau	Director	October 31, 2007
/s/ Gary J. Myles Gary J. Myles	Director	October 31, 2007
/s/ Earl V. Young Earl V. Young	Director	October 31, 2007
/s/ Wayne G. Schaeffer Wayne G. Schaeffer	Director	October 31, 2007

INDEX OF EXHIBITS

EXHIBITS

3.1(1)	Restated Articles of Incorporation of Aurora Oil & Gas Corporation.
3.2	By-Laws of Aurora Oil & Gas Corporation. (filed as an Exhibit 3.2 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)
5.1	Opinion of Fraser Trebilcock Davis & Dunlap, P.C.
10.1	Securities Purchase Agreement between Cadence Resources Corporation and the investors signatory thereto, dated April 2, 2004 (filed as Exhibit 99.3 to our Current Report on Form 8-K filed with the SEC on April 5, 2004, and incorporated herein by reference.)
10.2	Securities Purchase Agreement between Cadence Resources Corporation and the investors signatory thereto, dated January 31, 2005 (filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on February 2, 2005, and incorporated herein by reference.)
10.3(2)	Asset Purchase Agreement with Nor Am Energy, L.L.C., Provins Family, L.L.C. and O.I.L. Energy Corp. dated January 10, 2006.
10.4	Note Purchase Agreement between Aurora Antrim North, L.L.C. et al. and TCW Asset Management Company, dated August 12, 2004 (filed as an Exhibit to our Form S-4 registration statement filed with the SEC on May 13, 2005, and incorporated herein by reference.)
10.5	First Amended and Restated Note Purchase Agreement between Aurora Antrim North, L.L.C. et al. and TCW Asset Management Company, dated December 8, 2005 (filed as an Exhibit to our Annual Report on Form 10-KSB for the fiscal year ended September 30, 2005 filed with the SEC on December 29, 2005 and incorporated herein by reference.)
10.6(2)	First Amendment to First Amended and Restated Note Purchase Agreement between Aurora Antrim North, L.L.C., et al., and TCW Asset Management Company, dated January 31, 2006.
10.7	Amended and Restated Credit Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent and the Lenders Party hereto. (filed as an Exhibit 10.7 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)
10.8	Intercreditor and Subordination Agreement among, BNP Paribas, et al., TCW Asset Management Company, and Aurora Antrim North, L.L.C., dated January 31, 2006 (replaced and filed as Exhibit 10.26 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007, and incorporated herein by reference).
10.9(2)	Promissory Note from Aurora Energy, Ltd. to Northwestern Bank dated January 31, 2006.
10.10(2)	Confirmation from BNP Paribas to Aurora Antrim North, L.L.C., dated February 22, 2006 relating to gas sale commitment.
10.11	2006 Stock Incentive Plan. (filed as Exhibit 99.1 to our Form S-8 Registration Statement filed with the SEC on May 15, 2006 and incorporated herein by reference.)
10.12(1)	Employment Agreement with Ronald E. Huff dated June 19, 2006.
10.13(1)	Letter Agreement with Bach Enterprises dated July 10, 2006. This Agreement is confidential and has been filed separately with the SEC.
10.14(1)	First Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated July 14, 2006.
10.15(1)	The Denthorn Trust Commercial Guaranty of obligations to Northwestern Bank.
10.16(1)	William W. Deneau Commercial Guaranty of obligations to Northwestern Bank.
10.17(1)	The Denthorn Trust Commercial Pledge Agreement to Northwestern Bank.
10.18(3)	LLC Membership Interest Purchase Agreement dated October 6, 2006 relating to Kingsley Development Company, L.L.C.
10.19(3)	Asset Purchase Agreement with Bach Enterprises, Inc., et al., dated October 6, 2006.
10.20(3)	Promissory Note from Aurora Energy, Ltd. to Northwestern Bank dated October 15, 2006.
10.21(3)	Form of indemnification letter agreement between Aurora Oil & Gas Corporation and Rubicon Master Fund.
10.22(3)	Patricia A. Deneau Trust Commercial Guaranty of obligations to Northwestern Bank.
10.23(3)	Patricia A. Deneau Trust Commercial Pledge Agreement to Northwestern Bank.
10.24	Second Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated December 21, 2006. (filed as an Exhibit 10.24 to our Annual Report on Form 10-KSB for the fiscal year ended December 31, 2006, filed with the SEC on March 15, 2007 and incorporated herein by reference.)

10.25	Third Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated June 20, 2007. (filed as an Exhibit 10.25 to our Form 10-Q for the period ended June 30, 2007, filed with the SEC on August 9, 2007 and incorporated herein by reference.)
10.26	Intercreditor Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent and the Lenders Party hereto. (Replaced Exhibit 10.8 Intercreditor and Subordination Agreement among, BNP Paribas, et al., TCW Asset Management Company, and Aurora Antrim North, L.L.C., dated January 31, 2006.) (filed as an Exhibit 10.26 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)
10.27	Second Lien Term Loan Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent and the Lenders Party hereto. (filed as an Exhibit 10.27 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)
21	Subsidiaries of Aurora Oil & Gas Corporation.
23.1	Consent of Ralph E. Davis Associates, Inc.
23.2	Consent of Schlumberger Technology Corporation.
23.3	Consent of Netherland, Sewell & Associates, Inc.
23.4	Consent of Rachlin Cohen & Holtz LLP.
23.5	Awareness of Weaver and Tidwell, L.L.P.
23.6	Consent of Fraser Trebilcock Davis & Dunlap, P.C. (included in Exhibit 5.1).

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

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

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