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

As filed with the Securities and Exchange Commission on November 13, 2006

RegistrationNo. 333-110099

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 incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

4110 Copper Ridge Drive, Suite 100

Traverse City, Michigan 49684

(231) 941-0073

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

Name, address and telephone number of agent for service:

William W. Deneau, President

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 may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become 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 date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

SUBJECT TO COMPLETION, DATED NOVEMBER 13, 2006

3,919,540 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 57. 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 November 1, 2006, the last sales price of our common stock as reported on the American Stock Exchange was $3.01 per share.

Investing in our common stock involves risks.  See “Risk Factors” beginning on page 10.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this prospectus is November   , 2006.

TABLE OF CONTENTS

PROSPECTUS SUMMARY	1
RISK FACTORS	10
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS	20
USE OF PROCEEDS	21
CAPITALIZATION	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	51
PRINCIPAL AND SELLING SECURITY HOLDERS	55
RELATED PARTY TRANSACTIONS	60
PLAN OF DISTRIBUTION	62
DESCRIPTION OF SECURITIES	64
LEGAL MATTERS	67
EXPERTS	67
WHERE YOU CAN FIND MORE INFORMATION	68
FINANCIAL STATEMENTS	F-1
APPENDIX A — RESERVE REPORT OF SCHLUMBERGER (Michigan Properties)	A-1
APPENDIX B — RESERVE REPORT OF SCHLUMBERGER (Indiana Properties)	B-1
APPENDIX C — RESERVE REPORT OF RALPH E. DAVIS ASSOCIATES, INC.	C-1
APPENDIX D — RESERVE REPORT OF NETHERLAND, SEWELL & ASSOCIATES, INC.	D-1
APPENDIX E — GLOSSARY OF OIL AND NATURAL GAS TERMS	E-1
Opinion of Fraser Trebilcock Davis & Dunlap, P.C.
Awareness Letter from Rachlin Cohen & Holtz LLP
Consent of Rachlin Cohen & Holtz LLP.

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

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. Unless the context otherwise requires, the information in this prospectus assumes that the underwriters will not exercise their over-allotment option.

PROSPECTUS SUMMARY

This summary contains basic information about us and the offering. Because it is a summary, it does not contain all the information that you should consider before investing in our common stock. You should read and carefully consider this entire prospectus before making an investment decision, especially the information presented under the heading “Risk Factors” and our consolidated financial statements and the accompanying notes included elsewhere in this prospectus, as well as the other documents to which we refer you. We have provided definitions for some of the oil and natural gas industry terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms” in Appendix E. Natural gas equivalents are determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas 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 and the New Albany shale of Southern Indiana and Western Kentucky. Our management and technical teams have an extensive track record in the exploration and production business as well as significant operating experience in shale plays.

We own approximately 1,105,739 (621,290 net) leasehold acres, of which 575,453 net leasehold acres are related to shale where we have quantified approximately 2,665 net potential drilling locations. 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. The following table sets forth our approximate leasehold acreage and net potential drilling locations as of June 30, 2006:

						Net Potential
Play/Trend	Location	Gross Acres		Net Acres		Drilling Locations(a)
Antrim	Michigan		252,634		125,993		1,260
New Albany	Southern Indiana and Western Kentucky		784,816		449,460		1,405
Other	Various		68,289		45,837		286	��
Total			1,105,739		621,290		2,951

(a) Net potential drilling locations are locations quantified by management based on well spacing criteria for a particular play/trend. For example, New Albany drilling locations are based upon 320-acre spacing per well, Antrim drilling locations are based upon 100-acre spacing per well and Other drilling locations are based upon 160-acre spacing per well.

As of December 31, 2005, our net proved reserves were approximately 64 bcfe, of which 99% were natural gas reserves. As of June 30, 2006, our estimated net proved reserves had grown to 105 bcfe representing a 64% increase over our December 31, 2005 net proved reserves. This increase was attributable to our increased drilling activity and an acquisition of oil and natural gas properties with proven reserves of 24 bcfe completed in January 2006. During the first six months of 2006, we invested $20.4 million in drilling and related well activity and $40.1 million in net leasehold interest and property acquisitions.

Unconventional shale plays tend to be characterized by high drilling success rates. For the18-month period ending June 30, 2006, we invested $51.0 million to drill and complete 225 (141.78 net) wells, of which 96% were successful. In addition, we invested $51.3 million on property and leasehold acquisitions. Average net daily

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production increased from 609 mcfe/d in January 2005 to 7,392 mcfe/d in June 2006. The table below highlights our portfolio of wells as of June 30, 2006.

									Gross		Net
									Average Daily		Average Daily
					Gross Wells		Net Wells		Production		Production
	Gross Wells		Net Wells		Waiting		Waiting		(mcfe/d) in		(mcfe/d) in
Play /Trend	Producing		Producing		Hook-Up		Hook-Up		June 2006		June 2006
Antrim		325.00		154.05		59.00		30.71		15,015		6,702
New Albany		8.00		0.35		19.00		4.30		2,001		88
Other		45.00		15.19		8.00		2.74		1,434		602
Total		378.00		169.59		86.00		37.75		18,450		7,392

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 575,453 net leasehold acres in our shale areas, of which approximately 93% were undeveloped as of June 30, 2006. As of that date, we had approximately 2,665 net potential drilling locations on this acreage. At our current planned drilling rate, this would accommodate more than nine years of drilling activity.

Experienced management and technical teams.  Our four senior executive officers average 23 years of experience in the natural gas industry. In addition, we employ two senior geologists, one staff geologist, one senior oil and gas petroleum engineer, one drilling superintendent, one production supervisor and three senior land professionals with an average of over 24 years of oil and natural gas experience.

Operational control.  As of June 30, 2006, we operated approximately 38% of the wells in which we have an interest, and we expect our 56% 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.

Financial flexibility.  We seek to maintain a conservative financial position and believe that our operating cash flow and proceeds from a public offering that we just completed with additional debt financing will provide us with the financial flexibility to pursue our planned growth through exploration and development activities through 2007.

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 projects including approximately 575,453 net leasehold acres on which we have approximately 2,665 net potential drilling locations. In the Antrim shale play there have been over 8,000 wells drilled since the inception of the play with a historic success rate of approximately 95%. The New Albany shale play is an emerging play without the history of the Antrim shale play, but we believe it will have similar success characteristics to the Antrim shale play. We believe that by focusing our drilling budget on development oriented activities in our shale areas in the short run, we can maintain high drilling success rates yielding

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attractive rates of return. We anticipate committing a small portion of our drilling budget to locations outside of our shale project areas to continually evaluate and test new areas for exploration and development potential.

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

Manage costs by maximizing operational control.  We seek to exert control over our exploration, exploitation and development activities. As the operator of our projects, we have greater control over the amount and timing of the expenditures associated with those activities. As we manage our growth, we are focused on reducing lease operating expenses, general and administrative costs and finding and development costs on a per mcfe basis. As of June 30, 2006, we operated 38% of our wells. We believe this percentage will continue to increase, and we plan to operate approximately 44% of our wells drilled in 2007.

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

Our Challenges

Investing in our common stock involves risks. You should read carefully the section of this prospectus entitled “Risk Factors” beginning on page 10 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. For example, from January 1, 2006 to October 19, 2006, natural gas prices quoted for the near month NYMEX contract ranged from a low of $4.05 per mmbtu to a high of $11.38 per mmbtu.

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. We will also require substantial amounts of capital to develop our natural gas reserves.

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.

Summary of Our Budgeted Exploration, Exploitation and Development Activities

Our net capital expenditures for 2005 were $41.9 million, including $30.6 million for drilling and related well work and infrastructure, $15.6 million for leasehold interest acquisitions, $8.3 million for property acquisitions, less dispositions of $12.6 million. Our 2006 capital budget for drilling and related well work and infrastructure is approximately $51.2 million with participation in 221 (106 net) wells. Our 2006 capital budget for leasehold interest and property acquisitions is approximately $14.2 million and $39.3 million, respectively. Our 2007 capital budget for drilling and related well work and infrastructure is estimated to be approximately $105.6 million with participation in 410 (228 net) wells. Our 2007 capital budget for leasehold interest and property acquisitions is currently estimated to be approximately $9 million and $1 million, respectively.

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The following table summarizes information regarding our drilling and related well work budget for our key exploration and development areas for the 18 months commencing on July 1, 2006 through December 31, 2007:

	July 2006 through December 2006						January 2007 through December 2007
	Gross Wells		Net Wells		Net Capital		Gross Wells		Net Wells		Net Capital
	Projected to		Projected to		Expenditure		Projected to		Projected to		Expenditure
Play / Trend	be Drilled		be Drilled		Budget(a)		be Drilled		be Drilled		Budget(a)
Antrim		124.0		59.80	$	19,434,000		285.0		168.39	$	54,728,000
New Albany		19.0		9.30		7,901,000		106.0		43.10		36,630,000
Other		6.0		3.94		3,358,000		19.0		16.75		14,238,000
Total		149.0		73.04	$	30,693,000		410.0		228.24	$	105,596,000
Operated		52.0		46.54	$	18,395,000		180.0		156.94	$	62,279,000
Non-operated		97.0		26.50		12,298,000		230.0		71.30		43,317,000
Total		149.0		73.04	$	30,693,000		410.0		228.24	$	105,596,000

(a) Includes capital expenditures for drilling and related well work infrastructure and does not include costs for leasehold interest and property acquisitions.

Our Active Project Areas

The following is a summary of our activities in each of the two plays/trends in which we have development projects.

Antrim shale.  Our Antrim shale properties are located in Michigan. 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. Shale production is generally characterized by an initial dewatering phase of six to 18 months followed by increasing and then stabilized production prior to a natural decline. As of June 30, 2006, we had 384 (185 net) wells in this play/trend, of which 154 net wells are producing, and 31 net wells are awaiting hookup. Our Antrim wells are drilled to a shale formation at depths ranging from 250 to 1,500 feet targeting reserves of 0.5 bcfe per well and, based on our 2007 budget, cost approximately $325,000 to drill and complete each well. As of June 30, 2006, we had a 48% average working interest in the existing wells of our Antrim project area, and our average working interest in total Antrim leases was 50%. Key statistics for our position in this play/trend include:

•  125,993 total net acres, including 90,483 net undeveloped acres, at June 30, 2006;

•  6,702 mcfe/d of estimated average net production for June 2006, compared to 1,438 mcfe/d for June 2005;

•  325 (154 net) wells producing with another 59 (31 net) wells awaiting hookup as of June 30, 2006; and

•  101 bcfe of estimated net proved reserves as of June 30, 2006.

New Albany shale.  Our New Albany shale properties are located in Southern Indiana and Western Kentucky. Nearly all of our exploratory and developmental operations in this play/trend are focused on unconventional shale plays. The New Albany shale play is an emerging play with characteristics that we believe will be similar to the Antrim shale play. As of June 30, 2006, we had 27 (4.65 net) wells in this play/trend, of which 8 (0.35 net) are producing, and 19 (4.30 net) are awaiting hookup. Our New Albany wells are drilled to a shale formation at depths ranging from 500 to 3,000 feet targeting reserves of 0.9 to 1.3 bcfe per well and, based on our 2007 budget, cost approximately $850,000 to drill and complete each well. As of June 30, 2006, we had a 17% average working interest in the wells of our New Albany project area, and our average working interest in total New Albany leases was 57%. Key statistics for our position in this play/trend include:

•  449,460 total net acres, including 444,494 net undeveloped acres, at June 30, 2006;

•  88 mcfe/d of estimated average net production for June 2006;

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•  Eight (0.35 net) wells producing with another 19 (4.30 net) wells awaiting hookup as of June 30, 2006;

•  Two bcfe of estimated net proved reserves at June 30, 2006; and

•  Our most recent Schlumberger reserve report included 38 well locations in the New Albany shale, of which nine were classified as proved developed producing, four were classified as proved developed non-producing, and 25 were classified as proved undeveloped. The total gross reserves assigned to these 38 well locations was 47.7 bcfe or approximately 1.3 bcfe per well.

Other properties.  We also have acreage and leasehold interests outside our shale project areas. We are currently in the process of evaluating this portfolio.

Recent Developments

Letter of intent to acquire Antrim shale project.  On May 9, 2006, we entered into a non-binding letter of intent to acquire Antrim shale producing properties in Northern Michigan with estimated proved reserves in excess of 10 bcfe. It is anticipated that this acquisition will cost approximately $10.5 million, and closing is subject to our due diligence and bank approval.

Bach acquisition.  On October 6, 2006, we closed on the purchase all of the assets of Bach Enterprises, Inc. and certain of its affiliates. Bach Enterprises, Inc. is an oil and natural gas services company whose services include building compressors, CO₂ removal, pipelining, and facility construction. We have been its primary customer. Consideration paid in the form of stock and cash is deemed to be non-material for financial reporting purposes.

Disposition of DeSoto Parish assets.  On July 20, 2006, we sold oil and natural gas properties with 1.46 bcfe in estimated proven reserves located in DeSoto Parish, Louisiana to BEUSA Energy, Inc. for $4.75 million.

Operations Update.  We drilled or participated in the drilling of 58 (19 net) wells in the third quarter ending September 30, 2006 with a net success rate of 92%. Thus, as of September 30, 2006 we have 425 (192 net) producing wells and 77 (27 net) wells awaiting hook-up. Our estimated average daily production for September 2006 was 8,074 mcfe/d.

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 the selling security holders	3,919,540 shares
Use of proceeds	We will not receive any of the proceeds form 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 10 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 5,535,500 shares of common stock reserved for issuance under our 2006 Stock Incentive Plan;

•  excludes 4,802,776 shares of our common stock issuable upon exercise of outstanding options at a weighted average exercise price of $2.16 per share; and

•  excludes 2,079,500 shares of our common stock issuable upon exercise of outstanding warrants at a weighted average exercise price of $1.71 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, 2005 and 2004 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, 2006 and 2005 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,(a)						Year Ended December 31,(a)
	2006			2005			2005			2004
Statement of operations data
Revenues
Oil and gas sales	$	10,941,220		$	1,097,906		$	6,743,444		$	960,011
Other income		438,285			362,008			377,025			1,192,835
Interest income		244,214			165,910			243,013			47,678
Total revenue		11,623,719			1,625,824			7,363,482			2,200,524
Expenses
General and administrative		3,242,713			1,126,396			3,435,507			2,057,333
Pipeline operating expenses		284,201			—			—			—
Production and lease operating		3,411,051			652,957			2,047,028			614,338
Depletion, depreciation and amortization		3,024,166			102,227			1,155,254			203,249
Interest		3,564,154			237,354			1,228,274			392,402
Taxes		29,361			237,697			29,651			75,000
Total expenses		13,555,646			2,356,631			7,895,714			3,342,322
Loss before minority interest		(1,931,927	)		(730,807	)		(532,232	)		(1,141,798	)
Minority interest in (income) loss of subsidiaries		(17,919	)		(6,190	)		15,960			38,087
Net loss		(1,949,846	)		(736,997	)		(516,272	)		(1,103,711	)
Less dividends on preferred stock		—			—			—			(30,268	)
Loss attributable to common shareholders	$	(1,949,846	)	$	(736,997	)	$	(516,272	)	$	(1,133,979	)
Net loss per common share — basic and diluted	$	(0.03	)	$	(0.02	)	$	(0.01	)	$	(0.05	)
Weighted average common shares outstanding — basic and diluted		76,011,115			36,157,838			40,622,000			23,636,000
Cash flow data
Cash provided (used) by operating activities	$	2,636,906		$	(459,971	)	$	(411,196	)	$	218,441
Cash used by investing activities		(32,845,786	)		(7,946,216	)		(41,862,869	)		(8,716,784	)
Cash provided by financing activities		21,823,195			16,743,071			49,075,121			12,632,173

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	As of June 30,		As of December 31,
	2006		2005		2004
Balance sheet data
Cash and cash equivalents	$	3,594,953	$	11,980,638	$	5,179,582
Other current assets		11,158,265		7,274,869		2,636,114
Oil and gas properties, net (using full cost accounting)		124,298,203		68,960,754		14,967,457
Other property and equipment, net		8,414,997		—		—
Other assets		22,069,765		28,605,884		662,676
Total assets	$	169,536,183	$	116,822,145	$	23,445,829
Current liabilities	$	10,826,542	$	13,832,112	$	6,109,156
Long-term debt, net of current maturities		83,764,824		42,794,862		11,090,369
Deposit on sale of oil and gas properties		—		3,509,319		—
Redeemable convertible preferred stock		19,924		59,925		—
Shareholders’ equity		74,924,893		56,625,927		6,246,304
Total liabilities and shareholders’ equity	$	169,536,183	$	116,822,145	$	23,445,829

(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 condensed consolidated financial statements for the six months ended June 30, 2005, and years ended December 31, 2005 and 2004, and related notes have been retroactively adjusted to give effect to the reverse merger on October 31, 2005.

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,
	2006		2005		2004
Production
Oil (bbls)		11,888		10,628		4,798
Natural gas (mcf)		1,224,551		687,271		151,241
Natural gas equivalent (mcfe)		1,295,879		751,039		180,029
Oil and natural gas sales
Oil sales	$	741,110	$	558,455	$	226,599
Natural gas sales		10,200,110		6,184,989		733,412
Total	$	10,941,220	$	6,743,444	$	960,011
Average sales price (including realized gains or losses from hedging)
Oil ($ per bbl)	$	62.34	$	52.54	$	47.23
Natural gas ($ per mcf)		8.33		9.00		4.85
Natural gas equivalent ($ per mcfe)		8.44		8.98		5.33
Average production cost
Natural gas equivalent ($ per mcfe)	$	2.63	$	2.73	$	3.41

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	As of June 30,		As of December 31,
	2006		2005		2004
Estimated proved reserves(a)(b)
Oil (mbbls)		91		99		—
Natural gas (mmcf)		105,288		63,321		34,949
Natural gas equivalent (mmcfe)		105,834		63,915		34,949
PV-10(c)	$	136,038,320	$	199,507,440	$	47,910,500
Standardized measure(d)	$	116,722,099	$	152,868,240	$	32,159,710

(a)	The information presented for New Albany and Antrim reserves at June 30, 2006 is based on reserve reports prepared by Schlumberger. Consistent with Schlumberger’s standard engineering practices, these reports and such reserves excluded the impact of the following financial hedges: (i) 5,000 mmbtu/day at a price of $8.59/mmbtu through March 2007 and (ii) 5,000 mmbtu/day at a price of $9.00/mmbtu from April 2007 through December 2008.
(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)	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 June 30, 2006, and December 31, 2005 and 2004, respectively. 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, and at December 31, 2004, without escalation, using $6.20 per mmbtu, in each case adjusted by lease for transportation fees and regional price differentials. The estimated future production is priced at June 30, 2006, without escalation, using $69.32 per bbl and $5.69 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 ofPV-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 ofPV-10 to the most directly comparable GAAP measure — standardized measure of discounted future net cash flows — in the following table:

	As of June 30,		As of December 31,
	2006		2005		2004
Standardized measure of discounted future net cash flows	$	116,722,099	$	152,868,240	$	32,159,710
Add: Present value of future income tax discounted at 10%		19,316,221		46,639,200		15,750,790
PV-10	$	136,038,320	$	199,507,440	$	47,910,500

(d) 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 calculatePV-10. Standardized measure differs fromPV-10 because standardized measure includes the effect of future income taxes. As noted in footnote (a) above, the June 30, 2006 information excludes the impact of our hedges. If the impact of our hedges were included, the standardized measure for June 30, 2006 would have been increased by $8,960,351 to $125,682,450.

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RISK FACTORS

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

RISKS RELATED TO OUR BUSINESS

Natural gas prices are volatile. A substantial decrease in natural gas prices would significantly 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 to October 19, 2006, natural gas prices quoted for the near month NYMEX contract ranged from a low of $4.05 per mmbtu to a high of $11.38 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, in addition to the proceeds from the public offering that we recently completed and the cash generated from our operations, 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.

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

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 this region caused by weather conditions, governmental regulation, lack of field infrastructure, or other events which impact this area. 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 future drilling plans over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

As of June 30, 2006, we had approximately 2,665 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, 2005 and 2004, and the six months ended June 30, 2006. We expect to report a net loss in the third quarter of 2006 and also expect to show a net reduction in working capital and shareholder equity in the third quarter of 2006. 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, 2006, we operated 38% 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.

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We may be unable to make acquisitions of producing properties or prospects or successfully 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, 2006, we had acquired approximately 1,105,739 (621,290 net) acres with 105 bcfe 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, we recently closed on the acquisition of all of the assets of Bach Enterprises, Inc. (or Bach) and certain of its affiliates. Bach Enterprises, Inc. 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 services company and may encounter issues that prevent us from successfully integrating it as part of our business.

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 in Antrim shale projects as of June 30, 2006, 57% are classified as proved developed producing, 13% are classified as proved developed non-producing, and 30% 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

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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 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.

The oil and natural gas reserve data included in this document are estimates based on assumptions that may be inaccurate and existing economic and operating conditions that 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 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 40 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, 2006, approximately 4% 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

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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.

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 recently 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 is completed and permits are issued. The DEQ has also recently 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.

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 future exploration 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.

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

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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 limited operating 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, including Louisiana and Texas, 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.

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.

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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 limit our flexibility and may limit our borrowing capacity; needed increases in borrowing capacity may not be available.

As of October 13, 2006, our outstanding debt includes a senior credit facility with a current approved borrowing base of $50 million, all 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 $3.6 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 may result in our making cash payments or prevent us from receiving the full benefit of increases 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.

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 to compliance are significant, our profitability, stock price and results of operations and 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

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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 theout-of-pocket costs, the diversion of management’s attention from running theday-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 could adversely affect our business.

Oil and 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.

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

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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.

Since January 1, 2006, our stock has traded as high as $7.44 per share and as low as $2.60 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 cumulative voting.

In connection with the closing of the merger of Cadence Resources Corporation and Aurora, 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 14% of our outstanding shares prior to the close of this offering, 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 10.8 million shares of our common stock held by such shareholders was subject to these proxies at June 30, 2006. These provisions will limit our other shareholders’ ability to influence the outcome of shareholder votes 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 through October 31, 2008.

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 of shares 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 and purchasers of common stock offered in this prospectus. 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. As of November 13, 2006, 103,062,966 shares of common stock were outstanding. We have currently reserved 8,000,000 shares of common stock for future issuance to employees as restricted stock or stock option awards pursuant to our 2006 Stock Incentive Plan, of which stock grants and options to purchase a total of 2,464,500 shares have already been awarded, and 5,535,500 shares remain available for future awards. We also have other warrants and options outstanding which may be exercised for an additional 4,417,776 aggregate shares of our common stock. 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. 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 of substantial amounts of our common stock in the public markets.

We have two other shelf registration statements that are currently effective, which together with this registration statement have registered almost 40 million shares of common stock for resale. We have just completed the sale of 19,600,000 shares in a fully underwritten public offering. 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, the issuance of the additional shares in the public offering, 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. We have approximately 103 million shares of common stock issued and outstanding, including approximately 12.7 million shares of our common stock held or controlled by our executive officers and directors. Of those 12.7 million shares, 8.6 million are subject to lock-up agreements through October 31, 2008, 0.7 million are eligible for resale on anS-8 registration statement, and the balance are or will be eligible for sale under Rule 144 after the expiration of the90-day lock-up period that is applicable to our executive officers, directors and certain of our shareholders following the completion of this offering. In addition, the remaining 3.75 million shares retained by Rubicon Master Fund after closing of the public offering are subject to lock-up for a period of 90 days after the date of the public offering prospectus. Additionally, we have filed anS-8 registration statement with the Securities and Exchange Commission (“SEC”) providing for the registration of 9,589,496 shares of our common stock issued or reserved for issuance under our employee plans, all of which are eligible for sale without further registration under the Securities Act.

We do not intend to pay, and are prohibited from paying, any dividends on our common stock.

We anticipate that we will retain all future earnings and other cash resources for the future operation and development of our business. Accordingly, we do not intend to declare or pay any cash dividends on our common stock in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our operating results, financial condition, current and anticipated cash needs and plans for expansion. In addition, the declaration and payment of any dividends on our common stock is prohibited by the terms of certain of our credit facilities so long they are in effect. Our senior credit facility terminates on the earlier of January 31, 2010 or 91 days prior to the maturity of our mezzanine credit facility; however, prior to that time we may enter into a new credit facility or other contractual arrangement that further restricts our ability to pay dividends.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements within the meaning of Section 27A of 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 crude oil and natural gas;

•  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 under “Risk Factors.”

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 prospectus.

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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.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2006:

•  on an actual basis; and

•  on an as-adjusted basis to reflect our receipt of the estimated net proceeds from the sale of 19.6 million shares in a public offering that we have just completed at a public offering price of $3.00 per share, after deducting the underwriting discount and estimated offering expenses.

You should read this table in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our condensed consolidated financial statements and related notes, which are provided elsewhere in this prospectus.

	As of June 30, 2006
	Actual			As Adjusted
	(Unaudited)
	(Dollars in thousands)
Cash and cash equivalents	$	3,595		$	18,286
Total debt (including current maturities)	$	82,850		$	42,850
Redeemable convertible preferred stock		20			20
Shareholders’ Equity:
Common stock, $.01 par value, 250,000,000 authorized; 81,965,017 issued and outstanding actual; 103,062,966 issued and outstanding as adjusted		820			1,016
Additional paid-in capital		77,757			132,252
Accumulated other comprehensive income		962			962
Accumulated deficit		(4,614	)		(4,614	)
Total shareholders’ equity		74,925			129,616
Total capitalization	$	157,795		$	172,486

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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 theOver-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 four quarters of 2006. The prices during the time in which our stock tradedover-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.

	High Bid/		Low Bid/
Quarter Ended	Sales Price		Sales Price
March 31, 2004	$	4.70	$	3.00
June 30, 2004	$	3.80	$	1.70
September 30, 2004	$	2.30	$	0.85
December 31, 2004	$	1.65	$	0.98
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 (through November 1, 2006)	$	3.32	$	2.60

On November 1, 2006, the last reported per share sale price of our common stock on AMEX was $3.01 and there were 83,587,966 shares of our common stock outstanding and 587 holders of record. On November 7 and November 13, 2006, we closed on our public offering and the over-allotment option, respectively, resulting in an increase to 103,062,966 shares of common stock outstanding.

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.

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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, 2005 and 2004 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, 2006 and 2005 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, 2006 are not necessarily indicative of results that may be expected for the entire year 2006 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						Year Ended
	June 30,(a)						December 31,(a)
	2006			2005			2005			2004
Statement of operations data
Revenues
Oil and gas sales	$	10,941,220		$	1,097,906		$	6,743,444		$	960,011
Other income		438,285			362,008			377,025			1,192,835
Interest income		244,214			165,910			243,013			47,678
Total revenue		11,623,719			1,625,824			7,363,482			2,200,524
Expenses
General and administrative		3,242,713			1,126,396			3,435,507			2,057,333
Pipeline operating expenses		284,201			—			—			—
Production and lease operating		3,411,051			652,957			2,047,028			614,338
Depletion, depreciation and amortization		3,024,166			102,227			1,155,254			203,249
Interest		3,564,154			237,354			1,228,274			392,402
Taxes		29,361			237,697			29,651			75,000
Total expenses		13,555,646			2,356,631			7,895,714			3,342,322
Loss before minority interest		(1,931,927	)		(730,807	)		(532,232	)		(1,141,798	)
Minority interest in (income) loss of subsidiaries		(17,919	)		(6,190	)		15,960			38,087
Net loss		(1,949,846	)		(736,997	)		(516,272	)		(1,103,711	)
Less dividends on preferred stock		—			—			—			(30,268	)
Loss attributable to common shareholders	$	(1,949,846	)	$	(736,997	)	$	(516,272	)	$	(1,133,979	)
Net loss per common share — basic and diluted	$	(0.03	)	$	(0.02	)	$	(0.01	)	$	(0.05	)
Weighted average common shares outstanding — basic and diluted		76,011,115			36,157,838			40,622,000			23,636,000
Cash flow data
Cash provided (used) by operating activities	$	2,636,906		$	(459,971	)	$	(411,196	)	$	218,441
Cash used by investing activities		(32,845,786	)		(7,946,216	)		(41,862,869	)		(8,716,784	)
Cash provided by financing activities		21,823,195			16,743,071			49,075,121			12,632,173

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	As of June 30,		As of December 31,
	2006		2005		2004
Balance sheet data
Cash and cash equivalents	$	3,594,953	$	11,980,638	$	5,179,582
Other current assets		11,158,265		7,274,869		2,636,114
Oil and gas properties, net (using full cost accounting)		124,298,203		68,960,754		14,967,457
Other property and equipment, net		8,414,997		—		—
Other assets		22,069,765		28,605,884		662,676
Total assets	$	169,536,183	$	116,822,145	$	23,445,829
Current liabilities	$	10,826,542	$	13,832,112	$	6,109,156
Long-term debt, net of current maturities		83,764,824		42,794,862		11,090,369
Deposit on sale of oil and gas properties		—		3,509,319		—
Redeemable convertible preferred stock		19,924		59,925		—
Shareholders’ equity		74,924,893		56,625,927		6,246,304
Total liabilities and shareholders’ equity	$	169,536,183	$	116,822,145	$	23,445,829

(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 condensed consolidated financial statements for the six months ended June 30, 2005, and years ended December 31, 2005 and 2004, and related notes have been retroactively adjusted to give effect to the reverse merger on October 31, 2005.

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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 and related notes included elsewhere in this prospectus. This discussion contains forward-looking statements reflecting our current expectations and estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this 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 and New Albany shale of Southern Indiana and Western Kentucky.

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

As a result of the reverse merger, the historical financial statements presented for periods prior to the acquisition date are the financial statements of Aurora. The operations of the former Cadence Resources Corporation businesses have been included in the consolidated financial statements from the date of acquisition. Effective May 11, 2006, Cadence Resources Corporation amended its articles of incorporation to change the parent company name to Aurora Oil & Gas Corporation.

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

Recent Highlights

For the first six months of 2006, we continued to execute our strategy of focusing on lower risk shale development projects. As of June 30, 2006, we held approximately 1,105,739 (621,290 net) leasehold acres, which represent a 71% increase over our December 31, 2005 net acreage position. Of the 290,274 (257,200 net) leasehold acres acquired, 47,830 net acres were in the Antrim shale play and 177,568 net acres were in the New Albany shale play.

With regard to our strategy to generate growth through drilling, we drilled or participated in 72 (33 net) wells for the first six months of 2006. As of June 30, 2006, we had 378 (170 net) producing wells and 86 (38 net) wells awaiting hook-up. We also continued our strategy to have greater control over our projects by operating 175 (151 net) wells, operating 38% of our gross wells. We also supplemented our drilling strategy with the Hudson properties acquisition. This acquisition increased our proved reserves by approximately 24 bcfe in the Antrim shale play.

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

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

To further our growth, we entered into a senior secured credit facility on January 31, 2006 with an initial borrowing base of $40 million. Effective July 14, 2006, the borrowing base was increased to $50 million. As proved reserves are added, the borrowing base may increase to $100 million with consent of our mezzanine lender.

From late December 2005 through early February 2006, we reduced the exercise price of certain outstanding options and warrants in order to encourage the early exercise of these securities. As a result of the options and warrants exercised pursuant to this reduced exercise price arrangement, and pursuant to other exercises of outstanding options, an additional 20,315,422 shares were issued during the six months ended June 30, 2006 representing 15,565,457 shares issued for cash proceeds of $18,144,449 and 4,749,965 shares issued pursuant to cashless exercises of the applicable warrants or options. In December 2005, an additional 2,160,000 shares were issued for cash proceeds of $2,916,000.

RESULTS OF OPERATIONS

Operating Statistics

The following table sets forth certain key operating statistics for the six months ended June 30, 2006 and 2005 and for the years ended December 31, 2005 and 2004:

	Six Months Ended				Year Ended
	June 30,				December 31,
	2006		2005		2005		2004
Total net acreage held
Antrim		125,993		59,428		78,163		55,538
New Albany		449,460		139,431		271,891		220,984
Other		45,837		3,520		14,036		2,676
Total		621,290		202,379		364,090		279,198
Net wells drilled
Antrim		27		19		105		26
New Albany		2		—		—		—
Other		4		—		1		—
Total		33		19		106		26
Total net wells
Producing		170		47		123		25
Waiting hookup		37		20		60		17
Total		207		67		183		42
Production
Natural gas (mcf)		1,224,551		147,899		687,271		151,241
Crude oil (bbls)		11,888		2,764		10,628		4,798

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	Six Months Ended				Year Ended
	June 30,				December 31,
	2006		2005		2005		2004
Average daily production
Natural gas (mcf)		6,765		817		1,883		414
Crude oil (bbls)		66		15		29		13
Average sales prices (including realized gains or losses from hedging)
Natural gas ($ per mcf)	$	8.33	$	6.55	$	9.00	$	4.85
Crude oil ($ per bbl)	$	62.34	$	46.60	$	52.54	$	47.23
Production revenue
Natural gas	$	10,200,110	$	968,738	$	6,184,989	$	733,412
Crude oil		741,110		129,168		558,455		226,599
Total	$	10,941,220	$	1,097,906	$	6,743,444	$	960,011
Production expense per mcfe	$	2.63	$	3.97	$	2.73	$	3.41
Number of employees		53		32		36		19

RESULTS OF OPERATIONS

Six Months Ended June 30, 2006 (“Current Period”) compared with Six Months Ended June 30, 2005 (“Prior Period”)

General.  For the Current Period, the Company had a net loss of $1,949,846 on total revenues of $11,623,719. This compares to a net loss of $736,997 on total revenue of $1,625,824 during the Prior Period. The $9,997,895 increase in revenue represents the results of the initial steps that we are taking as an early stage developer of properties. We had 170 net wells producing at the end of the Current Period as compared to 47 net wells producing at the end of the Prior Period.

Oil and gas sales.  During the Current Period, oil and natural gas sales were $10,941,220 compared to $1,097,906 in the Prior Period. We produced 1,295,879 mcfe at a weighted average price of $8.44 compared to 164,483 mcfe at a weighted average price of $6.67. 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. Production from the Antrim shale play represented approximately 81% of our oil and natural gas revenue for the Current Period.

At the end of the Current Period, we had 170 net wells producing compared to 47 net wells at the end of the Prior Period. In addition, we placed 47 net wells into production during the Current Period. The favorable average price variance included $792,350 of realized gains from the natural gas hedging instrument entered into during the Current Period.

Other income.  Other income (exclusive of equity in loss of unconsolidated subsidiary) for the Current Period primarily includes pipeline revenue from the Hudson acquisition while the Prior Period includes prospect fees generated from joint ventures. During the Current Period, other income was $596,999 compared to $349,611 in the Prior Period. This increase was primarily due to the Hudson properties acquisition that includes a revenue generating pipeline business.

General and administrative expenses.  Our general and administrative expenses include officer and employee compensation, travel, audit, tax and legal fees, office supplies, utilities, insurance, other consulting fees and office related expenses. Effective January 1, 2006, general and administrative expenses excludes certain internal payroll and benefit costs that can be directly identified with our acquisition, exploration and development activities. For the Current Period, $992,372 of payroll and benefit costs were capitalized to oil and natural gas properties.

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The $2,116,317 increase in general and administrative expenses for the Current Period was the result of our growth strategy. This growth has resulted in substantial increases in employees and related costs, legal and accounting services related to SEC filings as well as increased consulting services. The Prior Period expenses reflect Aurora as a private entity whereas the Current Period represents the costs associated with becoming a public entity, execution of our growth strategy, and on-going costs of being a public company.

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

Production and lease operating expenses were $3,411,051 for the Current Period compared to $652,957 for the Prior Period. On a unit of production basis, production expenses were $2.63 per mcfe in the Current Period compared to $3.97 per mcfe for the Prior Period. The unit cost decrease in the Current Period was primarily attributable to the fixed costs of central processing facilities and water disposal facilities being spread over more production as new development wells come on-line. We also recognized transportation expense reduction of $225,113 due to the Hudson pipeline acquisition.

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

	Six Months Ended				Six Months Ended
	June 30, 2006				June 30, 2005
Expense Category	Per mcfe		Amount		Per mcfe		Amount
Severance taxes	$	.34	$	445,825	$	.30	$	49,079
Post-production expenses		.58		743,309		1.20		197,636
Lease operating expenses		1.71		2,221,917		2.47		406,242
Total	$	2.63	$	3,411,051	$	3.97	$	652,957

Depletion, depreciation and amortization (“DD&A”).  DD&A was $3,024,166 and $102,227 during the Current Period and the Prior Period, respectively. DD&A of oil and natural gas properties was $1,976,378 during the Current Period. This increase reflects the increase to the full cost pool of approximately $76.8 million. This represents wells being placed into production with costs being transferred from unproven properties to proven properties. In addition, there was an increase in depletion rates associated with the producing assets from the Cadence merger, since these assets have reserves with shorter lives than the Michigan Antrim shale.

��

Other depreciation and amortization was $1,047,788 during the Current Period of which $767,500 represented amortization of the intangible assets recognized in connection with the Cadence merger, $156,360 represented depreciation related to the Hudson pipeline acquisition, $34,005 represented amortization of asset retirement obligations and $89,923 represented depreciation of other property and equipment.

Interest expense.  Interest expense was $3,564,154 in the Current Period compared to $237,354 in the Prior Period. This increase is due to higher utilization of debt to continue our growth strategy of acquiring and developing operating interests in the Antrim shale and the New Albany shale. The amount of capitalized interest has decreased significantly from the Prior Period as our properties are transferred from undeveloped to producing or as financing is used for proven acquisition. As of June 30, 2006, we had borrowed $82.8 million compared to $20 million as of June 30, 2005.

Taxes.  Tax expense was $29,361 in the Current Period compared to $237,697 in the Prior Period. This decrease resulted from the reversal of an accrual related to the January 2005 sale of the 95% working interest to El Paso Corporation in certain New Albany shale acreage.

Year Ended December 31, 2005 compared with Year Ended December 31, 2004

Revenues.  We generate revenue primarily from the following sources: the sale of oil and natural gas; providing lease project management services; providing administrative overhead services for certain producing

29

properties; and the sale of certain leasehold projects. A comparative summary of the composition of our revenue for the years ended 2005 and 2004 is as follows:

	2005						2004
	Amount			% of Total			Amount		% of Total
Oil and natural gas sales	$	6,743,444			92	%	$	960,011		44	%
Other income		452,621			6	%		1,192,835		54	%
Equity in loss of subsidiary		(75,596	)		(1	)%		—		—
Interest income		243,013			3	%		47,678		2	%
Total revenues	$	7,363,482			100	%	$	2,200,524		100	%

During 2005, total revenues were $5,162,958 higher than the total revenues for 2004, a 235% increase. Production revenues for 2005 increased by $5,783,433 or a 602% increase from 2004. This increase was due to increased drilling activity in 2005 and late 2004, which resulted in an increased number of wells generating natural gas production revenue. Other income for 2005 decreased $740,214, a 62% decrease from 2004. This decrease was due largely to the reduction in management fees we received. The decrease in management fees is due to our shift from leasehold acquisitions through various joint ventures to the development of leased properties to produce natural gas. The increase in interest income of $195,335 was earned on the funds raised in the private equity transaction.

In 2005, we reported net revenues of $65,643 from investments in the Hudson Pipeline and Processing Company, LLC and net loss of $(141,239) in GeoPetra Partners, LLC for a combined net loss from equity interest in subsidiaries of $(75,596). Other material sources of income from operations include: management fees of $347,857 and $883,687 and operator revenues of $94,315 and $309,148 for December 31, 2005 and 2004, respectively.

Natural gas, oil and related product sales.  Our oil and natural gas product sales for the years ended December 31, 2005 and December 31, 2004 were generated primarily from production from Michigan oil and natural gas properties. Our production revenue was generated from the sale of 687,271 net mcf of natural gas at an average price of $9.00 per mcf from wells in the Antrim and 10,628 barrels of oil at an average price of $52.54 per bbl from non-operated working interests in wells located in Michigan, Texas, Kansas and New Mexico.

A summary of oil and natural gas revenue sources by play/trend for the years ended December 31, 2005 and 2004 is as follows:

Play/Trend	2005		2004
Antrim	$	6,099,274	$	960,011
New Albany		80,166		—
Other		564,004		—
Total	$	6,743,444	$	960,011

For the year ended December 31, 2005, nearly 64% of our revenues were generated from the Hudson 34, Hudson SW and Hudson NE units of the Hudson project, which went on-line in December 2004, February 2005 and late April 2005, respectively. The remaining production revenue generated from natural gas sales came from our interests in the Beyer, Black Bean, Paxton Quarry, Treasure Island, Eastern Group, and Church Lake Field projects. There were also minor overriding royalties and working interest revenues received from certain New Albany shale projects.

Other revenues.  In addition to oil and natural gas production revenue, we also generate revenue from two other sources: management fees from the administration of certain lease projects and overhead fees charged for the administration of certain producing properties.

Expenses.  Our expenses break into five general categories: General and Administrative; Production and Lease Operating; Depletion, Depreciation and Amortization; Interest; and Taxes.

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Our general and administrative expenses include officer and employee compensation, rent, travel, audit, tax and legal fees, office supplies, utilities, insurance, other consulting fees and office related expenses. Expenses from oil and natural gas operations include services related to producing oil and natural gas, such as severance taxes, post production costs (including transportation), and lease operating expenses.

The following table is a comparison of our general categories of expenses for the years ended December 31, 2005 and 2004:

	2005		2004
General and administrative	$	3,435,507	$	2,057,333
Production and lease operating		2,047,028		614,338
Depletion, depreciation and amortization		1,155,254		203,249
Interest		1,228,274		392,402
Taxes		29,651		75,000
Total expenses	$	7,895,714	$	3,342,322

Our general and administrative expenses for 2005 increased $1,378,174, or 67%, from 2004 due to the increase in personnel added to accommodate our continued growth as we hire additional personnel to oversee the drilling program and additional accounting staff to meet SEC filing requirements. We also incurred significant professional fees related to SEC filings in late December 2005.

Production and lease operating expenses for 2005 increased $1,432,690 compared to 2004. This increase was due to additional producing wells on-line during 2005. This increase of 233% in production costs is offset by the 602% increase in related production revenue from 2004 to 2005.

Depletion, depreciation and amortization expense for 2005 increased $952,005 from 2004, or 468%, due to the increased capitalized costs subject to depletion. There were no drilling or completion related costs in the early quarters of 2004 that were subject to amortization.

Interest expense for 2005 increased $835,872, or 213%, from the year ended December 31, 2004. This increase is due to the increase in mezzanine debt, offset by the capitalizing of interest costs in 2005 during the drilling and development phase. Limited drilling activity in the first three quarters of 2004 resulted in all interest being recorded as an expense for those quarters.

Taxes recorded in the years ended December 31, 2005 and 2004 were property and other miscellaneous taxes and Indiana income taxes, respectively.

LIQUIDITY AND CAPITAL RESOURCES

We expect to fund our growth strategy using a combination of debt, existing cash balances, internally generated cash flows from natural gas production, and the proceeds from a public offering that we have just completed. Our 2006 capital budget for drilling and related well work and infrastructure is approximately $51.2 million with an anticipated participation in 221 (106 net) wells. Our 2006 capital budget for leasehold interest and property acquisitions is approximately $14.2 million and $39.3 million, respectively. Our 2007 capital budget for drilling and related well work and infrastructure is estimated to be approximately $105.6 million with an anticipated participation in 410 (228 net) wells. Our 2007 capital budget for leasehold interest and property acquisitions is estimated to be approximately $9 million and $1 million, respectively. We believe that the proceeds from the public offering, our available credit facilities with anticipated increases in our borrowing bases, and our operating cash flow will be sufficient to fund our operations and capital expenditures for the next 18 months. However, future cash flows are subject to a number of variables, including the level of production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures.

Our mezzanine financing is a $50 million term credit facility with certain affiliates of Trust Company of the West (“TCW”) for the Michigan Antrim shale drilling program. It is a non-revolving term loan facility that has a commitment expiration date of August 12, 2007 and a maturity date of September 29, 2009. Borrowings under the

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TCW credit facility as of June 30, 2006 were $40 million with available borrowing capacity of $10 million. The interest rate is fixed at 11.5% per year, compounded quarterly, and is payable in arrears. Beginning September 28, 2006 and quarterly thereafter, the required principal payment is 75% (100% if a coverage deficiency or default occurs) of “adjusted net cash flow” determined by deducting specified expenses, including capital expenditures from “gross cash revenue.” We estimate that no principal payments on the mezzanine financing will be required until maturity because of the level of our anticipated capital expenditures. We have granted TCW a security interest in certain of our Michigan Antrim shale assets. This security interest is subordinated to the security interest of our senior lender described below. The TCW loan agreement contains, among other things, a number of financial and non-financial covenants, including covenants prohibiting the declaration or payment of dividends and covenants requiring the maintenance of certain financial and operating ratios, including collateral coverage and proved developed producing coverage ratios. As of June 30, 2006, we were in compliance with all of the applicable covenants.

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

Our senior secured credit facility is a $100 million senior secured revolving credit facility with BNP Paribas (“BNP”). The amount that we can borrow under this facility is limited to the amount of our borrowing base, which is determined semi-annually and at certain other times by our lenders. The initial borrowing base under this facility was $40 million. Effective July 14, 2006, the borrowing base was increased to $50 million. As proved reserves are added, this borrowing base may increase to $100 million with TCW consent. This facility matures on the earlier of January 31, 2010 or 91 days prior to the maturity of the mezzanine credit facility with TCW, unless we elect to terminate the commitment earlier pursuant to the terms of the credit facility. This facility provides for interest on borrowings tied to BNP’s prime rate (or, if higher, the federal funds effective rate plus 0.5%) or a LIBOR-based rate (LIBOR multiplied by a statutory reserve rate) plus 1.25 to 2.0% depending on our borrowing base utilization. Our borrowing base utilization is the percentage of our borrowing base that is drawn under our senior credit facility from time to time. As our borrowing base utilization increases, our LIBOR-based interest rates increase under this facility. As of June 30, 2006, interest on borrowings under our senior credit facility had a weighted average interest rate of 7.02%. A required semi-annual reserve report may result in an increase or decrease in our borrowing base and hence our credit availability. On July 14, 2006, the senior secured credit facility was also amended to defer the application of the trailing 12-month interest coverage ratio covenant until the fourth quarter of 2006, and to provide for a reduced ratio for that quarter. At June 30, 2006, our total borrowings under this facility were $40 million.

The security for our senior secured credit facility includes a first lien position in certain of our Michigan Antrim shale assets, a guarantee from Aurora, and a guarantee from us, secured by a pledge of our stock in Aurora. The senior secured credit facility contains, among other things, a number of financial and non-financial covenants, including covenants relating to restricted payments, loans or advances to others, additional indebtedness, incurrence of liens, a prohibition on our ability to prepay our mezzanine term credit facility with TCW, geographic limitations on our operations to the United States, and the maintenance of certain financial and operating ratios, including a current ratio and an interest coverage ratio. As of June 30, 2006, we were in compliance with all of the applicable covenants.

Our short-term line of credit is a $5 million revolving line of credit with Northwestern Bank for general corporate purposes. At June 30, 2006, our total borrowings under this facility were $10,000 with available borrowing capacity of $4.9 million. The interest rate is the prime rate with interest payable monthly in arrears. Principal is payable at the expiration of the line of credit. Northwestern Bank has recently agreed to extend the expiration date to October 15, 2007.

From late December 2005 through early February 2006, we reduced the exercise price of certain outstanding options and warrants in order to encourage the early exercise of these securities. Each holder who took advantage of the reduced exercise price was required to execute a six-month lock up agreement with respect to the shares issued in the exercise. As a result of the options and warrants exercised pursuant to this reduced exercise price arrangement, and pursuant to other exercises of outstanding options, an additional 20,315,422 shares were issued

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during the six months ended June 30, 2006 representing 15,565,457 shares issued for cash proceeds of $18,144,449 and 4,749,965 shares issued pursuant to cashless exercises of the applicable warrants or options. In December 2005 an additional 2,160,000 shares were issued for cash proceeds of $2,916,000.

CAPITALIZATION

Our total capitalization was as follows:

	As of		As of		As of
	June 30,		December 31,		December 31,
	2006		2005		2004
Short-term bank borrowings	$	10,000	$	6,210,000	$	350,000
Obligations under capital lease		7,173		11,085		21,486
Related party notes payable		—		69,833		3,018,531
Mortgage payable		2,833,397		2,865,477		—
Mezzanine financing		40,000,000		40,000,000		10,000,000
Senior secured credit facility		40,000,000		—		—
Total debt		82,850,570		49,156,395		13,390,017
Redeemable convertible preferred stock		19,924		59,925		—
Shareholders’ equity		74,924,893		56,625,927		6,246,304
Total capitalization	$	157,795,387	$	105,842,247	$	19,636,321

The 439% increase in our capitalization from 2004 to 2005 was primarily due to a combination of an increase in our borrowing capacity and increases in shareholders’ equity. The increase in borrowings included $30 million of additional advances from our mezzanine facility and approximately $9 million in short-term and long-term bank borrowings, less approximately $3 million in payments of related party notes payable. The increase in shareholders’ equity is due primarily to the $36.3 million net increase recorded as a result of the merger, $11.0 million in proceeds received from a private equity infusion and $3.6 million in proceeds from the issuance of additional equity securities.

CASH FLOWS

Operating activities

We generated $2,636,906 in net cash from operations in the Current Period compared to using $459,971 in the Prior Period. The $3,096,877 increase was primarily due to higher realized prices and higher volumes of oil and natural gas production as discussed in the Results of Operations.

We used $411,196 in net cash for the year ended December 31, 2005 and generated $218,441 in net cash from operations for the year ended December 31, 2004. The decrease in 2005 from 2004 is due to changes in operating assets and liabilities of $(1,166,550) and $1,063,757 for December 31, 2005 and 2004, respectively. Specifically in 2005 we reported a revenue receivable from our joint venture partners of $2,409,675, which was received early in the first quarter of 2006.

Investing activities

Net cash flows used in investing activities was $32,845,786 in the Current Period compared to $7,946,216 used in the Prior Period. This excludes asset retirement obligations of $976,343, capitalized stock based compensation of $365,293 and investment adjustment for the Hudson acquisition of $1,366,887.

Cash used in investing activities for the year ended December 31, 2005 and December 31, 2004 was ($41,862,869) and ($8,716,784), respectively. This investing activity included the purchase of leasehold and working interests, drilling and development costs, purchase of office computers and other equipment, advances on notes receivable, and investments in Hudson Pipeline & Processing Co., LLC and GeoPetra Partners, LLC. Cash

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flows provided by investing activities for 2005 and 2004 include $7,995,109 and $1,902,537, respectively, of proceeds received from various sales of working interest and project interests.

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

							Year Ended
	Six Months Ended June 30,						December 31,
	2006			2005			2005			2004
Acquisitions of leaseholds
Antrim	$	3,342,686		$	1,059,396		$	7,195,372		$	2,447,028
New Albany(a)		18,036,545			2,429,786			8,376,805			980,985
Other		348,588			—			21,612			5,781
Drilling and development of oil and natural gas properties
Antrim		13,889,316			10,958,670			30,343,249			5,184,398
New Albany		639,623			—			—			—
Other		250,152			—			208,043			—
Infrastructure properties
Antrim		5,615,861			—			—			1,541,471
Other		45,440
Acquisitions of producing properties		290,869			—			3,206,102			—
Additions to pipeline		162,108			—			928,956			230,396
Additions to other investments		475,000			515,956			485,741			—
Additions to other property and equipment		219,694			105,674			3,594,750			74,166
Capitalized merger cost		—			263,092			—			—
Advances on note receivable		60,000			72,379			107,475			155,096
Subtotal of capital expenditures		43,375,882			15,404,953			54,468,105			10,619,321
Disposition of oil and natural gas properties(a)		(10,500,000	)		(7,373,737	)		(11,504,428	)		(1,902,537	)
Divestiture of other receivable and investment		(30,096	)		(85,000	)		(143,788	)		—
Net cash acquired in merger		—			—			(957,020	)		—
Subtotal of capital divestitures		(10,530,096	)		(7,458,737	)		(12,605,236	)		(1,902,537	)
Total(b)	$	32,845,786		$	7,946,216		$	41,862,869		$	8,716,784

(a)

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

(b)

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

Financing activities

Cash flows provided by financing activities for the Current Period were $21,823,195 compared to $16,743,071 during the Prior Period. Cash flows provided and used for the Current Period included: 1) $37,613,387 of senior

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secured borrowing, of which, $27,615,993 was paid directly for the Hudson acquisition; 2) $18,144,449 of proceeds received from exercise of common stock options and warrants; and 3) pay-down of $6,200,000 in short-term bank borrowings. Cash flows provided and used by financing activities for the Prior Period included: 1) $11,025,000 of proceeds received from sales of common stock; 2) $9,850,000 of mezzanine borrowing, net of financing costs of $150,000; 3) pay-off of $2,948,698 of certain related-party notes; and 4) distributions of $805,000 to minority interest members for their proportionate share of the El Paso sale proceeds.

During the year ended December 31, 2005, we covered our capital budget through the combination of advances from our mezzanine facility of $29.49 million in 2005 compared to advances of $10.17 million in 2004, (net of financing fees of $508,544 and $294,545, respectively) and from proceeds from the sale of equities of $14.6 million in 2005, compared to $2.9 million in 2004. The purchase of office space in 2005 was financed with a mortgage in the amount of $2.9 million. In December 2005 we increased our mezzanine credit facility with TCW from $30 million to $50 million under an amendment to the original Note Purchase Agreement. Borrowings under this facility as of December 31, 2005 were $40 million.

Cash flows provided by financing activities during the years ended December 31, 2005 and December 31, 2004 include the following:

	2005		2004
Advances from short term bank borrowings	$	5,860,000	$	350,000
Advances from mezzanine financing (net of fees)		29,491,458		10,179,694
Proceeds from issuance of common stock		14,666,625		2,920,000
Advances from building mortgage		2,865,477		—
Proceeds from notes payable		—		154,118
Proceeds from subsidiary disposition		—		10,467
Total cash flows provided by financing activities	$	52,883,560	$	13,614,279

RECENT ACCOUNTING PRONOUNCEMENTS

The following is a summary of recent accounting pronouncements issued in 2006. We do not expect any of the following pronouncements to have a material effect on our consolidated financial position, cash flows or results of operations.

In February 2006, the FASB issued SFAS 155, “Accounting for Certain Hybrid Financial Instrument” which eliminates the exemption from applying SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments. SFAS 155 also allows the election of fair value measurement at acquisition, at issuance, or when a previously recognized financial instrument is subject to a re-measurement event. Adoption is effective for all financial instruments acquired or issued after the beginning of the first fiscal year that begins after September 15, 2006.

In February 2006, the FASB issued Financial Staff Position (“FSP”) No. 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. We adopted this FSP in the second quarter of 2006.

In April 2006, the FASB issued FSP No. FIN 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R),” which requires the use of a “by design” approach for determining whether an interest is variable when applying FASB Interpretation No. 46, “Consolidation of Variable Interest Entities.” This approach includes evaluating whether an interest is variable based on a thorough understanding of the design of the potential variable interest entity (“VIE”), including the nature of the risks that the potential VIE was designed to create and pass along to interest holders in the entity. The guidance in this FSP is effective for

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reporting periods beginning after June 15, 2006. We will adopt the guidance presented in this FSP in the third quarter of 2006 on a prospective basis.

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

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 process of preparing consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues, and expenses. These estimates primarily relate to the valuation of oil and natural gas reserves and unsettled transactions and events as of the date of the financial statements. Accordingly, changes in facts and circumstances may result in revised estimates and actual results may vary from estimated amounts.

Oil and natural gas properties

We employ the full cost method of accounting for our oil and natural gas properties. Under the full cost method all costs related to the acquisition, exploration and development of oil and natural gas properties, including directly related overhead costs, are capitalized and accumulated into a single cost center referred to as a full cost pool. Proceeds from the sale or other disposition of oil and natural gas properties are applied to adjust the capitalized costs in the full cost pool with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proven reserves of oil and natural gas, in which case the gain or loss is recognized as income.

Oil and natural gas reserves

Proved oil and natural gas reserves, as defined by SECRegulation S-XRule 4-10(a)(2), (3) and (4), are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions including prices and costs as of the date the estimate is made. As of December 31, 2005, we did not have any of our natural gas production hedged. Therefore, the price used in the reserve report to calculate value was $9.89 per mcf, the price at which we sold our gas on December 31, 2005. The price used in the interim reserve report to calculate value at June 30, 2006 was $5.69 per mcf, which excluded any adjustments for natural gas hedging activity.

Our estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates made by our engineers are reviewed annually and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things reservoir performance, prices, economic conditions and governmental restrictions. Decreases in prices, for example, may

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cause a reduction in some proved reserves due to reaching limits sooner. A material change in the estimated volumes of reserves could have an impact on the depletion rate calculation reported in the consolidated financial statements.

Commodity price management activities

We recognize all hedging contracts 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 Instruments and Hedging Activities”, as amended, is dependent upon whether or not a contract 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 our balance sheet until the hedged item is recognized in earnings as gas revenue. If a hedge contract has an ineffective portion, that particular portion of the gain or loss would be immediately reported in earnings.

Ceiling test

Companies that use the full cost method of accounting for oil and natural gas properties are required to perform the ceiling test each quarter. The ceiling is an impairment test performed as prescribed by SECRegulation S-XRule 4-10. The test determines a limit, or ceiling, on the book value of oil and natural gas properties. That limit is the after-tax value of the future net cash flows from proved crude oil and natural gas reserves discounted at ten percent per annum. This ceiling is compared to the net book value of the oil and natural gas properties and reduced by the related net deferred income tax liability and asset retirement obligations. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the ceiling, impairment or non-cash write down is required. A charge to income for impairment could give us a significant loss for a particular period. However, future depletion expense would be reduced.

The ceiling test is affected by a decrease in net cash flow from reserves due to higher operating or capital costs or reduction in market prices for natural gas and crude oil. These changes can reduce the amount of economically producible reserves. We were not required to record a charge for impairment during the year ended December 31, 2005 or the six months ended June 30, 2006.

Income taxes

Income taxes are provided for based upon the liability method of accounting pursuant to SFAS No. 109, “Accounting for Income Taxes.” Under this approach, deferred income taxes are recorded to reflect the tax consequences in future years of differences between the tax basis of assets and liabilities and their financial reporting amounts at each year-end. A valuation allowance is recorded against deferred tax assets if we do not believe that we have met the “more likely than not” standard imposed by SFAS No. 109 to allow recognition of such an asset.

At December 31, 2005, we had net deferred tax assets calculated at an expected rate of 34% of approximately $10,145,800. Because we cannot determine that it is more likely than not that we will realize the benefit of the net deferred tax asset, a valuation allowance equal to the net deferred tax asset has been established at December 31, 2005.

Stock-based compensation

On January 1, 2006, we 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. We 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.

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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. These increased capitalized costs were 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 are using SFAS No. 123R. Aurora stock options outstanding as of the date of the merger are not accounted for under APB Opinion 25 or SFAS 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 off-balance sheet arrangements, special purpose entities, financing partnerships or guarantees.

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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 on October 31, 2005 through the merger of our wholly-owned subsidiary with and into Aurora. The acquisition of Aurora was accounted for as a reverse merger, with Aurora being the acquiring party for accounting purposes. The Aurora executive management team also assumed management control at the time the merger closed, and we moved our corporate offices to Traverse City, Michigan.

As a result of the reverse merger, the historical financial statements presented for periods prior to the acquisition date are the financial statements of Aurora. The operations of the former Cadence Resources Corporation have been included in the financial statements from the date of acquisition. Effective May 11, 2006, Cadence Resources Corporation amended its articles of incorporation to change its name to Aurora Oil & Gas Corporation.

Our strategy is to maximize shareholder value by leveraging our significant acreage position. As an early stage developer of properties, we anticipate that reserve growth will be our initial focus followed by a more traditional balance between reserve and production growth. Our six-month drilling program ending June 30, 2006 resulted in us participating in 72 (33 net) wells of which 52 (27 net) wells were waiting hook-up. As of June 30, 2006, we operated 175 (151 net) wells and participated in another 289 (57 net) wells operated by other companies. This 2006 drilling activity and a 24 bcfe acquisition increased our proved reserves by nearly 64% to 105 bcfe of which 99% were natural gas reserves.

OPERATING AREAS

Antrim shale

Our Antrim shale properties are located in Michigan and represent our primary area of development over the next 12 to 18 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 8,000 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 CO₂, organic material, and the heavier oil and gases stored in the shale.

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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, thegas-in-place is typically 90% methane or greater, with the balance being CO₂ 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 8,000 wells with comparable geologic characteristics, areas with natural fractures in shale have compelling production potential.

At June 30, 2006, we owned working interests in 384 Antrim wells. In the last 18 months, we have drilled 199 (135 net) Antrim wells and successfully completed 191 for a success rate of 96%. In 2005, we drilled and successfully completed or participated in a total of 143 (105 net) Antrim wells including three horizontal wells. During the first six months of 2006, we drilled and successfully completed or participated in a total of 54 (28.30 net) wells. We have budgeted for the drilling of 409 (228 net) Antrim wells during the18-month period beginning June 30, 2006 and ending December 31, 2007. On average, our Antrim wells are drilled to depths ranging from 250 to 1,500 feet targeting reserves of 0.5 bcfe per well and, based on our 2007 budget, cost approximately $325,000 to drill and complete each well.

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. Nearly all 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 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 15 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 is being implemented in 2006.

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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 sixty days. Our New Albany shale wells are drilled to depths ranging from 500 to 3,000 feet and based on a recent Schlumberger reserve report could yield reserves of 0.9 to 1.3 bcfe per well and, based on our 2007 budget, will cost approximately $850,000 to drill and complete each well. At June 30, 2006, we owned working interests in 27 (4.65 net) New Albany shale wells. In the last 18 months, we have drilled 19 (4.17 net) New Albany shale wells and successfully completed all of these wells for a success rate of 100%. In 2005, we drilled and successfully completed or participated in a total of 3 (.15 net) New Albany shale wells all of which were horizontal wells. During the first six months of 2006, we drilled and successfully completed 16 (4.02 net) New Albany shale wells. We have planned for the drilling of approximately 125 (52.4 net) New Albany shale wells, with the majority being horizontal wells, during the18-month period beginning July 1, 2006 and ending December 31, 2007.

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 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.

For 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 gas production that would otherwise be left in the reservoir.

In the Michigan Antrim, we usually use a simple proven completion procedure. This procedure involves drilling through several pay zones, setting and cementing casing, and drilling a rat-hole, which is used for gas-water separation. The wells are then hydraulically fractured with a specifically designed four-stage fracture procedure. 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 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 to12-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.

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Oil and natural gas reserves

The following table presents information as of June 30, 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 for New Albany and Antrim is based on reserve reports prepared by Schlumberger, copies of which are attached as Appendices A and B. According to this report, over 44% of our proved reserves in Antrim and New Albany are classified as either proved developed non-producing or proved undeveloped.

	As of June 30, 2006
									Standardized
Oil and Natural Gas Reserves(a)	Oil		Gas		Total		PV-10(d)		Measure(e)
	(mbbls)		(mmcf)		(mmcfe)		(In thousands)		(In thousands)
Proved developed producing		24		59,592		59,736	$	86,395	$	74,039
Proved developed non-producing		—		13,498		13,498		20,894		14,527
Proved undeveloped		67		32,198		32,600		28,749		28,156
Total proved(b)(c)		91		105,288		105,834	$	136,038	$	116,722

			Percent of
Oil and Natural Gas Reserves by Play/Trend(a)	Total		Proved Reserves			PV-10
	(mmcfe)					(In thousands)
Antrim		101,411		96	%	$	125,474
New Albany		1,922		2	%		3,457
Other(f)		2,501		2	%		7,107
Total		105,834		100	%	$	136,038

Change in reserve quantity information for the six months ended June 30, 2006(a)	Oil			Gas			Total
	(mbbls)			(mmcf)			(mmcfe)
Proved reserves as of December 31, 2005		99			63,322			63,916
Revisions of previous estimates		(38	)		(4,093	)		(4,321	)
Purchases of minerals in place		—			24,720			24,720
Extensions and discoveries		41			22,563			22,809
Production		(11	)		(1,224	)		(1,290	)
Proved reserves as of June 30, 2006		91			105,288			105,834

(a)	The information presented for New Albany and Antrim 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 the following financial hedges: (i) 5,000 mmbtu/day at a price of $8.59/mmbtu through March 2007 and (ii) 5,000 mmbtu/day at a price of $9.00/mmbtu from April 2007 through December 2008.
(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 June 30, 2006. The estimated future production is priced at June 30,

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2006, without escalation, using $69.32 per bbl and $5.69 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 ofPV-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 ofPV-10 to the most directly comparable GAAP measure — standardized measure of discounted future net cash flow — in the following table:

	As of June 30,		As of December 31,
	2006		2005		2004
Standardized measure of discounted future net cash flows	$	116,722,099	$	152,868,240	$	32,159,710
Add: Present value of future income tax discounted at 10%		19,316,221		46,639,200		15,750,790
PV-10	$	136,038,320	$	199,507,440	$	47,910,500

(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 calculatePV-10. Standardized measure differs fromPV-10 because standardized measure includes the effect of future income taxes. As noted in footnote (a) above, this excludes the impact of our hedges. If the impact of our hedges were included, the standardized measure would have been increased by $8,960,351 to $125,682,450.

(f)

The reserves shown in the “Other” line were internally generated numbers that are not derived from a report of independent reserve engineers.

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, 2006 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		95,457		35,510		157,177		90,483		252,634		125,993
New Albany		99,320		4,965		685,496		444,494		784,816		449,459
Other		16,178		1,821		52,111		44,017		68,289		45,838
Total		210,955		42,296		894,784		578,994		1,105,739		621,290

(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 tables summarize sales volumes, sales prices, and production cost information for the periods indicated:

	Six Months
	Ended June 30,		Year Ended December 31,
	2006		2005		2004
Production
Oil (bbls)		11,888		10,628		4,798
Natural gas (mcf)		1,224,551		687,271		151,241
Natural gas equivalent (mcfe)		1,295,879		751,039		180,029
Oil and natural gas sales
Oil sales	$	741,110	$	558,455	$	226,599
Natural gas sales		10,200,110		6,184,989		733,412
Total	$	10,941,220	$	6,743,444	$	960,011
Average sales price (including realized gains or losses from hedging)
Oil ($ per bbl)	$	62.34	$	52.54	$	47.23
Natural gas ($ per mcf)		8.33		9.00		4.85
Natural gas equivalent ($ per mcfe)		8.44		8.98		5.33
Average production cost
Natural gas equivalent ($ per mcfe)	$	2.63	$	2.73	$	3.41

Productive wells

The following table sets forth information at June 30, 2006, relating to the productive wells in which we owned a working interest as of that date. 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
	Gross		Net		Gross		Net
Play/Trend	Wells		Wells		Wells		Wells
Antrim		384		184.76		—		—
New Albany		27		4.65		—		—
Other		29		8.25		24		9.68
Total		440		197.66		24		9.68

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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.

		Gross Wells						Net Wells
Period	Type of Well	Productive(b)		Dry(c)		Total		Productive(b)		Dry(c)		Total
Six Months Ended June 30, 2006	Exploratory(a)
	Antrim		—		—		—		—		—		—
	New Albany		8		—		8		3.62		—		3.62
	Other		2		2		4		0.92		1		1.92
	Total		10		2		12		4.54		1		5.54
	Development(a)
	Antrim		54		2		56		28.30		1.05		29.35
	New Albany		8		—		8		0.40		—		0.40
	Other		—		—		—		—		—		—
	Total		62		2		64		28.70		1.05		29.75
Year Ended December 31, 2005	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		3.4		104.77
	New Albany		3		—		3		0.15		—		0.15
	Other		—		—		—		—		—		—
	Total		139		5		144		101.52		3.4		104.92
Year Ended December 31, 2004	Exploratory(a)
	Antrim		—		—		—		—		—		—
	New Albany		—		—		—		—		—		—
	Total		—		—		—		—		—		—
	Development(a)
	Antrim		84		3		87		25.06		1.18		26.24
	New Albany		—		4		4		—		0.20		0.20
	Total		84		7		91		25.06		1.38		26.44

(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.

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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 CO₂ 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. 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.

We recently entered into a firm delivery gas contract to be effective for the period April 1, 2006 through March 31, 2007 for the delivery of 5,000 mmbtu per day. We will be paid $0.01 per mcf less than the published index for this gas. This contract will cover much of our existing production.

We also have three 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. For example, demand for natural gas has increased in recent years due to a trend in the power plant industry to move away from using oil and coal as a fuel source to using natural gas, because natural gas is a cleaner fuel. 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.

Effective April 1, 2006, we entered into a financial swap contract for 5,000 mmbtu per day at a fixed price of $8.59 per mmbtu covering a12-month period. On July 14, 2006, we entered into another financial swap contract for 5,000 mmbtu per day at a fixed price of $9.00 per mmbtu for the period from April 1, 2007 through December 31, 2008.

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 June 30, 2006, we have 53 full time employees and two 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. Factors that affect our ability to acquire producing properties include available funds, available information about

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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 ofand/or demand for oil and natural gas and thus the prices available for sales of oil and natural gas.

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 re-negotiation 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.

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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.

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 (Michigan) 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.

Legal proceedings

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

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MANAGEMENT

The following table sets forth the name, age and position of each of our executive officers and directors as of June 30, 2006.

Name	Age		Position(s) with the Company
William W. Deneau		62	Director, Chairman and President
Ronald E. Huff		51	Director and Chief Financial Officer
John V. Miller, Jr.		48	Vice President, Science and Strategic Planning
Thomas W. Tucker		64	Vice President, Operations
Kevin D. Stulp		50	Director
Richard M. Deneau		60	Director
Gary J. Myles		61	Director
Earl V. Young		65	Director

Our Board of Directors is comprised of seven persons. We currently have one vacancy and are conducting a search for a person to fill this vacancy. Information about our incumbent directors and executive officers follows.

William W. Deneauhas served as our President and Chairman of the Board of Directors since November 1, 2005. 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 officially became a Director of Aurora on June 25, 1997 and the President of Aurora on July 17, 1997. Since 1987, Mr. Deneau has also been the President, a Director, and the sole owner of White Pine Land Services, Inc. of Traverse City, Michigan. Prior to March 1, 1997, White Pine Land Services, Inc. was a 35-member company engaged in the business of providing real estate services to oil and gas companies. On March 1, 1997, White Pine Land Services, Inc. sold its business to a newly formed corporation, White Pine Land Company. White Pine Land Services, Inc. continues to exist for the purpose of managing its investments. William W. Deneau is the brother of Richard M. Deneau, another one of our Directors.

Ronald E. Huff, CPA, has served as our Chief Financial Officer since June 19, 2006 and as a Director since November 21, 2005. 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. Mr. Huff worked for Belden & Blake Corporation from 1986 to 1999 as its Chief Financial Officer and was also its President from 1997 to 1999. Belden & Blake Corporation acquired properties, explored for and developed oil and gas reserves, and marketed natural gas, primarily in the Appalachian and Michigan Plays/trends. It went through a successful initial public offering in 1992, and was acquired by Texas Pacific Group in 1997. From 1983 to 1986 Mr. Huff was the Chief Accounting Officer of Zilkha Petroleum; from 1980 to 1983, he was a financial analyst for Southern Natural Resources, a natural gas marketing company; and from 1977 to 1980 he was a corporate accountant with Transco Companies Incorporated.

John V. Millerhas served as our Vice President, Science and Strategic Planning, since May 2006, and served as Vice President of Exploration and Production from November 1, 2005 to May 2006. 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. In 1994, Mr. Miller joined Jet Exploration, Inc. of Traverse City, Michigan, as a Vice President with responsibility for getting Jet Exploration, Inc. into the shale gas play in Michigan and Indiana. He was the driving force behind the establishment of Jet/LaVanway Exploration, L.L.C. and its effort in southern Indiana. Mr. Miller left the position with Jet Exploration, Inc. to join Aurora. From 1988 to 1994, Mr. Miller worked for White Pine Land Services, Inc. of Traverse City, Michigan, as Land Manager.

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Thomas W. Tuckerhas served as our Vice President of Operations since May 2006, and served as Vice President of Land and Development from November 2005 to May 2006. 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 the present, 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. Mr. Tucker founded Jet Oil Corporation with his father in 1982. In 1987, after his father’s death, Mr. Tucker founded Jet Exploration, Inc. Mr. Tucker has been the President of Jet Exploration, Inc. since its inception. Jet Exploration, Inc. no longer takes on any new projects, and its existing projects are being allowed to run out their course.

Kevin D. Stulphas served on our Board of Directors since March 1997. Since August 1995, Mr. Stulp has variously worked as consultant with Forte Group, on the board of the Bible League, and is active with various other non-profit organizations. 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. Mr. Stulp holds a B.S.L.E. from Calvin College, Grand Rapids, Michigan, and a B.S.M.E. in Mechanical Engineering and an M.B.A. from the University of Michigan.

Richard M. Deneauhas 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, was 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. Prior to working for Anchor, Richard M. Deneau served in management at Ball Foster Glass Container Corp., American National Can, Foster Forbes Glass and First National Bank of Lapeer. He served as an auditor with Ernst & Ernst after graduating from Michigan State University in 1968. Richard M. Deneau is the brother of William W. Deneau, our President and Chairman of the Board of Directors.

Gary J. Myleshas 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 $3,500,000 annually. Mr. Myles had been with Fifth Third Bank and its predecessor, Old Kent Mortgage Company, since July 1988. Mr. Myles also owns Foster Care, Ltd., a closely held company for which he serves as a Director, President and Treasurer. Mr. Myles is the chairperson of our Audit Committee and Nominating and Corporate Governance Committee.

Earl V. Younghas 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 exploration in Madagascar. From 1996 to 1999, Mr. Young was the Senior Vice President of Corporate Development for American Mineral Fields, Inc. of Dallas, Texas. From 1993 to 1996, Mr. Young was a principal in Young & Lowe, which offered business consulting services to small capitalization companies. Prior to 1993, Mr. Young was involved in the investment banking business. He is President of the US/Madagascar Business Council headquartered in Washington, D.C. and a Director of the Corporate Council on Africa in Washington D.C. Mr. Young was a gold medalist in the Summer Olympic Games in 1960 in track, has served as President of the Southwest Chapter of Olympians, and was the founding chairman of the Olympians for Olympians Relief Committee. Mr. Young is the chairperson of our Compensation Committee.

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Indemnification

Our bylaws provide that our directors and officers will be indemnified to the fullest extent permitted by the Utah Corporation Code. However, such indemnification does not apply to acts of intentional misconduct, a knowing violation of law, or any transaction where an officer or director personally received a benefit in money, property, or services to which the director was not legally entitled.

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, we have been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable.

BOARD COMMITTEES

The composition of our board committees is as follows:

•  Audit Committee:  Gary J. Myles (Chairman), Earl V. Young and Kevin D. Stulp;

•  Compensation Committee:  Earl V. Young (Chairman), Kevin D. Stulp and Gary J. Myles; and

•  Nominating and Corporate Governance Committee:  Gary J. Myles (Chairman), Earl V. Young, and Kevin D. Stulp.

The board of directors has designated the following directors as independent directors: Gary J. Myles, Kevin D. Stulp and Earl V. Young.

Each of our Audit Committee members is an independent outside director, and one, Gary J. Myles, is a financial expert with knowledge of financial statements, generally accepted accounting principles and accounting procedures and disclosure rules. His credentials are described in greater detail above.

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.

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 Cadence operations. 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, 2004 and 2003, and compensation paid by Cadence for the months of November and December 2005.

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SUMMARY COMPENSATION TABLE

							Long-Term Compensation Awards
	Annual Compensation						Value of Restricted			# of Securities
Name and Principal Position	Year		Salary(a)		Bonuses		Stock Awards(b)			Underlying Options
William W. Deneau		2005	$	140,000	$	—	$	—			—
President, Chief Executive Officer		2004		90,000
		2003		52,500
John V. Miller, Jr.		2005		125,000		—		—			—
Vice President, Science and		2004		90,000
Strategic Planning		2003		63,300
Thomas W. Tucker,		2005		125,000		—		—			—
Vice President, Operations		2004		90,000
		2003		52,500
Lorraine M. King,		2005		125,000		—		116,400	(d)		20,000 shares	(e)
Chief Financial Officer(c)		2004		65,000		25,000		—			20,000 shares	(f)
		2003		65,000		—		—			20,000 shares	(f)

(a)	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.
(b)	Because all of the shares we issued in exchange for Aurora stock in the merger were registered under theForm S-4 registration statement, none of the named executive officers held restricted stock at December 31, 2005.
(c)	Effective June 19, 2006, Lorraine M. King resigned her position as Chief Financial Officer, and Ronald E. Huff became our Chief Financial Officer. Ms. King is now our Treasurer.
(d)	Ms. King was awarded 30,000 shares of common stock by the Board of Directors on December 8, 2005. The closing price at which our stock traded on that date was $3.88 per share. Issuance of these shares was deferred until aForm S-8 registration statement was filed with the SEC, but the compensation related to this award was recorded as an expense in the 2005 consolidated financial statements.
(e)	Option to purchase 10,000 shares of Aurora common stock at an exercise price of $3.50 per share; converted in the merger into the right to purchase 20,000 shares of our common stock at an exercise price of $1.75 per share.
(f)	Option to purchase 10,000 shares of Aurora common stock at an exercise price of $0.75 per share; converted in the merger into the right to purchase 20,000 shares of our common stock at an exercise price of $0.375 per share.

OPTION GRANTS IN 2005
Individual

	# of Securities			% of Total Options			Exercise
	Underlying Options			Granted to Employees			Price per			Expiration
Name	Granted			in Fiscal Year			Share (a)			Date
Lorraine M. King(b)		20,000	(c)		7	%	$	1.75	(c)		10/18/15

(a)	At the date of grant, Aurora had not yet merged with Cadence, and Aurora was not publicly traded. Accordingly, there was no market price at the date of grant.
(b)	Effective June 19, 2006, Lorraine M. King resigned her position as Chief Financial Officer and Ronald E. Huff became our Chief Financial Officer. Ms. King is now our Treasurer.
(c)	This award was initially for 10,000 shares of Aurora’s common stock with an exercise price of $3.50 per share, and was converted in the merger as described in the table.

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AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION VALUES

	Shares				# of Securities Underlying				Value of Unexercised
	Acquired				Unexercised Options at				In-the-Money Options at
	on		Value		12/31/05				12/31/05(a)
Name	Exercise		Realized		Exercisable		Unexercisable		Exercisable		Unexercisable
William W. Deneau		0		0		600,000		0	$	2,475,000		—
John V. Miller, Jr.		0		0		600,000		0		2,475,000		—
Thomas W. Tucker		0		0		600,000		0		2,475,000		—
Lorraine M. King(b)		0		0		160,000		0		638,900		—

(a)	Options are“in-the-money” if the market price of a share of common stock exceeds the exercise price of the option.
(b)	Effective June 19, 2006, Lorraine M. King resigned her position as Chief Financial Officer and Ronald E. Huff became our Chief Financial Officer. Ms. King is now our Treasurer.

We do not currently have any long term incentive compensation plans in place.

As compensation for their services as directors of Aurora during 2005 and prior to the merger, on December 8, 2005, our board voted to award Earl V. Young and Gary J. Myles each 30,000 shares of common stock, to be issued in 2006 after the shares are registered on aForm S-8 registration statement. These shares were awarded in lieu of awarding stock options that would otherwise have been issued, but were deferred due to the ongoing work on the merger, which extended through most of 2005.

The following are our standard compensation arrangements for service as a director, post-merger:

Option to purchase 200,000 shares of our common stock at an exercise price of $3.62 per share; 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 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 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 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 chairman.

Prior to the merger, we had a different arrangement for compensating directors, as follows:

All directors were reimbursed forout-of-pocket expenses in connection with attendance at meetings of the board of directors. During the fiscal year ended September 30, 2005, each non-employee director received (1) $5,000 and 5,000 shares of restricted stock per quarter of completed service, (2) 2,500 restricted shares of common stock for each year of service on any committee of the board of directors, (3) $2,500 for chair of the Audit Committee and $1,000 for any other committee which they chaired, and each director (employee or non-employee) was entitled to an option to purchase 50,000 shares of our common stock on the anniversary of his appointment to the board.

During the fiscal year ended September 30, 2005, Messrs. Christian, DeHekker and Stulp, the three non-employee directors, each received options to purchase 50,000 shares of our common stock at an exercise price of $1.42 per share, and Messrs. Crosby and Ryan, the employee directors, each received options to purchase 50,000 shares of our common stock at an exercise price of $1.21 per share. Also for the September 30, 2005 fiscal year, Messrs. Christian, Crosby, DeHekker, Ryan and Stulp each received 15,000 shares of our common stock per quarter for the first three quarters of 2005 as compensation for their service on the board of directors.

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Messrs. DeHekker and Stulp received an additional 4,000 shares of our common stock for their service on a committee of the board of directors.

In addition, subsequent to September 30, 2005, each of Messrs. Christian, DeHekker and Ryan, the directors resigning because of the merger with Aurora, received warrants to purchase an aggregate of 37,500 shares of our common stock, consisting of a warrant to purchase 12,500 shares of our common stock for a purchase price of $2.53 per share, a warrant to purchase 12,500 shares of our common stock for a purchase price of $2.23 per share, and a warrant to purchase 12,500 shares of our common stock for a purchase price of $3.28 per share.

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 approximately $2.1 million 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. 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.

We do not have any other contractual arrangements with our executive officers or directors, nor do we have any compensatory arrangements with our executive officers other than as described above. Except as described above with respect to Mr. Huff, we have not agreed to make any payments to our named executive officers because of resignation, retirement or any other termination of employment with us or our subsidiaries, or from a change in control of us, or a change in the executive’s responsibilities following a change in control.

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PRINCIPAL AND SELLING SECURITY HOLDERS

Principal shareholders

The following table sets forth, as of November 13, 2006, certain information regarding the ownership of our voting securities by each shareholder known to our management 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. We believe that, except as otherwise indicated, 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.

	Amount and Nature
	of Beneficial			Percent of
Name and Address of Beneficial Owner(a)	Ownership(b)			Outstanding Shares
FMR Corp.		9,836,246	(c)		9.5	%
82 Devonshire Street
Boston, Massachusetts 02109
Nathan A. Low Roth IRA and affiliates		7,657,766	(d)		7.4	%
641 Lexington Avenue
New York, New York 10022
Crestview Capital Master, LLC		5,542,320			5.4	%
95 Revere Drive, Suite A
Northbrook, Illinois, 60062
William W. Deneau		4,232,500	(e)		4.1	%
Thomas W. Tucker		3,888,194	(f)		3.8	%
John V. Miller, Jr.		3,308,262	(g)		3.2	%
Kevin D. Stulp		527,500	(h)		0.5	%
Earl V. Young		416,204	(i)		0.4	%
Gary J. Myles		308,798	(j)		0.3	%
Richard M. Deneau(k)		—			—
Ronald E. Huff(l)		—			—
All executive officers and directors as a group (8 persons)		12,681,458	(m)		12.3	%

(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 SEC on September 13, 2006, 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 9,768,546 shares of common stock. Edward C. Johnson 3d and members of his family form a controlling group with respect to FMR Corp. Accordingly, FMR Corp. and Edward C. Johnson 3d have the sole power to dispose of 9,768,546 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 67,700 shares of common stock, and FMR Corp and Edward C. Johnson 3d have the sole dispositive power and sole power to vote or direct the voting of the 67,700 shares of common stock beneficially owned by Fidelity Management Trust Company.

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(d) Based on information included in an amendment to Schedule 13D/A filed with the SEC on January 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.

(e) Includes 3,272,000 shares of common stock held by the Patricia A. Deneau Trust; 940,500 shares of common stock held by the Denthorn Trust; and 20,000 shares of common stock held by White Pine Land Services, Inc. Does not include an option to purchase 200,000 shares of common stock vesting as follows: 60,000 shares on January 1, 2007; 70,000 shares on January 1, 2008; and 70,000 shares on January 1, 2009.

(f) Includes 1,607,574 shares of common stock held by the Sandra L. Tucker Trust; 24,646 shares of common stock held by Jet Exploration, Inc.; 1,615,974 shares of common stock held by the Thomas W. Tucker Trust; and options currently exercisable for 40,000 shares of common stock.

(g) Includes 1,000,000 shares of common stock held by Miller Resources, Inc.; 1,689,762 shares of common stock owned by Circle M, LLC; 500,000 shares of common stock held by the John V. Miller Jr. Living Trust DTD 7/21/05; 18,500 shares of common stock held by the Michelle R. Miller and options currently exercisable for 40,000 shares of common stock.

(h) Includes options currently exercisable for 50,000 shares of common stock and warrants currently exercisable for 100,000 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 200,000 shares of common stock vesting as follows: 60,000 shares on January 1, 2007; 70,000 shares on January 1, 2008; and 70,000 shares on January 1, 2009.

(i) Includes options currently exercisable for 199,998 shares of common stock. Does not include an option to purchase 200,000 shares of common stock vesting as follows: 60,000 shares on January 1, 2007; 70,000 shares on January 1, 2008; and 70,000 shares on January 1, 2009.

(j) Includes 77,800 shares of common stock held by the Gary J. Myles & Rosemary Myles Inter Vivos Trust; and options currently exercisable for 199,998 shares of common stock. Does not include an option to purchase 200,000 shares of common stock vesting as follows: 60,000 shares on January 1, 2007; 70,000 shares on January 1, 2008; and 70,000 shares on January 1, 2009.

(k) Does not include an option to purchase 200,000 shares of common stock vesting as follows: 60,000 shares on January 1, 2007; 70,000 shares on January 1, 2008; and 70,000 shares on January 1, 2009.

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

(m) Includes options and warrants currently exercisable for a total of 629,996 shares of common stock.

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Selling security holders

We issued to the selling security holders the common stock and the options and warrants to purchase common stock that are covered by this prospectus pursuant to private placements in (i) October 2002, (ii) April through June 2003, (iii) September 2003, (iv) October 2003, and (v) April 2, 2004 (the “April Private Placement”).

This prospectus relates to the resale from time to time of up to a total of 3,919,540 shares of our common stock by the selling security holders identified in this prospectus. 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 this transaction.

The options being registered on behalf of American Friends of Ohr Somayach, American Friends of Yeshiva D’Mir, American Friends of Shalva, American Friends of Yad Ezra, Marcia Kucher, Lisa Low as custodian for Daniel Low, Michael Low, Gabriel Low and Chantal Low and Jason Lyons are exercisable at a price of $2.50 per share and expire in September 2008. These options may be exercised on a cashless basis at any time. The options being registered on behalf of Proteus Capital Corp. are exercisable at a price of $1.75 per share and expire on June 18, 2007.

In the April Private Placement, we sold 120 units at the price of $50,000 per unit to seven accredited investors for an aggregate sales price of $6,000,000. Each unit consisted of a senior secured note in the principal amount of $50,000 and a warrant to purchase 6,375 shares of our common stock, exercisable at $4.00 per share. On January 31, 2005, we entered into an agreement with the investors in the April Private Placement pursuant to which we paid off the notes in full and reduced the exercise price of the warrants to $1.25 per share.

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 that: (i) Guma Aguiar was an officer and director prior to November, 2005, and Ellen Aguiar is Guma Aguiar’s mother; (ii) Derek Caldwell is an employee of Sunrise Securities Corporation, which is controlled by Nathan A. Low, and has performed institutional investor relations services for us; (iii) Nathan A. Low acted as a finder for us in the April Private Placement described above and has done so in prior and subsequent placements, for which he was compensated by us; and (iv) Douglas Newby, who controls Proteus Capital Corp., was our Vice President prior to mid-2005.

	Shares of Common				Beneficial		Percent of Class
	Stock Beneficially				Ownership After		Owned After
	Owned Prior to		Shares of Common		Offering if All		Offering if All
Selling Security Holders	Offering*		Stock to be Sold*		Shares are Sold*		Shares are Sold**
Moshe Azouley(1)		227,500		227,500		0		0
Nathan A. Low Affiliates(2)		7,657,766		0		7,221,016		7.0	%
Lisa Low as Custodian for Gabriel S. Low UNYGMA		—		57,375		—		—
Nathan A. Low		—		207,500		—		—
Bear Stearns as Custodian for Nathan A. Low Roth IRA		—		31,875		—		—
Lisa Low, as Custodian for Daniel Low		—		5,000		—		—

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	Shares of Common				Beneficial		Percent of Class
	Stock Beneficially				Ownership After		Owned After
	Owned Prior to		Shares of Common		Offering if All		Offering if All
Selling Security Holders	Offering*		Stock to be Sold*		Shares are Sold*		Shares are Sold**
Lisa Low, as Custodian for Michael Low		—		70,000		—		—
Lisa Low, as Custodian for Gabriel Low		—		10,000		—		—
Lisa Low, as Custodian for Chantel Low		—		15,000		—		—
Nathan Low Family Trust DTD 4/12/96		—		40,000		0		0
Ruth Low		58,250		58,250		0		0
Omicron Capital(3)		127,500		127,500		0		0
Portside Growth and Opportunity Fund(4)		195,300		195,300		0		0
Smithfield Fiduciary LLC(5)		655,000		655,000		0		0
Ellen Aguiar		461,283		300,000		161,283		***
American Friends of Ohr Somayach(6)		11,860		11,860		0		0
American Friends of Shalva(7)		10,280		10,280		0		0
American Friends of Yad Ezra(8)		20,000		20,000		0		0
American Friends of Yeshiva(9) D’Mir		20,000		20,000		0		0
B* Capital(10)		10,000		10,000		0		0
Balestra Capital Partners, L.P.(11)		25,900		25,900		0		0
Michael S. Berlin		40,000		40,000		0		0
Merlin Bingham		5,180		5,000		180		***
Derek Caldwell		60,000		34,000		26,000		***
Concorde Bank Limited(12)		15,000		15,000		0		0
Robert Darbee		10,000		10,000		0		0
David A. Dayton and Carol Dayton		7,000		7,000		0		0
Robert Denison		55,000		50,000		5,000		***
Buzz Fairchild		10,000		10,000		0		0
Carol Gatewood IRA		25,000		25,000		0		0
Floyd E. Hambleton		91,250		20,000		71,250		***
Stephen M. Harris		25,000		25,000		0		0
Joy A. Henshel		5,000		5,000		0		0
James H. Harris, MD PSP Trust		10,000		10,000		0		0
Joseph Klein III 10% Charitable Remainder Unitrust		12,000		12,000		0		0
Marcia Kucher		500		500	��	0		0
LCM Holdings, LDC(13)		3,560,181		160,000		3,400,181		3.3	%
Nathan Leight		13,200		13,200		0		0
John S. Lemak		100,000		100,000		0		0
Jason Lyons		500		500		0		0
Scott Mager		100,000		100,000		0		0

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	Shares of Common				Beneficial		Percent of Class
	Stock Beneficially				Ownership After		Owned After
	Owned Prior to		Shares of Common		Offering if All		Offering if All
Selling Security Holders	Offering*		Stock to be Sold*		Shares are Sold*		Shares are Sold**
James E. McDowell and Janet L. McDowell		10,000		10,000		0		0
Scott Notowitz and Shari Notowitz		25,000		25,000		0		0
Paul Papi		20,000		20,000		0		0
Michael Pisani		20,000		20,000		0		0
Proteus Capital Corp.(14)		317,000		50,000		267,000		***
Michael Ritger		5,000		5,000		0		0
William J. Ritger		258,334		250,000		8,334		***
Elaine Roberts Investment Trust		25,000		25,000		0		0
Seaside Partners, L.P.(15)		40,000		40,000		0		0
Sherleigh Associates Inc. PSP(16)		80,000		80,000		0		0
Joyce Stump		10,000		10,000		0		0
Joseph A. Tedesco		10,000		10,000		0		0
Charles Wafer		50,000		50,000		0		0
Michael H. Weiss		180,000		180,000		0		0
Wallis W. Wood		3,000		3,000		0		0
Winton Capital Holdings Ltd.(17)		6,000		6,000		0		0
York Global Value Partners, L.P.(18)		63,854		63,854		0		0
York Select L.P.(18)		203,566		203,566		0		0
York Select Unit Trust(18)		127,580		127,580		0		0
Totals		15,079,784		3,919,540		11,160,244		10.8	%

* 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 and options 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 the merger with Aurora closed, except in the cases where a Schedule 13D or Schedule 13G filing reflect different information.

** The percent of class information assumes that the number of shares outstanding includes shares issued in the public offering that we expect to complete in the near future, excluding the underwriters’ over-allotment option shares, and is therefore based upon a total of 103,062,966 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 the merger with Aurora closed, 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 1%
(1)	Shares of common stock beneficially and to be sold includes warrants to purchase 127,500 shares of our common stock.

(2) See footnote (d) above under the heading “Principal Shareholders”. Nathan A. Low controls Sunrise Securities Corporation, a registered broker-dealer. In this registration statement he is not acting as an underwriter because he purchased the shares in the ordinary course of business and represented to us at the

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time of purchase that he had no agreements or understandings, directly or indirectly, with any party to distribute the securities.

(3) We have been informed that Bruce Bernstein is the controlling person of Omicron Capital.

(4) Ramius Capital Group, LLC (“Ramius Capital”) is the investment advisor of Portside Growth & Opportunity Fund (“Portside”) and consequently has voting control and investment discretion over securities held by Portside. Ramius Capital disclaims beneficial ownership of the shares held by Portside. Peter A. Cohen, Morgan B. Stark, Thomas W. Strauss and Jeffrey M. Solomon are the sole managing members of C4S & Co., LLC, the sole managing member of Ramius Capital. As a result, Messrs. Cohen, Stark, Strauss and Solomon may be considered beneficial owners of any shares deemed to be beneficially owned by Ramius Capital. Messrs. Cohen, Stark, Strauss and Solomon disclaim beneficial ownership of these shares.

(5) Highbridge Capital Management, LLC is the trading manager of Smithfield Fiduciary LLC and consequently has voting control and investment discretion over securities held by Smithfield Fiduciary LLC. Glenn Dubin and Henry Swieca control Highbridge Capital Management, LLC. Each of Highbridge Capital Management, LLC, Glenn Dubin and Henry Swieca disclaims beneficial ownership of the securities held by Smithfield Fiduciary LLC.

(6) We have been informed that Nota Schieller is the controlling person of American Friends of Ohr Somayach.

(7) We have been informed that Leo Klein is the controlling person of American Friends of Salva. Shares of common stock beneficially owned and to be sold consist of 10,280 shares of common stock issuable upon exercise of options.

(8) We have been informed that Zvi Waldman is the controlling person of American Friends of Yad Ezra. Shares of common stock beneficially owned and to be sold consist of 20,000 shares of common stock issuable upon exercise of options.

(9) We have been informed that Mordechai Grunwald is the controlling person of American Friends of Yeshiva D’Mir.

(10) We have been informed that Geannine Charriere is the controlling person of B* Capital.

(11) We have been informed that James Melcher is the controlling person of Balestra Capital Partners, L.P.

(12) We have been informed that Remy Chapentier is the controlling person of Concorde Bank Limited.

(13) We have been advised by the selling security holder that its controlling person is Thomas S. Kaplan. Based on Schedule 13G filed with the SEC on February 13, 2006, Thomas S. Kaplan has the sole voting and dispositive power over 3,560,181 shares of our common stock, as follows: 480,811 shares owned by Electrum Resources, LLC; 2,129,370 shares and 800,000 shares issuable upon the exercise of warrants owned by Electrum Capital, LLC, and 150,000 shares owned by LCM Holdings, LLC.

(14) We have been informed that Douglas Newby is the controlling person of Proteus Capital Corp.

(15) We have been informed that Bill Ritger is the controlling person of Seaside Partners, L.P.

(16) We have been informed that Jack Silver is the controlling person of Sherleigh Associates, Inc. PSP.

(17) We have been informed that Marc Belzberg is the controlling person of Winton Capital Holdings Ltd.

(18) We have been informed that James G. Dinan is the controlling person of York Global Value Partners, L.P., York Select, L.P., and York Select Unit Trust.

RELATED PARTY TRANSACTIONS

On January 31, 2005, we entered into a purchase agreement (the “Purchase Agreement”) with 22 accredited investors pursuant to which the investors purchased 7,810,000 shares of common stock and warrants to purchase 14,050,000 shares of common stock at an exercise price of $1.75 per share for aggregate sales proceeds of $9,762,500. The Nathan A. Low Family Trust dated 4/12/96 and Bear Stearns as Custodian for Nathan A. Low Roth IRA, both of which are controlled by Nathan Low, who was at that time a greater than 10% holder of our common stock, invested in us pursuant to the Purchase Agreement. Sunrise Securities Corporation, an affiliate of Nathan Low, received a commission equal to $976,250 and a warrant to purchase 1,821,000 shares of our common stock for services rendered as the placement agent in the transaction.

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On January 31, 2005, we entered into an agreement with the seven accredited investors in our April 2004 private placement pursuant to which we were permitted to repay the $6,000,000 in notes held by such investors without any prepayment penalties in exchange for the exercise price of the warrants to purchase 765,000 shares of common stock issued in the April 2004 private placement being reduced from $4.00 per share to $1.25 per share. $5,000,000 of the notes were repaid in cash and $1,000,000 of the notes were converted into common stock and warrants pursuant to the Purchase Agreement. Nathan Low, who at that time was a greater than 10% holder of Cadence’s common stock, and Lisa Low, Nathan Low’s wife, as Custodian for Gabriel S. Low UNYGMA were two of the eight accredited investors involved in this transaction. In connection with this transaction, the exercise price of the warrants to purchase 76,500 shares of common stock held by Nathan A. Low, who acted as a finder in the April 2004 private placement, was also reduced to $1.25 per share.

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 we moved our corporate offices in early December 2005, we no longer had a need for the space in the South 31, L.L.C. property. We entered into a Settlement Agreement and Mutual Release with South 31, L.L.C. pursuant to which we made a payment to South 31, L.L.C. in the amount of $65,250 on January 27, 2006 and South 31, L.L.C. released us from any further obligation on the lease.

Messrs. Deneau, Tucker and Miller, who are officers and directors of us, 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 we also have an interest, most of which are operated by unrelated third parties, but some of which are operated by us. Existing affiliations involving co-ownership of projects in which our Aurora subsidiary is active, are itemized below.

Messrs. Deneau, Tucker and Miller own equal shares in JetX, LLC, an exploration company that owns a 10% working interest in the Treasure Island project. This project is operated by Samson Resources Corporation.

Mr. Miller has an ownership interest in Miller Resources, Inc., Miller Resources 1994-1, L.L.C., Miller Resources 1994-2, L.L.C., and Miller Resources 1996-1, L.L.C., which own small working interests in the Beyer project, and overriding royalty interests in the Corner #1 project and various Alpena County projects. Mr. Miller also has an ownership interest in Energy Ventures, LLC, which owns a small working interest in the Black Bean project. All of these projects are operated by Samson Resources Corporation.

Messrs. Deneau, Tucker and Miller own Jet Exploration, Inc. which owns a small working interest in the Beregasi well, which is operated by West Bay Exploration.

Messrs. Deneau, Tucker and Miller own a controlling share of Circle D, Ltd. Circle D, Ltd. owns overriding royalty interests in several projects in which we participate, both directly and indirectly, including projects operated by Samson Resources Corporation and the Charlevoix, 1500 Antrim and 2000 Antrim projects, for which we serve as operator. Some of these overriding royalty interests were assigned to Circle D, Ltd. by Aurora, or affiliates of Aurora, within the last two years. Circle D, Ltd. also owns a controlling interest in Northern Gas Fields, LLC, which has entered into various agreements with Aurora granting Aurora options to purchase specified leasehold interests in areas operated by Samson Resources Corporation, none of which involve material exercise prices.

Mr. Miller has an ownership interest in Miller Resources 1996-1, L.L.C., which owns overriding royalty interests in several projects in which we participate, both directly and indirectly, including projects operated by Samson Resources Corporation and the Charlevoix, 1500 Antrim and 2000 Antrim projects, for which we serve as operator. Some of these overriding royalty interests were assigned to Miller Resources 1996-1, L.L.C. by Aurora, or affiliates of Aurora, within the last two years.

Mr. Deneau, directly and indirectly, owns a controlling interest in White Pine R.P., Inc., which owns overriding royalty interests in, the Charlevoix, 1500 Antrim and 2000 Antrim projects, all of which are operated by Aurora.

Mr. Deneau owns White Pine Land Services, Inc., which received an assignment of overriding royalties from Aurora in various Alpena County projects operated by Samson Resources Corporation.

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The Patricia A. Deneau Trust, DTD 10/19/95, which is controlled by William W. Deneau, owns overriding royalty interests in several projects for which Aurora serves as operator, including the Charlevoix, 1500 Antrim and 2000 Antrim projects.

Kevin D. Stulp, one of our directors, owns a 331/3% working interest in 10 wells drilled and operated by TN Oil Company (six of which are dry). We own 650,000 shares of TN Oil Company at a cost of $65,000, which represents approximately a 14% equity interest in TN Oil Company.

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

On September 7, 2004, the Patricia A. Deneau Trust, DTD 10/12/95, borrowed $100,000 from our 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. The shares purchased by the trust were subsequently sold by the trust to Ms. King.

In connection with the December 2005 through February 2006 exercise of certain warrants that had previously been issued by Cadence 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.

We believe that all of these related party transactions were either on terms at least as favorable to us as could have been obtained through arm’s-length negotiations with unaffiliated third parties or were negotiated in connection with acquisitions, the overall terms of which were as favorable to us as could have been obtained through arm’s-length negotiations with unaffiliated third parties. We intend to address future material transactions with our affiliates by having the transactions submitted for approval to a committee of disinterested directors.

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.

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;

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•  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.

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 pledgees 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 pledgee, 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, pledgees 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 amending the list of selling security holders to include the pledgee, 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 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 November 13, 2006, we had 103,062,966 shares of common stock issued and outstanding and no shares of preferred 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, 2006, there were 591 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 previously authorized the issuance of 2,500,000 shares of Class A Preferred Shares. As of the date of this prospectus, all previously issued shares of Class A Preferred stock have been converted to common stock.

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 on behalf of Moshe Azouley, Lisa Low as Custodian For Gabriel S. Low UNYGMA, Nathan A Low, Bear Stearns as Custodian For Nathan A. Low Roth IRA, Ruth Low, Omicron Capital, Portside Growth and Opportunity Fund and Smithfield Fiduciary LLC are exercisable at $1.25 per share and expire on April 2, 2007. 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

64

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 purchase such number of securities as if the warrant holder were a holder of common stock.

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

Options

The options being registered on behalf of American Friends of Ohr Somayach, American Friends of Yeshiva D’Mir, American Friends of Shalva, American Friends of Yad Ezra, Marcia Kucher, Lisa Low as custodian for Daniel Low, Michael Low, Gabriel Low and Chantal Low and Jason Lyons are exercisable at a price of $2.50 per share and expire in September 2008. These options may be exercised on a cashless basis at any time. The options being registered on behalf of Proteus Capital Corp. are exercisable at a price of $1.75 per share and expire on June 18, 2007.

The options may be exercised in whole or in part, subject to the limitations provided in the options. Any option holders who do not exercise their options prior to the conclusion of the exercise period will forfeit the right to purchase the shares of common stock underlying the options and any outstanding options will become void and be of no further force or effect. Holders of the options have no voting, preemptive, liquidation or other rights of a shareholder, and no dividends will be declared on the options.

Transfer Agent And Registrar

Our transfer agent and registrar is Mellon Investor Services LLC.

Securities Authorized For Issuance Under Equity Compensation Plans

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 814,706. Although we do not intend to make any further awards under this plan, this plan currently continues to exist.

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 480,000 shares of Aurora’s common stock under this plan, which upon closing the merger, converted into the right to acquire up to 960,000 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 299,997 shares of Aurora common stock under this plan, which upon closing the merger converted to the right to acquire 599,994 shares of our common stock. Because of the merger, no further awards can be made under this plan.

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 August 25, 2006, we had awarded restricted stock and options to purchase restricted stock in a total amount of 2,464,500 shares, leaving 5,535,500 shares available for future awards.

65

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.

The following chart sets forth certain information as of December 31, 2005 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.

						No. of Securities Remaining
	No. of Securities to be			Weighted Average		Available for Future Issuance
	Issued Upon Exercise of			Exercise Price of		Under Equity Compensation
	Outstanding Options,			Outstanding Options,		Plans (Excluding Securities in
Plan Category	Warrants and Rights			Warrants and Rights		the First Column of this Table)
Equity compensation plans approved by security holders		1,784,994		$	0.83		185,294	(a)
Equity compensation plans and awards not approved by security holders		5,355,140	(b)		1.04		—
Total/combined		7,140,134		$	0.99		185,294	(a)

(a)	Although technically still available for issuance, we do not presently intend to issue these shares or options to issue these shares. Instead, in March 2006, we adopted an entirely new plan that includes 8,000,000 available shares.
(b)	These options and warrants to purchase shares were issued as follows:
	Warrants and options to purchase 3,255,140 shares (1,204,000 are Aurora conversion shares originally issued to purchase 602,000 shares of Aurora common stock) were issued to Nathan A. Low and his designees in compensation for investment banking services rendered.
	Options to purchase 2,100,000 shares (which includes 1,800,000 Aurora conversion shares initially issued to purchase 900,000 shares of Aurora common stock) were issued in five separate individualized compensation arrangements with executive officersand/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 November 13, 2006, we had 103,062,966 shares of common stock outstanding. Of this amount, 11,702,580 shares (approximately 14% of our outstanding shares prior to the close of this offering) are subject tolock-up and may not be sold through October 31, 2008.

We have two other shelf registration statements that are currently effective, which together with this registration statement have registered almost 40 million shares of common stock for resale. This includes approximately 2 million 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 a 2004 financing and in the financings received by us and Aurora on January 31, 2005.

On November 13, 2006, we had options and warrants to purchase 6,882,276 shares of common stock outstanding, and we had still available 5,535,500 shares for issuance as options or restricted stock under our 2006 Stock Incentive Plan.

We have just completed a public offering in which we sold 19,600,000 shares. All of the shares sold in the public offering are 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,

66

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 is approximately 1,030,629 shares; 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.

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 has been passed upon for us by Fraser Trebilcock Davis & Dunlap, P.C., Lansing, Michigan.

EXPERTS

Our consolidated financial statements for the years ended December 31, 2005 and December 31, 2004, have been audited by Rachlin Cohen & Holtz LLP, an independent registered public accounting firm, as indicated in their accompanying report. Our condensed consolidated financial statements for the six months ended June 30, 2006 and June 30, 2005 have been reviewed by Rachlin Cohen & Holtz LLP, as indicated in their accompanying report. Both of these financial statements and accompanying reports 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, 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.

67

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement onForm 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 at1-800-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 iswww.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 onForm 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.

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FINANCIAL STATEMENTS

INDEX TO FINANCIAL STATEMENTS

	Page
Cadence Resources Corporation (now known as Aurora Oil & Gas Corporation) Financial Statements for the years ended December 31, 2005 and 2004
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Financial Statements
Balance Sheets		F-3
Statements of Operations		F-4
Statements of Shareholders’ Equity		F-5
Statements of Cash Flows		F-6
Notes to Financial Statements		F-7 — F-33
Supplemental Oil and Gas Information (unaudited)		F-34 — F-37
Aurora Oil & Gas Corporation Condensed Consolidated Financial Statements for the Six Months Ended June 30, 2006 and 2005
Report of Independent Registered Public Accounting Firm		F-38
Consolidated Financial Statements
Balance Sheet		F-39
Statements of Operations		F-40
Statement of Shareholders’ Equity		F-41
Statements of Cash Flows		F-42
Notes to Financial Statements		F-43 — F-53

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Shareholders and Board of Directors

Cadence Resources Corporation and Subsidiaries

Traverse City, Michigan

We have audited the accompanying consolidated balance sheets of Cadence Resources Corporation and Subsidiaries as of December 31, 2005 and 2004 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 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 Cadence Resources Corporation and Subsidiaries as of December 31, 2005 and 2004 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 of America.

RACHLIN COHEN & HOLTZ LLP

Miami, Florida

February 24, 2006

F-2

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2005			2004
ASSETS
Current assets:
Cash and cash equivalents	$	11,980,638		$	5,179,582
Accounts receivable:
Oil and gas sales		2,409,675			1,893,051
Joint interest owners		4,380,606			376,856
Related parties		—			129,960
Notes receivable:
Related parties		15,000			135,096
Other		229,346			101,151
Prepaid expenses and other current assets		240,242			—
Total current assets		19,255,507			7,815,696
Oil and gas properties, using full cost accounting:
Proved properties		39,643,003			7,585,807
Unproved properties		37,279,889			7,981,727
Total oil and gas properties		76,922,892			15,567,534
Less accumulated depletion and amortization		7,962,138			600,077
Oil and gas properties, net		68,960,754			14,967,457
Other assets:
Deposit on purchase of oil and gas properties		3,206,102			—
Property and equipment, net		3,610,138			115,283
Goodwill		15,973,346			—
Intangibles, net		3,197,917			—
Other investments		1,855,977			230,396
Other assets		762,404			316,997
Total assets		28,605,884			662,676
	$	116,822,145		$	23,445,829
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	7,053,288		$	3,221,533
Accrued expenses		417,291			200,800
Drilling advances		—			387,175
Short-term bank borrowings		6,210,000			350,000
Current portion of obligations under capital leases		8,823			8,823
Current portion of note payable — related party		69,833			1,940,825
Current portion of mortgage payable		72,877			—
Total current liabilities		13,832,112			6,109,156
Deposit on sale of oil and gas properties		3,509,319			—
Long-term debt:
Obligations under capital leases, net of current portion		2,262			12,663
Notes payable — related parties		—			1,077,706
Mortgage payable		2,792,600			—
Mezzanine financing		40,000,000			10,000,000
Total long-term debt		42,794,862			11,090,369
Total liabilities		60,136,293			17,199,525
Redeemable convertible preferred stock		59,925			—
Commitments, contingencies and subsequent events		—			—
Shareholders’ equity:
Preferred stock, $1.50 par value; authorized 500,000 shares; issued and outstanding none in 2005 and 99,350 shares in 2004		—			149,025
Common stock, $.01 par value; authorized 100,000,000 shares; issued and outstanding 61,536,261 shares in 2005 and 13,775,933 shares in 2004		615,363			13,776
Additional paid-in capital		58,670,698			8,183,025
Accumulated deficit		(2,660,134	)		(2,099,522	)
Total shareholders’ equity		56,625,927			6,246,304
Total liabilities and shareholders’ equity	$	116,822,145		$	23,445,829

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

F-3

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended
	December 31,
	2005			2004
Revenues:
Oil and gas sales	$	6,743,444		$	960,011
Interest income		243,013			47,678
Equity in loss of unconsolidated subsidiaries		(75,596	)		—
Other income		452,621			1,192,835
Total revenues		7,363,482			2,200,524
Costs and expenses:
General and administrative		3,435,507			2,057,333
Production and lease operating		2,047,028			614,338
Depletion, depreciation and amortization		1,155,254			203,249
Interest		1,228,274			392,402
Taxes		29,651			75,000
Total costs and expenses		7,895,714			3,342,322
Loss before minority interest		(532,232	)		(1,141,798	)
Minority interest in loss of subsidiaries		15,960			38,087
Net loss		(516,272	)		(1,103,711	)
Less dividends on preferred stock		—			(30,268	)
Loss attributable to common shareholders	$	(516,272	)	$	(1,133,979	)
Net loss per common share — basic and diluted	$	(0.01	)	$	(0.05	)
Weighted average common shares outstanding — basic and diluted		40,622,000			23,636,000

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

F-4

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

											Additional						Total
	Preferred Stock						Common Stock				Paid-In			Accumulated			Shareholders’
	Shares			Amount			Shares		Amount		Capital			Deficit			Equity
Balances at January 1, 2004		410,461		$	615,692			11,432,824	$	11,433	$	4,745,222		$	(868,699	)	$	4,503,648
Issuance of common stock for consulting services		—			—			54,776		55		53,424			—			53,479
Sale of common stock:
Issued in private placement		—			—			600,000		600		1,499,400			—			1,500,000
Issued to Cadence Resource Corporation		—			—			300,000		300		749,700			—			750,000
Issued to others		—			—			145,000		145		362,355			—			362,500
Exercise of common stock options		—			—			310,000		310		307,190			—			307,500
Conversion of preferred stock to common stock		(311,111	)		(466,667	)		933,333		933		465,734			—			—
Dividends paid on preferred stock		—			—			—		—		—			(127,112	)		(127,112	)
Net loss		—			—			—		—		—			(1,103,711	)		(1,103,711	)
Balances at December 31, 2004		99,350			149,025			13,775,933		13,776		8,183,025			(2,099,522	)		6,246,304
Conversion of preferred stock to common stock		(99,350	)		(149,025	)		298,050		298		148,727			—			—
Dividends paid on preferred stock		—			—			—		—		—			(44,340	)		(44,340	)
Sale of common stock, net of commissions and fees		—			—			4,972,200		4,972		11,020,028			—			11,025,000
Exercise of options prior to merger		—			—			10,000		10		7,490			—			7,500
Merger between Cadence and Aurora		—			—			39,592,510		567,431		35,706,179			—			36,273,610
Cashless exercise of options and warrants		—			—			245,068		2,451		(2,451	)		—			—
Exercise of common stock options and warrants		—			—			2,642,500		26,425		3,607,700			—			3,634,125
Net loss		—			—			—		—		—			(516,272	)		(516,272	)
Balances at December 31, 2005		—		$	—			61,536,261	$	615,363	$	58,670,698		$	(2,660,134	)	$	56,625,927

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

F-5

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended
	December 31,
	2005			2004
Cash flows from operating activities:
Net loss	$	(516,272	)	$	(1,103,711	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization		1,155,254			203,249
Equity in loss of non-consolidated investees		75,596			—
Unrealized loss on investments		31,237			—
Loss on disposal of property and equipment		25,499			—
Services received in settlement of note receivable		—			39,754
Common stock issued for services		—			53,479
Minority interest in loss of subsidiaries		(15,960	)		(38,087	)
Changes in operating assets and liabilities, net of effect of merger:
Accounts receivable		(3,957,497	)		(1,365,271	)
Accounts receivable — related parties		129,960			7,854
Prepaid expenses		41,634			76,110
Accounts payable		2,790,037			1,939,965
Drilling advances		(387,175	)		352,320
Accrued expenses		216,491			52,779
Net cash (used in) provided by operating activities		(411,196	)		218,441
Cash flows from investing activities:
Proceeds from sale of oil and gas properties		7,995,109			1,902,537
Proceeds from sale of property and equipment		23,693			—
Capital expenditures for oil and gas development		(46,145,082	)		(10,159,663	)
Capital expenditures for property and equipment		(3,594,750	)		(74,166	)
Advances of notes receivable		(107,475	)		(155,096	)
Payments on notes receivable, related parties		120,096			—
Deposits made for the purchase of oil and gas properties		(3,206,102	)		—
Deposits received for the sale of oil and gas properties		3,509,319			—
Investment in Hudson Pipeline		(928,956	)		(230,396	)
Investment in GeoPetra		(485,741	)		—
Net cash acquired in merger		957,020			—
Net cash used in investing activities		(41,862,869	)		(8,716,784	)
Cash flows from financing activities:
Net short-term bank borrowings		5,860,000			350,000
Advances from mezzanine financing, net of financing costs of approximately $500,000 in 2005		29,491,458			10,179,694
Mortgage financing advances		2,865,477			—
Payments on capital lease obligations		(10,401	)		(128,278	)
Distributions to minority interest members		(805,000	)		(41,347	)
Net proceeds from sales of common stock		14,666,625			2,920,000
Dividends paid		(44,340	)		—
Net proceeds from subsidiary disposition		—			10,467
Repayment of debt to related parties		(2,948,698	)		(504,546	)
Payments on notes payable — other		—			(307,935	)
Advances from related parties		—			154,118
Net cash provided by financing activities		49,075,121			12,632,173
Net increase in cash and cash equivalents		6,801,056			4,133,830
Cash and cash equivalents, beginning of year		5,179,582			1,045,752
Cash and cash equivalents, end of year	$	11,980,638		$	5,179,582

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

F-6

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2005 and 2004

NOTE 1.   BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Cadence Resources Corporation is an independent oil and gas exploration company engaged in the exploration, acquisition, development, production and sale of natural gas. We generate most of our revenues from the production and sale of natural gas. While we do have some non-operated interest in oil wells, nearly 100% of our proved reserves consist of natural gas from our position in the Antrim Shale in Michigan. Additionally, we have a substantial leasehold position in the New Albany Shale in Indiana.

Our current operations consist primarily of the drilling for and production of natural gas. The results of operations are determined by the difference between the natural gas price received for the gas produced, less the cost to drill, develop and produce the gas. Natural gas prices are subject to fluctuations in response to many factors such as quantities in gas storage, level of consumer demand and the worldwide political climate as well as the impact of certain weather related disasters.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts ofCadence Resources Corporationand the entities identified below under the heading Organization and Nature of Operations, hereinafter referred to as “the Company” or “Cadence”.

All significant intercompany accounts and transactions have been eliminated in consolidation.

As further described in Note 2, on October 31, 2005, 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.

While Cadence was the legal acquirer, the merger was accounted for as a reverse acquisition, whereby Aurora was deemed to have acquired Cadence for financial reporting purposes. This determination was based on factors including relative stock ownership and voting rights, board control, and senior management composition. Consistent with the reverse acquisition accounting treatment, 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 and related notes have been retroactively adjusted to give effect to the reverse acquisition on October 31, 2005 for all periods presented.

Organization and Nature of Operations

The nature and composition of the Company’s operations are as follows:

Cadence Resources Corporation (formerly Royal Silver Mines, Inc.) hereinafter (“Cadence” or “the Company”) was incorporated in April 1969 under the laws of the State of Utah primarily for the purpose of acquiring and developing mineral properties. The Company changed its name from Royal Silver Mines, Inc. to Cadence Resources Corporation on May 2, 2001.

Previously, the Company had presented its financial statements on a September 30 fiscal year-end. Subsequent to the closing of the merger with Aurora, the Company changed its fiscal year-end to December 31, in order to conform with the fiscal year-end of Aurora.

F-7

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cadence Resource Corporation’s subsidiaries operations as a result of its merger with Aurora are as follows:

Aurora Energy, Ltd. (“Aurora”) is a Nevada corporation, engaged primarily in the acquisition, development, production, exploration and sale of oil, gas and natural gas liquids. Aurora sells its oil and gas products primarily to domestic pipelines and refineries.

Aurora Operating, LLC (“Operating”) is a limited liability company, engaged primarily in oil and gas operations and development. Operating was formed on January 1, 2000 and its term of existence extends through January 1, 2020. Operating holds certain oil and gas properties in the New Albany Shale Project. Aurora owned a 71% member interest in this entity. In December 2003, Aurora entered into an agreement to sell 20% of its member interest in Operating to an unrelated third party. This sale changed Aurora’s ownership in Operating from 71% to 51%.

Restrictions related to this sale specify that the purchaser is not entitled to receive any cash distributions nor are they required to make any capital contributions within two years from the closing date (December 9, 2003). The agreement also includes put and call options at the same price that the 20% was initially sold for. The call option allows Aurora to purchase this interest back between December 10, 2005 and December 9, 2008. The put option allows the purchaser to sell their interest back to Aurora during the same time frame. The Company has subsequently purchased this interest back on January 31, 2006. See Subsequent Events, Note 26.

Aurora Antrim North, LLC (“North”) is a limited liability company engaged primarily in any activity with the purpose for which the LLC may be formed. North was formed on January 18, 2001 and its term of existence extends through January 18, 2021. Aurora holds a 100% interest in North. In 2003, certain oil and gas properties were conveyed from Aurora to North in connection with mezzanine financing with Wells Fargo. This financing facility was paid in full and terminated during 2004, and Aurora entered into a new mezzanine financing arrangement, which is more fully described in Note 12.

Aurora Holdings, LLC (“Holdings”) is a limited liability company engaged primarily in any activity with the purpose for which the LLC may be formed. Holdings was formed on January  10, 2001 and its term of existence extends through January 10, 2021. Aurora holds a 100% interest in Holdings. Operations for Holdings for the period from inception to December 31, 2005 were insignificant.

Indiana Royalty Trustory, LLC (“IRT”) is a limited liability company engaged primarily in investments in royalties and other financial instruments. IRT was formed on January 1, 2001 and its term of existence extends through January 1, 2021. The Company holds a 51% interest in IRT. Operations for IRT during 2005 and 2004 were insignificant.

Aurora Investments, LLC (“AIL”) is a limited liability company formed in October 2001 to raise funds specifically earmarked for drilling of certain defined oil and gas prospects. Under the terms outlined in the private placement memorandum dated October 1, 2001, third party investors contributed 95% of the funds needed to drill a specific project and Aurora contributed 5% in the form of oil and gas properties. As manager of AIL, Aurora made key decisions relating to AIL’s operations and was conveyed an additional 12.5% interest in AIL for a total membership interest of 17.5%. Once all third party investor members received 100% of their initial investment back, Aurora is to receive an additional 12.5% interest for a total member interest of 30%. AIL was consolidated into Aurora due to the control that Aurora exercised over the operations of AIL. During 2004, Aurora exchanged its 17.5% membership interests in AIL in exchange for certain working interests, which resulted in the removal of AIL from the consolidated financial statements as of December 31, 2004. While the agreement covering a potential 12.5% additional interest is still in effect, management believes the likelihood of receiving this additional interest is remote.

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CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Beyer Antrim Company, LLC (“BAC”) is a limited liability company formed in May 2002 to raise funds specifically earmarked for drilling of certain defined oil and gas prospects. Under the terms outlined in the private placement memorandum dated April 20, 2002, third party investors contributed 95% of the funds needed to drill a specific project and Aurora contributed 5% in the form of oil and gas properties.

As manager of BAC, Aurora makes key decisions relating to BAC’s operations and was conveyed an additional 12.5% interest in BAC for a total membership interest of 17.5%. Once all third party investor members received 100% of their initial investment back, Aurora is to receive an additional 12.5% interest for a total member interest of 30%. BAC was consolidated into Aurora due to the control that Aurora exercised over the operations of BAC. During 2004, Aurora exchanged its 17.5% membership interests in BAC in exchange for certain working interests, which resulted in the removal of BAC from the consolidated financial statements as of December 31, 2004. While the agreement covering a potential 12.5% additional interest is still in effect, management believes the likelihood of receiving this additional interest is remote.

Aurora Natural Gas Production, LLC (“ANG”) is a limited liability company formed in June 2002 to raise funds specifically earmarked for drilling of certain defined oil and gas prospects. Under the terms outlined in the private placement memorandum dated May 15, 2002, third party investors contributed 95% of the funds needed to drill a specific project and Aurora contributed 5% in the form of oil and gas properties. As manager of ANG, Aurora made key decisions relating to ANG’s operations and was conveyed an additional 12.5% interest in ANG for a total membership interest of 17.5%. Once all third party investor members received 100% of their initial investment back, Aurora is to receive an additional 12.5% interest for a total member interest of 30%. ANG was consolidated into Aurora due to the control that Aurora exercised over the operations of ANG. During 2004, Aurora exchanged its 17.5% membership interests in ANG in exchange for certain working interests, which resulted in the removal of ANG from the consolidated financial statements as of December 31, 2004. While the agreement covering a potential 12.5% additional interest is still in effect, management believes the likelihood of receiving this additional interest is remote.

BFG Holdings, LLC (“BFG”) is a limited liability company engaged primarily in any activity with the purpose for which the LLC may be formed. BFG was formed on September 18, 2002 and Aurora holds a 100% interest in BFG. In 2003, certain oil and gas properties were conveyed from Aurora to BFG in connection with the reserve base financing with Texas Capital Bank, N.A. This financing vehicle has been paid in full and terminated during 2004. These properties were transferred to BFG at their net book value on the date of transfer. During 2004, BFG was closed and transferred all oil and gas properties to North at their net book value. All operations of BFG have ceased as of December 31, 2004.

Consolidated Exploration, LLC (“Conexco”) is a limited liability company engaged primarily in the acquisition, development and sale of oil and gas leasehold interests. Conexco owns certain leasehold interests in Indiana’s New Albany Shale area, including an overriding royalty in the producing Corydon fields.

Conexco was formed on April 4, 1994 and its term of existence extends through April 4, 2014. On January 1, 1999, Aurora purchased a 100% interest in Conexco and this entity became a wholly-owned subsidiary.

Indigas Energy, LLC (“Indigas”) is a limited liability company engaged primarily in the acquisition, development, production and sale of oil and gas leasehold interests. Indigas owns certain leasehold interests in Indiana and Kentucky’s New Albany Shale area. Indigas was formed on January 1, 1996 and its term of existence extends through January 1, 2016. On January 1, 1999, Aurora purchased a 100% interest in Indigas and this entity became a wholly-owned subsidiary.

F-9

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Both Conexco and Indigas received certain proceeds from the signing of an option agreement (the “Option”) related to their leasehold interests. These proceeds were used to return to investors their original investment plus the agreed-upon return percentage. With all of the lease investors monies returned, operations of both entities ceased as of December 31, 2003. These entities continue to hold certain overriding royalty interests in the undeveloped leases sold under the agreement described above. Any future revenues that may result from drilling on these leases from these overriding royalty interests will be assigned directly to Aurora Energy, Ltd.

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. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates underlying these financial statements include:

•  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,

•  accruals related to oil and gas revenues and lease operating expenses, and

•  estimates used in computation of our federal and state income tax liabilities.

While we are not aware of any material revision to any of our estimates, there will likely be future revisions to our estimates as a result of changes in our joint venture agreements, working interest ownership, payouts, and reallocations by purchasers. These types of adjustments are not currently predictable and will be recorded in the period they occur.

Oil and Gas Properties

Aurora uses the full cost method of accounting for oil and gas properties. Prior to the merger, Cadence used the successful efforts method of accounting; however, in connection with the merger, Cadence adopted the full cost method in order to conform with Aurora’s accounting principles. The adoption of the full cost method by Cadence resulted in a net increase to oil and gas properties of $774,912.

Under the full cost method, all costs associated with acquisition, exploration and development of oil and gas reserves, including directly related overhead costs, are capitalized. Costs associated with production and general corporate activities are expensed in the period incurred.

All capitalized costs of oil and gas properties, including the estimated future costs to develop proven reserves, are amortized on theunit-of-production method using estimates of proven reserves. Investments in unproven properties and major development projects are not amortized until proven reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Capitalized costs of oil and gas properties, net of accumulated amortization, are limited to the aggregate of estimated future net revenues from proven reserves, discounted at ten percent, based on current economic and operating conditions, plus the lower of cost or fair value of unproven properties. Sales of proven and unproven properties are applied to reduce the capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proven reserves of oil and gas, in which case the gain or loss is recognized in income. Abandonment of properties is accounted for as adjustments of capitalized costs with no loss recognized.

F-10

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Full Cost Ceiling Test

At the end of each reporting period, the unamortized cost of oil and gas properties is limited to the sum of the estimated future net revenues from proved properties (including future development and abandonment costs of wells to be drilled, using period-end prices, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”).

The calculation of the Ceiling Test and provision for depreciation and amortization is based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered. Our reserves estimates are prepared in accordance with Securities and Exchange Commission guidelines and, are reviewed on an annual basis at year-end by a firm of independent petroleum engineers in accordance with standards approved by the Board of Directors of the Society of Petroleum Engineers.

Given the volatility of oil and gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline from our period-end prices used in the Ceiling Test, even if only for a short period, it is possible that non-cash write-downs of oil and gas properties could occur in the future.

Capitalized Interest

The Company capitalizes interest on debt related to expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Interest capitalized amounted to $1,146,084 and $329,028 during 2005 and 2004, respectively.

Other Mineral Properties

Costs of acquiring, exploring and developing mineral properties are capitalized by project area. Costs to maintain the mineral rights and leases are expensed as incurred. When a property reaches the production stage, the related capitalized costs will be amortized, using the units of production method on the basis of periodic estimates of ore reserves. The cost of the Company’s mineral properties are included in other investments in the accompanying financial statements, as the Company has changed its focus from minerals exploration to oil and gas exploration.

Derivative Instruments

The Financial Accounting Standards Board issued Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities — Deferral of the Effective Date of FASB No. 133”, and SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” and SFAS No. 149, “Amendment of Statement No. 133 on Derivative Instruments and Hedging Activities.” These standards establish accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. They require that an entity recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as a hedge, the objective of which is to match the timing of gain or loss recognition on the hedging derivative with the recognition of (i) the changes in the fair value of the hedged asset or liability that are attributable to the hedged risk or (ii) the earnings effect of the hedged forecasted transaction.

F-11

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For a derivative not designated as a hedging instrument, the gain or loss is recognized in income in the period of change.

Historically, the Company has not entered into derivatives contracts to hedge existing risks or for speculative purposes.

At December 31, 2005 and for the periods covered in the accompanying financial statements, the Company has not engaged in any transactions that would be considered derivative instruments or hedging activities.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an initial maturity of three months or less to be cash equivalents.

Deferred Loan Origination Costs

Loan origination costs related to mezzanine financing obtained in late 2004 and also in 2005, as more fully described in Note 12, are deferred and are included in other assets. These costs are being amortized using the interest method over the term of the related loan. Annual amortization expense during 2006 to 2009 will be approximately $160,000.

Environmental Remediation and Compliance

Expenditures for ongoing compliance with environmental regulations that relate to current operations are expensed or capitalized as appropriate. Expenditures resulting from the remediation of existing conditions caused by past operations that do not contribute to future revenue generations are expensed. Liabilities are recognized when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated.

Estimates of such liabilities are based upon currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other societal and economic factors, and include estimates of associated legal costs. These amounts also reflect prior experience in remediating contaminated sites, other companies’clean-up experience and data released by The Environmental Protection Agency or other organizations. Such estimates are by their nature imprecise and can be expected to be revised over time because of changes in government regulations, operations, technology and inflation. Recoveries are evaluated separately from the liability and, when recovery is assured the Company records and reports an asset separately from the associated liability. At December 31, 2005 and 2004, the Company had no accrued liabilities for compliance with environmental regulations.

Investments in Unconsolidated 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. 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 equity in income or loss of unconsolidated subsidiaries.

Revenue Recognition

Oil and gas sales are generally recognized at the time of extraction of product or performance of services. Revenues from service contracts are recognized ratably over the term of the contract.

Accounts Receivable

Accounts receivable generally consist of amounts due from the sale of oil and gas products and from working interest partners for their proportionate share of expenses related to certain oil and gas projects. Accounts receivable

F-12

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

may also include certain costs that are incurred on behalf of joint partners which are billed subsequent to the end of the reporting period.

The Company assesses the collectibility of accounts receivable and, based on management’s assessment of the current status of individual accounts, the Company accrues a reserve when it is believed that a receivable may not be collected. Losses on collection of accounts receivable have not been material and, accordingly, no allowance for doubtful accounts was considered necessary in the accompanying financial statements.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash, accounts receivable, loans receivable, accounts payable and 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. The estimated fair value is not necessarily indicative of the amounts the Company would realize in a current market exchange or from future earnings or cash flows.

Property and Equipment

Property and equipment are stated at cost. Major improvements and renewals are capitalized while ordinary maintenance and repairs are expensed. Management annually reviews these assets to determine whether carrying values have been impaired.

Depreciation, which includes amortization of assets recorded as capital leases, is computed using the straight-line method over the estimated useful lives of the related assets, which range from 5 to 20 years or lease term, if shorter.

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 discount rate reflecting the Company’s average cost of funds. Future impairment of goodwill could result if the Company’s estimated future operating cash flows are not achieved. The carrying value of goodwill at December 31, 2005 was approximately $15,973,000. No impairment loss was recorded for the year ended December 31, 2005.

Intangible Assets

Acquired intangible assets, which consist of non-compete agreements and proprietary business relationships, are recorded at fair value. These intangible assets are amortized on a straight-line basis over a three year period. Amortization expense is estimated to be approximately $1,535,000 per year through 2007.

Income Taxes

Income taxes are provided based upon the liability method of accounting pursuant to Statement of Financial Accounting Standards No. 109,“Accounting for Income Taxes” (“SFAS No. 109”). Under this approach, deferred income taxes are recorded to reflect the tax consequences in future years of differences between the tax basis of assets and liabilities and their financial reporting amounts at each year-end.

Deferred income tax assets and liabilities are computed annually for differences between the consolidated financial statements and federal income tax bases of assets and liabilities that will result in taxable or deductible

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CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

amounts in the future, based on enacted tax laws and rates applicable to the periods in which the differences are expected to affect taxable income. Deferred income taxes arise from temporary basis differences principally related to intangible drilling costs incurred in connection with the development of oil and gas properties, depreciation and net operating losses.

Valuation allowances are established when necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable or refundable for the year plus or minus the change during the year in deferred tax assets and liabilities.

Concentrations of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk are cash and cash equivalents and accounts receivable.

Cash and Cash Equivalents

The Company’s bank accounts periodically exceed federally insured limits. As of December 31, 2005 and 2004, cash in excess of FDIC limits amounted to approximately $12,310,000 and $1,055,000 respectively. The Company maintains its deposits with high quality financial institutions and, accordingly, believes that the Company is not exposed to any significant credit risk on its cash deposits.

Accounts Receivable

We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owner’s receivables, to various companies in the oil and 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 our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. During 2005, oil and gas sales to one customer, CIMA Energy, Ltd., were approximately 63% of total oil and gas sales.

Minority Interest

The minority interest at December 31, 2005 and 2004 is insignificant and is included in other asset in the accompanying consolidated balance sheets. The balance represents the minority members’ share of contributed capital, income or loss and distributions.

Reclassifications

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

Recent Accounting Pronouncements

In November 2005, the FASB issued Staff PositionNo. FAS 115-1,The Meaning ofOther-Than-Temporary Impairment and its Application to Certain Investments (“FSP 115-1”). FSP 115-1 provides accounting guidance for determining and measuringother-than-temporary impairments of debt and equity securities, and confirms the disclosure requirements for investments in unrealized loss positions as outlined in EITFissue 03-01,The Meaning ofOther-Than-Temporary Impairments and its Application to Certain Investments.The accounting requirements of FSP 115-1 are effective for us on January  1, 2006 and will not have a material impact on our consolidated financial position, results of operations or cash flows.

In May 2005, the FASB issued SFAS No. 154,“Accounting for Changes and Error Corrections, a Replacement of APB Opinion No. 20 and FASB Statement No. 3” SFAS 154 applies to all voluntary changes

F-14

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

in accounting principle and requires retrospective application to prior periods’ financial statements of changes in accounting principle. This statement also requires that a change in depreciation, amortization, or depletion method for long-lived, non-financial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. SFAS 154 carries forward without change the guidance contained in Opinion No. 20 for reporting the correction of an error in previously issued financial statements and a change in accounting estimate. This statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company does not expect the adoption of this standard to have a material impact on its financial condition, results of operations, or liquidity.

In March 2005, the Financial Accounting Standards Board issued FASB Interpretation No. 47,“Accounting for Conditional Asset Retirement Obligations, an Interpretation of FASB Statement No. 143.” This Interpretation clarifies that the term conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value can be reasonably estimated. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. The Company does not expect the adoption of this standard to have a material impact on its financial condition, results of operations, or liquidity.

In December 2004, the FASB issued SFAS No. 153,“Exchanges of Non-monetary Assets, an Amendment of APB Opinion No. 29.” SFAS No. 153 requires exchanges of productive assets to be accounted for at fair value, rather than at carryover basis, unless (1) neither the asset received nor the asset surrendered has a fair value that is determinable within reasonable limits or (2) the transactions lack commercial substance. This Statement is effective for non-monetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Company does not expect the adoption of this standard to have a material impact on its financial condition, results of operations, or liquidity.

In December 2004, the FASB issued SFAS No. 123 (revised 2004),“Share-Based Payment.” SFAS No. 123(R) is a revision of SFAS No. 123,“Accounting for Stock-Based Compensation,” and supersedes APB Opinion No. 25,“Accounting for Stock Issued to Employees.” Statement No. 123(R) will require the fair value of all stock based awards issued to employees to be recorded as an expense over the related vesting period. The statement also requires the recognition of compensation expense for the fair value of any unvested stock based awards outstanding at the date of adoption. This statement becomes effective the beginning of the first interim or annual reporting period that begins after December 15, 2005. The Company is currently evaluating the impact on its results from adopting SFAS No. 123(R).

NOTE 2.   MERGER WITH AURORA ENERGY, LTD.

On October 31, 2005, Cadence Resources Corporation (“Cadence”) acquired Aurora Energy, Ltd. (“Aurora”) through the merger of a wholly-owned subsidiary with and into Aurora. As a result of the merger, Aurora became a wholly-owned subsidiary.

The merger has been accounted for as a reverse acquisition using the purchase method of accounting. Although the merger was structured such that Aurora became a wholly-owned subsidiary of Cadence, Aurora has been treated as the acquiring company for accounting purposes under Statement of Financial Accounting Standards (“SFAS”) No. 141, “Business Combinations”, due to the following factors: (1) Aurora’s stockholders received the larger share of the voting rights in the merger; (2) Aurora received the majority of the members of the board of directors; and (3) Aurora’s senior management prior to the merger dominated the senior management of the combined company. As a result of the reverse acquisition, the statements of operations presented herein include the results of Aurora for the year ended December 31, 2005 and include the results of Cadence for the period from date of acquisition (November 1, 2005 through December 31, 2005). The financial information reflected in the financial statements for 2004 are comprised of the accounts and activities of Aurora.

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CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 assigned to this transaction is equal to $41,546,351 determined as follows:

Fair value of Cadence’s common stock outstanding at January 31, 2005	$	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

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 historical balance sheet of Cadence was adjusted to the purchase price of $41,546,351 with amounts in excess of historical book value allocated among the following categories: (1) unproved oil and gas properties and property and equipment, (2) other investments, (3) intangible assets and (4) goodwill.

The following table summarizes the estimated fair value of the assets acquired and the liabilities assumed at the date of acquisition. The Company has 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 gas properties and property and equipment		14,647,614
Investments		1,503,832
Other Mineral properties		197,406
Non-compete agreements		3,265,000
Proprietary business relationships		1,340,000
Goodwill		15,973,346
Redeemable convertible preferred stock		(59,925	)
	$	41,546,351

The Company has followed the guidance of SFAS No. 141 to record this purchase. SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 1, 2001 and that goodwill, as well as any intangible assets believed to have an indefinite life, shall not be amortized for financial accounting purposes. The Company has recognized goodwill in the amount of $15,973,346 in connection with this acquisition. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets”, the goodwill will be reviewed periodically to determine if there has been any impairment to its value. The Company will perform an impairment test as of December 31, 2006, unless circumstances or events indicate that an impairment test should be performed sooner.

F-16

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 the periods presented, compared with the historical results of operations of Aurora for the same periods.

	2005						2004
	Historical			Pro Forma			Historical			Pro Forma*
Oil and gas revenues	$	6,743,444		$	8,821,869		$	960,011		$	3,501,458
Production expenses		(2,047,028	)		(2,799,504	)		(614,338	)		(789,174	)
Net operating revenues		4,696,416			6,022,365			345,673			2,712,284
Net loss		(516,272	)		(4,293,053	)		(1,103,711	)		(7,989,175	)
Net loss per common share — basic and diluted		(0.01	)		(0.07	)		(0.05	)		(0.22	)
Weighted average number of common shares outstanding — basic and diluted		40,622,000			58,108,000			23,636,000			36,351,000

*  Includes operations of Cadence for the year ended September 30, 2004

NOTE 3.   ACCOUNTS RECEIVABLE (INCLUDING RELATED PARTIES)

Accounts receivable generally consist of amounts due from the sale of oil and gas products and from joint interest billings to investors who have invested with the Company on specific oil and gas projects. Accounts receivable may be offset by royalty payments and are typically collateralized by the owner’s interest in a specific oil and gas project. Potential credit losses, in the aggregate, have not been significant and have not exceeded management’s expectations.

Receivables due from related parties at December 31, 2004 amounted to $129,960, and consisted of amounts due from affiliates with common ownership for joint billings on projects which they are involved in with the Company. The amounts at December 31, 2005 were not material.

F-17

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 4.   NOTES RECEIVABLE (INCLUDING RELATED PARTIES)

Notes receivable consist of the following amounts as of December 31:

	2005		2004
Related parties:
Unsecured notes receivable from shareholder; due upon demand; interest at 4.5%	$	15,000	$	100,000
Unsecured note receivable from a party related by common ownership, including interest at 6.0% This note was collected in full in March 2005		—		35,096
		15,000		135,096
Other:
Secured note receivable; interest rate of 6%; collateralized by an assignable interest in cellular Tower Sites. Payments of $35,000 are required when Assignor completes a sale of any tower site		105,000		—
Unsecured note receivable; arising from an agreement to provide funds to secure certain contract services over a two year period. The agreement requires payments to be made as the party renders services to the Company, including interest at 6%		83,626		81,151
Other unsecured notes; due on demand		40,720		20,000
		229,346		101,151
Total notes receivable	$	244,346	$	236,247

NOTE 5.   DEPOSIT ON PURCHASE OF OIL AND GAS PROPERTIES

On November 30, 2005, the Company entered into a Purchase and Sale Agreement with respect to certain New Albany Shale acreage located in Indiana, commonly called the Wabash project. Pursuant to the terms of this agreement, the Company was required to deposit into escrow for the seller $3,200,000. Interest earned from November 30, 2005 through December 31, 2005 was $6,102. The total $3,206,102 is reflected in the accompanying financial statements as deposit on purchase of oil and gas properties.

This Purchase and Sale Agreement closed on February 1, 2006. At the closing, Aurora acquired 64,000 acres of oil and gas leases from Wabash Energy Partners, L.P. and this deposit was added to the cost pool as part of the purchase price of these leasehold assets. See Subsequent Events, Note 26.

F-18

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 6.   SALE OF INTERESTS IN OIL AND GAS PROPERTIES

The Company had the following transactions related to the sale of oil and gas properties, all of which were applied to reduce the full cost pool:

			Interest	Gross
Year	Type of Property	Description	Sold	Proceeds
2005	Unproved	Various Indiana leaseholds	95%	$	7,373,737
2005	Unproved	Corner #1 project	50%		344,114
2005	Unproved	Eastview & Gaston leaseholds	25-100%		259,258
2005	Proved	Various	<5%		18,000
Total				$	7,995,109
2004	Unproven and Proved	Antrim leaseholds	80%	$	6,433,890
2004	Proved	Crossroads project	90%		292,132
2004	Unproved	New Albany shale	95%		349,829
Total				$	7,075,851

During 2004, Aurora entered into a sale agreement with an unrelated third party for $6,433,890. As part of this agreement, the third party assumed capital leases in the amount of $847,025. Further, Aurora received $1,260,576 in proceeds net of the payoff of the mezzanine facility obligation in the amount of $4,674,639 and reserve base lending obligation in the amount of $498,675 for the sale of an 80% interest in Aurora’s Antrim leasehold units located in Northeast Michigan. Proceeds, net of historical cost in the amount of $7,211,916, were recorded as a reduction to the full cost pool as the reduction of capitalized costs to the oil and gas reserve were not significantly altered.

NOTE 7.   OIL AND GAS PROPERTIES NOT SUBJECT TO AMORTIZATION

The Company is currently participating in oil and gas exploration and development activities on blocks of acreage in the states of Indiana, Michigan, Ohio, and Kentucky. A determination cannot be made about the extent, if any, of additional oil and gas reserves that should be classified as proven reserves in connection with these projects. Consequently, the associated property and exploration costs have been excluded in computing amortization of the full cost pool.

NOTE 8.   INTANGIBLE ASSETS

Intangible assets consist of the following as of December 31, 2005:

Non-compete agreements	$	3,265,000
Proprietary business relationships		1,340,000
Total		4,605,000
Less accumulated amortization		1,407,083
Intangibles, net	$	3,197,917

The intangible assets are being amortized over three years, and the future annual amortization expense is estimated to be approximately $1,535,000 through 2007.

F-19

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 9.   OTHER INVESTMENTS

Other investments consist of the following at December 31:

	2005		2004
Investments in unconsolidated subsidiaries:
Hudson Pipeline & Processing Co., LLC	$	1,224,995	$	230,396
GeoPetra Partners, LLC		344,502		—
Mineral properties		197,406		—
Other		89,074		—
	$	1,855,977	$	230,396

Hudson Pipeline & Processing Co., LLC (“Hudson”)

Hudson is a limited liability company that owns a facility plant, pipeline,rights-of-way and meter used by nearby Antrim wells, and processes the gas produced from those wells. North owns a 48.75% membership interest in this limited liability company until the revenues received from the pipeline facility equal 125% of the amount spent on construction of the pipeline, after which North’s membership interest will be 47.5%. As of January 31, 2006, North increased its membership interest to approximately 91% pursuant to a Purchase and Sales Agreement with O.I.L. Energy Corp. See Subsequent Events, Note 26.

Ownership for this investment is accounted for using the equity method, whereby the investment is stated at cost and adjusted for the Company’s equity in undistributed earnings and loss since acquisition. The construction of the pipeline began in late 2004. Operations for Hudson for the period ended December 31, 2004 were insignificant; for 2005, the Company’s allocable share of net income was $65,643.

The following is condensed financial information concerning Hudson:

Balance Sheets

	December 31,
	2005		2004
	(Unaudited)
Current assets	$	475,906	$	43,839
Construction projects in progress, net		2,201,946		749,223
Other assets		15,592		—
Total assets	$	2,693,444	$	793,062
Current liabilities	$	240,086	$	563,009
Members’ equity		2,453,358		230,053
Total liabilities and members’ equity	$	2,693,444	$	793,062

F-20

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Statements of Operations

	Year Ended
	December 31,
	2005		2004
	(Unaudited)
Revenues	$	653,362	$	24,964
Costs and expenses		518,989		22,565
Operating income		134,373		2,399
General and administrative		4,279		—
Net income before other		130,094		2,399
Interest income		2,161		—
Net income	$	132,255	$	2,399

GeoPetra Partners, LLC (“GeoPetra”)

In June 2005, the Company acquired a 30% interest in GeoPetra. GeoPetra is a limited liability company engaged primarily in the following activities (i) identification and evaluation for acquisition of oil and 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 gas and (iii) providing consultation, advice, and recommendations to the members of GeoPetra in connection with other oil and gas properties and interests, operations and activities. GeoPetra was formed April 1, 2005.

The Company invested a total of $485,741 in GeoPetra in 2005, and its allocable share of net loss for 2005 was ($141,239). The following is condensed financial information concerning GeoPetra:

Balance Sheet
December 31, 2005
(Unaudited)

Current assets	$	201,943
Prepaid expenses		48,000
Oil and gas properties, net		1,186,218
Property and equipment, net		48,992
Total assets	$	1,485,153
Current liabilities	$	289,130
Members’ equity		1,196,023
Total liabilities and members’ equity	$	1,485,153

F-21

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Statement of Operations
Period Ended December 31, 2005
(Unaudited)

Operating revenues	$	—
Operating costs and expenses		418,530
Other expense		5,187
Net loss	$	(423,717	)

Other Mineral Properties

Utah Property

The Company has retained a 25% undivided interest in the Vipont Mine located in Northwest Utah. The Company has recorded its undivided interest at $197,406, the carrying value previously reflected by Cadence, which is considered to be equivalent to its estimated fair value.

Mineral Properties in North Idaho

At December 31, 2005, the Company held unpatented mining claims in the Coeur d’Alene Mining District in distinct groups called the South Galena Group, Moe Group, Rock Creek Group and Palisades Group. The Company has undertaken only minimal exploration and development work on these properties, such as general geological reconnaissance and claim-staking activities. All of these claims have previously been written off by Cadence as permanently impaired.

During 2005, the Company entered into a mineral lease with Gold Creek Mines, Inc. on the Gold Creek claims consisting of 27 patented and 5 unpatented mining claims. The lease is for an initial term of twenty years and so long thereafter as minerals are produced from the property. The Company is obligated to spend $50,000 during the first two years of the lease on mineral exploration activities. Additionally, during the first two years of the lease, the Company is obligated to pay advance royalty payments of $750 per month, increasing to $1,000 per month during the second two year period, and $1,500 per month thereafter. At the inception of the lease, the Company made a one time advance royalty payment of $53,000 to the lessor, which was charged to expense.

NOTE 10.   PROPERTY AND EQUIPMENT

Property and equipment consist of the following at December 31:

	2005		2004
Office condominium building	$	3,165,382	$	—
Furniture and fixtures		265,115		108,047
Office equipment		39,579		—
Computer equipment		148,601		77,509
Software		85,070		11,325
Leasehold improvements		—		19,042
Vehicles and other equipment		20,171		7,050
Total property and equipment		3,723,918		222,973
Less accumulated depreciation		113,780		107,690
Property and equipment, net	$	3,610,138	$	115,283

F-22

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On April 26, 2005, the Company entered into a Condominium Purchase agreement to purchase the entire second floor of a commercial condominium project. On October 4, 2005, the Company closed on the purchase of the office condominium property, and executed a mortgage payable in the original amount of $2,925,000 (see Note 12).

Depreciation expense amounted to $52,703 and $28,249 during 2005 and 2004, respectively.

NOTE 11.   LEASES (INCLUDING RELATED PARTIES)

Oil and gas equipment which qualify as a capital lease with an original cost of $42,400 in 2004 are capitalized into the oil and gas cost pool and are amortized as part of the entire full cost pool.

The following is a schedule of annual future minimum lease payments required under capitalized lease obligations as of December 31, 2005:

2006	$	9,960
2007		3,292
Total minimum payments due		13,252
Less amounts representing interest, imputed at 6.5%		2,167
Present value of net minimum lease payments		11,085
Current portion		8,823
Obligations under capital leases, net of current portion	$	2,262

During 2003, the Company entered into a lease for office space under an operating lease on amonth-to-month basis. The leased office space was owned by an entity which was owned one-third by one of the Company’s principal shareholders and one-third by a trust in the name of another of the Company’s principal shareholders. In 2004, the Company extended this lease for a3-year term requiring monthly payments of $8,700 expiring in March 2007. Rent charged to expense during 2005 and 2004 was $95,700 and $106,800, respectively.

The Company purchased on a commercial condominium space on October 4, 2005, as more fully described in Note 10. A settlement payment of $62,250 made in 2006 released the Company from future lease payments under the lease extension agreement.

NOTE 12.   DEBT (INCLUDING RELATED PARTIES)

Short-Term Bank Borrowings

On October 12, 2005, the Company entered into a revolvingline-of-credit agreement with a bank. Under the terms of this agreement, the Company can borrow up to a maximum of $7,500,000. Interest payments are due monthly at a rate of 6.75%. Theline-of-credit agreement expires on October 15, 2006. At December 31, 2005, a balance of $6,210,000 was outstanding on the line. A payment of $2,130,000 on January 31, 2006 reduced the line of credit and the agreement was amended to a maximum line of $5,000,000. See Subsequent Events, Note 26.

During 2004, the Company entered into an unsecured revolvingline-of-credit agreement with a bank. Under the terms of this agreement, the Company was able to borrow up to a maximum of $350,000, with monthly interest payments at prime plus 1% (effective rate at December 31, 2004 of 6.0%). Subsequent to December 31, 2004, short-term borrowings in the amount of $350,000 were paid in full. Theline-of-credit agreement expired on April 1, 2005.

F-23

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Long-Term Debt

Notes Payable — Related Parties

A summary of notes payable to related parties is as follows at December 31:

		Interest
Related Party		Rate	Due Date		2005		2004
Affiliated entity	(1)	Prime	5/31/2005	**	$	—	$	1,700,000
Affiliated entity	*	6.00%	3/15/2005	**		—		86,650
Affiliated entity	*	10.50%	5/1/2006			69,833		69,833
Shareholder/director	(2)	9.50%	See below	**		—		400,000
Shareholder/director	(3)	4.68%	1/1/2006	**		—		50,000
Shareholders/directors		5.12% to 8%	From 3/15/2005 to 6/1/06	**		—		555,355
Accrued interest				**		—		156,693

Total notes payable — related parties		69,833		3,018,531
Current portion of notes payable — related parties		69,833		1,940,825
Notes payable — related parties, net of current portion	$	—	$	1,077,706

(1)	This note required payments of interest monthly and also required additional payments based upon the quantity of gas extracted from certain oil and gas properties. Interest expense related to this note amounted to $93,618 in 2004.
(2)	Monthly payments were required on this note with the principal and interest determined based upon the quantity of oil and gas extracted from certain oil and gas properties. Interest expense amounted to $45,704 in 2004.
(3)	This interest rate adjusted annually based on the highest applicable federal rate (4.68% at December 31, 2004).
*	These entities are affiliated through common ownership and ultimate management control.
**	These notes were paid in full during March 2005.

Mortgage Payable

On October 4, 2005, the Company closed a mortgage loan from Northwestern Bank in the amount of $2,925,000. The repayment schedule is monthly interest only for three successive months starting on November 1, 2005, and beginning on February 1, 2006, principal and interest in 32 monthly payments of $21,969. The loan bears interest at the rate of 6.5% per year. The maturity date is October 1, 2008. Loan proceeds were used to purchase the condominium and to pay for interior improvements to the premises.

The mortgage loan is secured by the personal guaranties of three of the Company’s directors. The mortgage had an outstanding balance of $2,865,477 at December 31, 2005.

Mezzanine Financing

In August 2004, North entered into a $30,000,000 mezzanine credit facility to enable the Company to fund its 20%-50% share of the Michigan Antrim drilling program. On December 8, 2005, North entered into an Amended Note Purchase Agreement, increasing the borrowing capacity under the existing credit facility to $50 million, representing an additional $20 million available for development. The additional commitment in the five-year

F-24

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

revolving credit facility was provided by the existing mezzanine lender, Trust Company of the West (“TCW”). The terms of this financing are as follows:

Facility Amount:	Initially up to $30,000,000 ($50,000,000 as of December 2005) secured advancingline-of-credit with overriding royalty provisions.
Interest Rate:	11.5%
Maturity:	September 29, 2009
Use of Proceeds:	To fund drilling, completion, gathering lines, and gas processing facility for certain Michigan Antrim wells.
Security:	100% working interest in all wells completed.
Payments:	Beginning September 28, 2006 and quarterly thereafter. The required payment is 75% (100% if coverage deficiency or default occurs) of Adjusted Net Cash Flow (“ANCF”) determined by deducting applicable operating expenses from gross revenue.

On January 31, 2006, the Company entered into a new senior secured revolving credit facility of up to $100 million with a new lender (see Subsequent Events, Note 26). In this connection, the TCW facility was subordinated to the new senior credit facility.

Interest expense related to this debt amounted to $329,028 in 2004, all of which was capitalized. Interest expense in 2005 related to this debt amounted to $2,171,389, of which $1,146,084 was capitalized.

The loan agreement 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).

Maturities of Long-Term Debt

Aggregate maturities of long-term debt at December 31, 2005 are as follows:

2006	$	151,533
2007		86,862
2008		2,708,000
2009		40,000,000
Total	$	42,946,395

The Company estimates that no principal payments on the mezzanine financing will be required until maturity because of the level of anticipated capital expenditures and the senior lending credit facility entered into on January 31, 2006 (see Subsequent Events, Note 26).

NOTE 13.   DEPOSIT ON SALE OF OIL AND GAS PROPERTIES

On November 30, 2005, after the execution of the agreement to purchase 64,000 acres of leasehold interests in the Wabash Project discussed in Note 5, the Company entered into a second Purchase and Sale Agreement with respect to this New Albany Shale acreage whereby the Company sold half of its interest in a combined 95,000 acre lease to New Albany-Indiana, LLC, an affiliate of Rex Energy Operating Corporation. Of these 95,000 acres, 64,000 acres were the interests acquired from Wabash Energy Partners, L.P., and 31,000 acres were acquired by Aurora in other transactions.

F-25

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Pursuant to the terms of this sales agreement, $3,500,000 was placed in escrow by the purchaser on behalf of the Company as a deposit until the closing in February 2006. Interest earned from November 30, 2005 through December 31, 2005 was $9,319. The total $3,509,319 is reflected in the accompanying financial statements as a deposit on sale of oil and gas properties.

NOTE 14.   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 34,950 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 are 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. The Class A shares mature seven years from the date of issuance. At maturity, the Class A shares will be redeemed for cash or common stock at Cadence’s option in an amount equal to the amount paid by the investors for the shares plus any accrued and unpaid dividends. If shares of common stock are to be issued at maturity, the conversion price shall be determined by the average closing bid price for the 20 trading days prior to the maturity date.

In February 2006, a total of 23,334 shares of redeemable convertible preferred stock was converted into common stock.

NOTE 15.   INCOME TAXES

A reconciliation of the provision for income taxes and the amount computed by applying the statutory Federal income tax rate to net income (loss) is as follows for the year ended December 31:

	2005			2004
Income tax (benefit) provision at the statutory rate	$	(175,500	)	$	(375,300	)
Increase (decrease) in allowance against net operating loss		173,500			335,500
Permanent differences/other		2,000			39,800
Income tax provision	$	—		$	—

The Company’s total deferred tax liabilities, deferred tax assets and deferred tax asset valuation allowances as of December 31 are as follows:

	2005			2004
Total deferred tax assets:
Net operating loss carryover	$	12,324,600		$	1,441,300
Section 1231 carryover		146,900			—
Capital loss carryover		66,000			—
Less valuation allowance		(2,391,700	)		(635,400	)
Deferred tax assets, net		10,145,800			805,900
Total deferred tax liabilities:
Excess assigned acquisition value		(4,339,000	)		—
Intangible drilling costs and other		(5,806,800	)		(805,900	)
Net deferred tax assets (liabilities)	$	—		$	—

Management determined that the deferred tax assets do not satisfy the recognition criteria of SFAS No. 109 and, accordingly, a full valuation allowance has been recorded for this amount.

F-26

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company has net operating loss carryforwards available to offset future Federal taxable income of approximately $36,249,000, which expire from 2009 through 2025. Included in this amount is a pre-merger net operating loss carryforward incurred by Cadence of approximately $16,900,000. In addition, Cadence had pre-merger section 1231 loss carryforwards of approximately $432,000, which expire in 2006, and net capital loss carryforwards of approximately $194,000, which expire in the years 2006 through 2009.

The Tax Reform Act of 1986 imposed substantial restrictions on the utilization of net operating losses and tax credits in the event of an “ownership change”, as defined by the Internal Revenue Code. Federal and State net operating losses are subject to limitations as a result of these restrictions. Under such circumstances, the Company’s ability to utilize its net operating losses against future income may be reduced.

NOTE 16.   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 $.75 per share.

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

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 — $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.

2004

The Company issued 49,976 shares of common stock in exchange for consulting services provided to the Company during the previous three years. The value assigned per share was contractual and was agreed to by the Company and the vendor in June, 2001. The amount expensed as a result of this exchange amounted to $41,479.

The Company sold 1,045,000 shares of common stock to unrelated third parties at $2.50 per share, primarily in the fourth quarter of 2004. Total proceeds from the sale of these shares amounted to $2,612,500.

The Company issued 4,800 shares of common stock as payment for consulting on the sale of the Company’s common stock. The price per share used for this exchange of $2.50 was based upon comparable sales of the Company’s common stock and amounted to $12,000.

F-27

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company issued 310,000 shares of common stock to a director upon the exercise of options at prices ranging from $.75 to $1.00 per share.

NOTE 17.   PREFERRED STOCK

During 2000, Aurora authorized 500,000 shares of Series A preferred stock with the terms and amounts set at the Board of Directors discretion. Preferred stock has liquidation preference over common stock equal to the original issue value, plus any accrued or arreared dividends.

Each share of Series A preferred stock is voting and is convertible into three shares of common stock. During 2004, 311,111 shares of preferred stock were exchanged for 933,333 shares of the Company’s common stock. The preferred shares require dividends of 6% on a cumulative basis commencing in 2001. Dividends were required to be accrued on January 1 of each year. Dividends in the amount of $127,112 were satisfied through issuance of a note payable. In early 2005, the remaining 99,350 shares of preferred stock were converted to 298,050 shares of common stock and all dividends associated with these shares were paid in full.

NOTE 18.   COMMON STOCK OPTIONS

Both Cadence and Aurora awarded stock options under plans and other arrangements in place prior to the merger. The following describes the plans that remain in place as of December 31, 2005.

On October 1, 1997, Aurora adopted an incentive qualified stock option plan which authorized the issuance of up to 1,000,000 shares of Aurora’s common stock at an option price which may not be less than 100% of the estimated fair value on the date of grant (25% effective with a January 1, 2004 amendment to the plan). The maximum term of options granted is ten years. The plan was created in an effort to retain key employees, attract new employees, obtain the services of consultants, encourage the sense of proprietorship of such persons and to stimulate the active interest of such persons in the development and financial success of the Company.

In April 2004, Cadence adopted an incentive stock option plan as part of a larger equity incentive plan that includes non-statutory stock options, stock bonuses and restricted stock awards. The equity incentive plan provides that no more than 5,000,000 shares of stock may issued pursuant to the equity awards and option prices may not be less than 100% of the estimated fair value on the date of grant. The maximum term of options granted is ten years. The purpose of the plan is to attract and retain the services of employees, directors and consultants and promote the interests of Cadence by aligning the interests of selected eligible persons under the plan with the interests of the stockholders of the Cadence and by providing to such persons an opportunity to obtain the benefits from ownership of Cadence stock.

Activity related to the two incentive stock option plans was as follows for the years ended December 31, 2005 and 2004:

	2005			2004
Options outstanding at beginning of year		344,000			250,000
Granted during the year		146,000			94,000
Assumed upon merger:
2 for 1 exchange of Aurora options		490,000			—
Cadence options		400,000			—
Options exercised		(175,000	)		—
Options outstanding at end of year		1,205,000			344,000

A majority of the Company’s outstanding stock options have been issued outside of the incentive stock option plans. These include options for the purchase of 99,999 shares which were issued to certain directors in 2004, as compensation in exchange for serving on Aurora’s board of directors.

F-28

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Activity with respect to all stock options (including options granted under the incentive stock option plans) is presented below for the years ended December 31, 2005 and 2004:

	2005					2004
				Weighted					Weighted
				Average					Average
				Exercise					Exercise
	Shares			Price		Shares			Price
Options outstanding at beginning of year		2,700,664		$	0.99		2,816,665		$	1.01
Granted during the year		156,000			3.32		193,999			0.75
Assumed upon merger:
2 for 1 exchange of Aurora options		2,856,664			—		—			—
Cadence options		1,124,349			1.79		—			—
Options exercised		(357,500	)		1.20		(310,000	)		0.99
Forfeitures and other adjustments		(31,709	)		0.43		—			—
Options outstanding at end of year		6,448,468			0.72		2,700,664			0.99

All of the above options are considered eligible for exercise as such options vest immediately upon their grant. The weighted average remaining life by exercise price as of December 31, 2005 is summarized below:

			Weighted
	Shares		Average
	Outstanding		Remaining
	and		Contractual
Range of Exercise Prices	Exercisable		Life
$0.25 - $0.38		1,187,994		5.9
$0.42 - $0.50		1,880,000		1.3
$0.63		2,333,334		0.8
$1.25 - $1.75		718,500		5.0
$2.00 - $2.50		253,640		2.4
$3.73		75,000		0.1
		6,448,468

The Company follows only the disclosure aspects of Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation”. The Company continues to apply Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for its plans. Under APB 25, the exercise price of the stock options was more than the market value of the shares at the date of grant and, accordingly, no compensation cost has been recognized in the consolidated financial statements for the outstanding stock options.

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 years ended December 31, 2005 and 2004:

	2005			2004
Net loss available to common shareholders	$	(516,272	)	$	(1,133,979	)
Deduct total stock-based compensation expense determined under fair value based method for all awards, net of related tax effects		(298,745	)		(36,746	)
Pro forma net loss	$	(815,017	)	$	(1,170,725	)

F-29

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	2005			2004
Loss per share — basic and diluted
As reported	$	(0.01	)	$	(0.05	)
Pro forma	$	(0.02	)	$	(0.05	)

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

	2005			2004
Risk-free interest rate		4	%	3%
Expected years until exercise		10		5-10
Expected stock volatility		41	%	0%
Dividend yield		0	%	0%

NOTE 19.   COMMON STOCK WARRANTS

During 2003, the Company issued 212,500 shares of stock with 212,500 warrants attached, and 25,000 warrants related to a July 2002 purchase. The warrants were valued at $51,375 using the Black-Scholes Option Price calculation. The following assumptions were made in estimating fair value: risk free interest rate 5%, volatility 100%, expected life 3 years and no expected dividends. These warrants may be used to purchase 237,500 shares of the Company’s common stock at $1.35 per share. The warrants remained exercisable through October 15, 2005.

During 2004, the Company issued certain note holders warrants to purchase a total of 765,000 shares of common stock, exercisable at $4.00 per share, expiring in three years. Both the number of warrants and the exercise price are adjustable, dependent upon certain future equity transactions of the Company. The warrants were valued at $745,237 using the Black-Scholes Option Price calculation. The following assumptions were made in estimating fair value: risk-free interest rate 5%, volatility 100%, expected life 3 three years and no expected dividends. During 2005, the Company paid back the notes which were related to these warrants. As an incentive to the note holders to allow the Company to redeem the notes prematurely, the Company modified the exercise price of the warrants to $1.75. Using current Black-Scholes calculations, the Company incurred no additional charges to its financial statements with this modification.

During 2005, the Company issued warrants to purchase a total of 14,050,000 shares of stock. These warrants were attached to 7,810,000 shares of stock which were issued for cash and debt. The warrants were valued at $3,685,875 using the Black-Scholes Option Price calculation. The following assumptions were made in estimating fair value during 2005: risk free interest rate 4%, volatility 41%, expected life 3 years and no expected dividends.

Also during 2005, Aurora issued warrants to purchase 1,900,000 shares of stock. These warrants were attached to 4,972,200 shares which were issued for cash.

NOTE 20.   OTHER INCOME

Components of other income presented in the accompanying consolidated statements of operations are summarized as follows for the year ended December 31:

	2005		2004
Project management fees	$	347,857	$	883,687
Administrative fees for producing properties		94,315		309,148
Miscellaneous income		10,449		—
Total other income	$	452,621	$	1,192,835

F-30

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 21.   RETIREMENT PLAN

The Company maintains a SIMPLE 401(k) plan for substantially all of its employees. Under this SIMPLE plan, eligible employees are permitted to contribute up to 15% of gross compensation into the retirement plan. The Company makes no matching contribution; however, the Company can make a discretionary contribution to the plan. There were no contributions to this plan in 2005 and 2004.

NOTE 22.   CONTINGENCIES

The Company is occasionally subject to various lawsuits arising in the normal course of business. In the opinion of management, the ultimate liability, if any, resulting from such matters will not have a significant effect on the Company’s results of operations, liquidity, or financial position.

NOTE 23.   EARNINGS (LOSS) PER SHARE

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

	Year Ended December 31,
	2005			2004
Basic and diluted earning (loss) per share:
Loss available to common shareholders	$	(516,272	)	$	(1,133,979	)
Weighted average common shares outstanding		40,622,000			23,636,000
Basic loss per share	$	(0.01	)	$	(0.05	)

The common stock and per share information have been retroactively adjusted to give effect to thetwo-for-one exchange ratio in the reverse acquisition of and merger with Cadence on October 31, 2005.

During 2005 and 2004, stock options and warrants and convertible preferred stock were excluded in the computation of diluted loss per share because their effect was anti-dilutive.

NOTE 24.   MINORITY INTEREST IN NET ASSETS OF SUBSIDIARIES

The following is an analysis of changes in minority interest in net assets of subsidiaries for the year ended December 31, 2004:

Balance at December 31, 2003	$	1,685,063
Distributions to minority members		(41,347	)
Income allocated to minority interest owners prior to disposal		41,243
Disposition of subsidiary and elimination of minority member interest		(90,518	)
Transfer of member interest in subsidiary in exchange for working interest		(1,578,806	)
Minority interest reclassified as other receivable		22,452
Net loss		(38,087	)
Balance at December 31, 2004	$	—

F-31

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 25.   SUPPLEMENTAL CASH FLOWS INFORMATION

Non-Cash Financing and Investing Activities

2005

None.

2004

During 2004, Aurora conveyed its entire interest totaling $338,177 in AIL, BAC and ANG back to the respective consolidated subsidiaries in exchange for oil and gas reserves in the same amount. As a result of this conveyance, Aurora no longer maintained a controlling interest in these subsidiaries. Minority interests and oil and gas properties related to this conveyance, in the amount $1,992,361, has been eliminated from these consolidated financial statements.

Pursuant to the purchase and sale agreement with an unrelated third party more fully described in Note 6, Aurora repaid in full the mezzanine facility obligation in the amount of $4,674,639, reserve base lending obligation in the amount of $498,675 and transferred certain lease obligations in the amount of $847,025.

During 2004, $127,112 of cumulative dividends on convertible preferred stock were satisfied by issuance of a note payable.

Other Cash Flows Information

Cash paid for interest amounted to $2,258,691 and $681,025 in 2005 and 2004, respectively.

NOTE 26.   SUBSEQUENT EVENTS

Senior Secured Credit Facility

On January 31, 2006, the Company entered into a Credit Agreement with BNP Paribas. The new facility consists of a senior secured revolving credit facility in an amount of up to $100 million, having an initial borrowing base without hedges of $40 million. The ability to increase the borrowing base beyond $50 million is subject to certain conditions in the Second Lien Notes held by TCW (see Note 12). The proceeds from this facility are intended to be used for drilling, development, and acquisitions as well as other general corporate purposes. This facility matures the earlier of January 31, 2010 or 91 days prior to the maturity of the Second Lien Notes currently due September 2009. This facility provides for borrowings tied to BNP’s prime rate (or if higher, the federal funds effective rate plus 0.5%) or LIBOR plus 1.25 to 2.0% depending on the borrowing base utilization, as selected by the Company.

O.I.L. Acquisition

On January 31, 2006, the Company completed the acquisition of additional working interests in the Hudson project area (see Note 9). The total purchase price of approximately $27,500,000 was financed under the senior secured credit facility with BNP. This acquisition increased the Company’s working interest in the project area from an average of approximately 49% to 96% in the project. Additionally, pursuant to this acquisition was the purchase of 48.75% member interest in Hudson, which pipeline and production facilities related to the Hudson project. This increased the Company’s member ownership from 48.75% to 97%.

Rex/Wabash Transaction

On February 1, 2006, the Company completed a transaction involving the acquisition of 64,000 acres of New Albany Shale acreage in the Wabash Project (see Note 5). The Company then sold half interest in its accumulated 95,000 acres to an unrelated third party, resulting in a net acreage gain to the Company.

F-32

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Stock Option and Warrant Exercise

In February 2006, the Company reported the receipt of a total of approximately $20.6 million in cash proceeds from the exercise of certain options and warrants. Approximately $18 million of this cash was received in 2006; the balance of approximately $2.6 million was received in 2005.

Pro Forma Presentation

The pro forma effect of these 2006 subsequent events on the Company’s financial position, assuming that they had occurred as of December 31, 2005, is as follows:

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET
DECEMBER 31, 2005
(Unaudited)

			2006
			Subsequent
	Historical		Events			Pro Forma
Current assets	$	19,256,000	$	15,870,000		$	35,126,000
Oil and gas properties, using full cost accounting		68,961,000		27,197,000			96,158,000
Property and equipment, net		3,610,000		—			3,610,000
Other Investments		1,856,000		—			1,856,000
Other Assets		762,000		2,500,000			3,262,000
Deposit on purchase of oil and gas properties		3,206,000		(3,206,000	)		—
Goodwill and other intangibles		19,171,000		—			19,171,000
Total assets	$	116,822,000	$	42,361,000		$	159,183,000
Current liabilities	$	13,832,000	$	(2,130,000	)	$	11,702,000
Deposit on sale of oil and gas properties		3,509,000		(3,509,000	)		—
Long-term debt		42,795,000		30,000,000			72,795,000
Total liabilities		60,136,000		24,361,000			84,497,000
Redeemable preferred stock		60,000		—			60,000
Shareholders’ equity		56,626,000		18,000,000			74,626,000
Total liabilities and shareholders’ equity	$	116,822,000	$	42,361,000		$	159,183,000

F-33

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION

(UNAUDITED)

Supplemental Reserve Information

The following information presents estimates of our proved oil and gas reserves. The Company retained the services of an independent petroleum consultant (Data & Consulting Services, Division of Schlumberger Technology Corporation) to estimate its proved natural gas reserves at December 31, 2005 and 2004. Included in the tables that follow are proved oil and natural gas reserves located in Michigan that were acquired as a separate property acquisition near the end of the year and proved oil and 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, 2005 were estimated under the Securities and Exchange Commission (“SEC”) reporting standards. Natural gas reserves at December 31, 2004 were estimated under the SEC reporting standards with the exception of operating costs assumptions. Operating costs were calculated as a monthly amount for each individual unit which amounts decline over the first eight years and remain constant thereafter.

	Oil			Natural Gas
Estimates of Proved Reserves	(mbbl)			(mmcf)
Proved reserves as of December 31, 2003		—			16,660
Revisions of previous estimates		—			—
Purchases of minerals in place		—			—
Extensions and discoveries		—			18,440
Production		—			(151	)
Proved reserves as of December 31, 2004		—			34,949
Revisions of previous estimates		6			5,381
Purchases of minerals in place		103			1,572
Extensions and discoveries		—			22,107
Production		(10	)		(688	)
Proved reserves as of December 31, 2005		99			63,321
Proved developed reserves:
December 31, 2004		—			12,520
December 31, 2005		70			45,205

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

	2005		2004
Natural gas (per mcf)	$	9.89	$	6.195
Oil (per barrel)	$	56.41		n/a

F-34

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION — (Continued)

(UNAUDITED)

Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and 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.

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 decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions 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, 2005 and 2004.

	2005			2004
Future gross revenues(1)	$	632,058,720		$	216,162,240
Future production costs(2)		(182,710,406	)		(74,240,020	)
Future development costs(2)		(15,073,590	)		(13,659,320	)
Future net cash flows before income taxes		434,274,724			128,262,900
Future income tax expense(3)		(101,521,160	)		(42,167,000	)
Future net cash flows after income taxes		332,753,564			86,095,900
Discount at 10% per annum		(179,885,324	)		(53,936,190	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	152,868,240		$	32,159,710

(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 gas producing activities and tax carry forwards.

F-35

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION — (Continued)
(UNAUDITED)

Changes in Standardized Measure of Discounted Future Cash Flows

The following table sets forth the change in Standardized Measure of Discounted Future Net Cash Flows for the years ended December 31, 2005 and 2004.

	2005			2004
Beginning balance	$	32,159,710		$	15,708,150
Revisions to reserves proved in prior years:
Net change in prices and production costs		85,425,515			—
Net change in future development costs		6,299,524			—
Net change due to revisions in quantity estimates		33,335,739			—
Net change in accretion of discount		(66,761,600	)		—
Other		38,137,602			(6,025,690	)
Total revisions to reserves provided in prior years		96,436,780			(6,025,690	)
New discoveries and extensions, net of future development and production costs		76,487,826			12,272,113
Purchases of minerals in place		11,834,500			—
Sales of oil and gas produced, net of production costs		(4,696,416	)		(345,673	)
Previously estimated development costs incurred		—			10,550,810
Net change in income taxes		(59,354,160	)		—
Net change in standardized measure of discounted cash flows		120,708,530			16,451,560
Ending balance	$	152,868,240		$	32,159,710

Capitalized Costs Related to Oil and 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, 2005 and 2004.

	2005		2004
Proved properties	$	39,643,003	$	7,585,807
Unproved properties		37,279,889		7,981,727
Total oil and gas properties		76,922,892		15,567,534
Less accumulated depreciation, depletion and amortization		7,962,138		600,077
Oil and gas properties — net	$	68,960,754	$	14,967,457
Cadence’s share of equity method investees’ net capitalized cost	$	355,865	$	—

F-36

CADENCE RESOURCES CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION — (Continued)
(UNAUDITED)

Costs Incurred in Oil and 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.

The following table sets forth costs incurred related to the Company’s oil and gas activities for the years ended December 31, 2005 and 2004.

	2005		2004
Property acquisition costs:
Proved	$	22,763,734	$	1,932,442
Unproved		16,400,997		6,836,229
Exploration		781,586		—
Development		29,927,619		1,782,139
Total costs incurred	$	69,873,936	$	10,550,810
Cadence’s share of equity method investees’ costs of property acquisition, exploration and development	$	355,865	$	—

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, 2005 and 2004.

	2005			2004
Oil and gas sales	$	6,743,444		$	960,011
Production and lease operating costs		(2,047,028	)		(614,338	)
Depreciation and depletion		(1,155,254	)		(203,249	)
Results of producing activities	$	3,541,162		$	142,424

These results of operations do not include a provision for income taxes due to the net operating loss carry forward available to offset taxable income during both 2005 and 2004.

F-37

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Aurora Oil & Gas Corporation and Subsidiaries

Traverse City, Michigan

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

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

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

RACHLIN COHEN & HOLTZ LLP

Miami, Florida

August 7, 2006

F-38

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

June 30, 2006

(Unaudited)

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,594,953
Accounts receivable
Oil and gas sales		2,189,886
Joint interest owners		6,401,514
Notes receivable
Related party		50,720
Other		236,626
Drilling advances		988,734
Prepaid expenses and other current assets		328,770
Short-term derivative instruments		962,015
Total current assets		14,753,218
PROPERTY AND EQUIPMENT:
Oil and gas properties, using full cost accounting:
Proved properties		79,213,485
Unproved properties		33,791,338
Properties held for sale		21,365,575
Less: accumulated depletion and amortization		(10,072,195	)
Total oil and gas properties, net		124,298,203
Pipelines		4,831,358
Other property and equipment		3,943,612
Less: accumulated depreciation		(359,973	)
Total property and equipment, net		132,713,200
OTHER ASSETS:
Goodwill		15,973,346
Intangibles (net of accumulated amortization of $2,174,583 and $1,407,083, respectively)		2,430,417
Other investments		934,606
Debt issuance costs (net of accumulated amortization of $462,242 and $79,096, respectively)		2,731,396
Total other assets		22,069,765
TOTAL ASSETS	$	169,536,183
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	10,062,326
Accrued liabilities		42,604
Short-term bank borrowings		10,000
Current portion of obligations under capital leases		7,173
Current portion of mortgage payable		81,902
Drilling advances		622,537
Total current liabilities		10,826,542
LONG-TERM LIABILITIES:
Asset retirement obligation		1,013,329
Mortgage payable		2,751,495
Senior secured credit facility		40,000,000
Mezzanine financing		40,000,000
Total long-term liabilities		83,764,824
Total liabilities		94,591,366
COMMITMENTS, CONTINGENCIES AND SUBSEQUENT EVENTS
REDEEMABLE CONVERTIBLE PREFERRED STOCK		19,924
SHAREHOLDERS’ EQUITY:
Common stock, $.01 par value; authorized 250,000,000 shares; issued and outstanding 81,965,017 shares		819,651
Additional paid-in capital		77,757,502
Accumulated other comprehensive income		962,015
Accumulated deficit		(4,614,275	)
Total shareholders’ equity		74,924,893
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	169,536,183

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

F-39

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Six Months Ended June 30, 2006 and 2005

(Unaudited)

	2006			2005
REVENUES:
Oil and gas sales	$	10,941,220		$	1,097,906
Interest income		244,214			165,910
Equity in (loss) income of unconsolidated subsidiary		(158,714	)		12,397
Other income		596,999			349,611
Total revenues		11,623,719			1,625,824
EXPENSES:
General and administrative		3,242,713			1,126,396
Pipeline operating expenses		284,201			—
Production and lease operating		3,411,051			652,957
Depletion, depreciation and amortization		3,024,166			102,227
Interest expense		3,564,154			237,354
Taxes		29,361			237,697
Total expenses		13,555,646			2,356,631
LOSS BEFORE MINORITY INTEREST		(1,931,927	)		(730,807	)
MINORITY INTEREST IN (INCOME) OF SUBSIDIARIES		(17,919	)		(6,190	)
NET LOSS	$	(1,949,846	)	$	(736,997	)
NET LOSS PER COMMON SHARE — BASIC AND DILUTED	$	(0.03	)	$	(0.02	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING — BASIC AND DILUTED		76,011,115			36,157,838

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

F-40

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

Six Months Ended June 30, 2006

(Unaudited)

	Shares		Amount
COMMON STOCK:
Balance, beginning		61,536,261	$	615,363
Cashless exercise of common stock options and warrants		3,280,105		32,801
Conversion of redeemable convertible preferred stock to common stock		23,334		233
Exercise of common stock options and warrants		15,565,457		155,655
Issuance of common stock to related party		90,000		900
Issuance of common stock to related party in lieu of commission relating to exercise of warrants		1,469,860		14,699
Balance, end		81,965,017		819,651
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning				58,670,698
Cashless exercise of common stock options and warrants				(32,801	)
Conversion of redeemable convertible preferred stock to common stock				39,768
Stock-based compensation				757,442
Exercise of common stock options and warrants				17,988,794
Issuance of common stock to related party				348,300
Issuance of common stock to related party in lieu of commission relating to exercise of warrants				(14,699	)
Balance, end				77,757,502
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Balance, beginning				—
Unrealized gains on derivative instrument				1,754,365
Reclassification of gain on derivative instrument				(792,350	)
Balance, end				962,015
ACCUMULATED DEFICIT:
Balance, beginning				(2,660,134	)
Dividends accrued				(4,295	)
Net loss				(1,949,846	)
Balance, end				(4,614,275	)
TOTAL SHAREHOLDERS’ EQUITY			$	74,924,893

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

F-41

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Six Months Ended June 30, 2006 and 2005

(Unaudited)

	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,949,846	)	$	(736,997	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		3,024,166			117,504
Amortization of debt issuance costs		383,422			—
Accretion of asset retirement obligation		36,989			—
Stock-based compensation		392,149			—
Equity in (loss) income of non-consolidated entities		158,714			(12,397	)
Other		(20,950	)		—
Minority interest in income of subsidiaries		17,919			6,190
Changes in operating assets and liabilities, net
Accounts receivable		(1,568,754	)		65,667
Accounts receivable — related party		—			(10,792	)
Drilling advance assets		(988,734	)		—
Prepaid expenses		(88,528	)		(36,752	)
Accounts payable		2,634,781			126,333
Drilling advance liabilities		622,537			(143,807	)
Accrued liabilities		(16,959	)		165,080
Net cash provided by (used in) operating activities		2,636,906			(459,971	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for oil and gas development		(42,459,080	)		(14,447,849	)
Capital expenditures for property and equipment		(219,694	)		(105,677	)
Proceeds from sale of oil and gas properties		10,500,000			7,373,737
Proceeds from sale of other investments		13,096			—
Payments for capitalized merger costs		—			(263,092	)
Advances of notes receivable		(30,000	)		(72,379	)
Advances of notes receivable — related parties		(30,000	)		—
Payments received on notes receivable — related parties		17,000			85,000
Purchase of member interest in Hudson Pipelines and Processing Co., L.L.C.		(162,108	)		(501,956	)
Investment in unconsolidated subsidiary		(475,000	)		(14,000	)
Net cash used in investing activities		(32,845,786	)		(7,946,216	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term bank borrowings (payments)		(6,200,000	)		(350,000	)
Advances on senior secured credit facility, net of financing costs of $2,386,613		9,997,394			—
Advances on mezzanine financing, net of financing costs of $150,000		—			9,850,000
Payments on mortgage obligation		(32,080	)		—
Payments on notes payable — related party		(69,833	)		(2,948,698	)
Payments on capital lease obligations		(3,912	)		(4,068	)
Distributions to minority interest members		—			(805,000	)
Net proceeds from sales of common stock		—			11,025,000
Net proceeds from exercise of options and warrants		18,144,449			—
Dividends paid on preferred stock		(12,823	)		(44,340	)
Other		—			20,177
Net cash provided by financing activities		21,823,195			16,743,071
Net (decrease) increase in cash and cash equivalents		(8,385,685	)		8,336,884
Cash and cash equivalents, beginning of the period		11,980,638			5,179,582
Cash and cash equivalents, end of the period	$	3,594,953		$	13,516,466
NON-CASH FINANCING AND INVESTING ACTIVITIES:
Oil and gas properties asset retirement obligation	$	976,343		$	—
Purchase of oil and gas working interest through senior secured credit facility	$	27,615,993		$	—
CASH PAID FOR INTEREST	$	3,430,225		$	632,500

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

F-42

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

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

As an independent oil and 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 gas prices will continue to be subject to wide fluctuations in the future. A substantial or extended decline in natural gas and oil prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and access to capital, and on the quantities of natural gas and oil reserves that can be economically produced.

NOTE 2.   BASIS OF PRESENTATION

The financial information included herein is unaudited. However, such information includes all adjustments (consisting solely of normal recurring adjustments), which are, in the opinion of management, necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods. The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year. Certain amounts as reported in the 2005 financial statements have been reclassified to conform with the 2006 presentation.

Certain information, accounting policies and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to certain rules and regulations of the Securities and Exchange Commission. These financial statements should be read in conjunction with the audited consolidated financial statements and notes for the year ended December 31, 2005.

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

NOTE 3.   ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT OBLIGATIONS

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

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 lands to ecological condition similar to that existing before oil and gas extraction began. Prior to January 1, 2006, such amount was not considered material.

Effective January 1, 2006, the Company recorded a liability of $812,634 (an “asset retirement obligation” or “ARO”) on the consolidated balance sheet and capitalized the asset retirement cost to oil and gas properties. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for the company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs are depreciated on aunit-of-production basis within the related full cost pool. The accretion expense is included in interest expense and the depreciation expense is included in depreciation, depletion and amortization on the condensed consolidated statement of operations.

The change in the ARO for the six months ended June 30, 2006 is as follows:

Balance as of January 1, 2006	$	812,634
Accretion expense		15,237
Balance as of March 31, 2006		827,871
Additions		263,026
Revisions		(99,317	)
Accretion expense		21,749
Balance as of June 30, 2006	$	1,013,329

NOTE 4.   RECENT ACCOUNTING PRONOUNCEMENTS

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

In February 2006, the FASB issued Financial Staff Position (“FSP”) No. 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. We adopted this FSP in the second quarter of 2006. The implementation did not have an effect on the results of operations or financial position.

In April 2006, the FASB issued FSP No. FIN 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R),” which requires the use of a “by design” approach for determining whether an interest is variable when applying FASB Interpretation No. 46, “Consolidation of Variable Interest Entities.” This approach includes evaluating whether an interest is variable based on a thorough understanding of the design of the potential variable interest entity (“VIE”), including the nature of the risks that the potential VIE

F-44

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

was designed to create and pass along to interest holders in the entity. The guidance in this FSP is effective for reporting periods beginning after June 15, 2006. We will adopt the guidance presented in this FSP in the third quarter of 2006 on a prospective basis. We do not expect the adoption of this FSP to have a material impact on our results of operations or financial position.

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

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

The Company recognizes all derivative instruments as assets or liabilities in the balance sheet at fair value. The accounting treatment for changes in fair value as specified in SFAS No. 133 is dependent upon whether or not a derivative instrument is designated as a hedge. For derivatives designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in Accumulated Other Comprehensive Income on the Company’s balance sheet until the hedged item is recognized in earnings as gas revenue. If this hedge has an ineffective portion, that particular portion of the gain or loss would be immediately reported in earnings.

Effective April 1, 2006, the Company entered into financial swap contract for 5,000 mmbtu per day at a fixed price of $8.59 per mmbtu covering a12-month period. For the six months ended June 30, 2006, the Company has recognized in Accumulated Other Comprehensive Income, net unrealized gain of $962,015 on a swap contract that has been designated as a cash flow hedge on forecasted sales of natural gas. The balance is expected to be reclassified into earnings within the next nine months. The Company has also recorded as of June 30, 2006, a corresponding short-term derivative instrument asset totaling $962,015 in Current Assets. In addition, for six months ended June 30, 2006, the Company recorded a $792,350 net gain in earnings from hedging activities (included in oil and gas revenues).

For the six months ended June 30, 2005, the Company had no derivative instruments to manage price risk on its natural gas production.

On July 14, 2006, the Company entered into another financial swap contract for 5,000 mmbtu per day at a fixed price of $9.00 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

F-45

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

their respective estimated fair value due to the short-term maturities and approximate market interest rates of these instruments.

NOTE 6.   ACQUISITIONS AND DISPOSITIONS

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

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

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

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 financial statements.

2006-Wabash Project

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

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 result of this transaction, Aurora received gross proceeds in the amount of $7,373,737. After deducting a distribution to subsidiary members of $805,000 and an additional $1,000,000 set aside for the subsidiary’s share of anticipated future drilling expense, approximately $5,500,000 of net proceeds was retained by Aurora.

2005- GeoPetra Partners, L.L.C. Investment

In June 2005, the Company acquired a 30% interest in GeoPetra Partners, LLC (“GeoPetra”) for $14,000. GeoPetra is a limited liability company engaged primarily in the following activities (i) identification and evaluation for acquisition of oil and gas properties and interest and entities which hold such properties and interests, (ii) areas to be explored and developed for the production of oil and gas and (iii) providing consultation, advice and recommendations to the members of GeoPetra in connection with other oil and gas properties and interests, operations and activities. GeoPetra was formed April 1, 2005.

F-46

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 7.   DEBT

Short-Term Bank Borrowings

On October 12, 2005, the Company entered into a $7.5 million revolvingline-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, a Company executive officer pledged certain shares of AOG common stock under his control. The interest rate is Wall Street prime with interest payable monthly in arrears. Principal is payable at the expiration of the line of credit, October 15, 2006. As of June 30, 2006, Northwestern Bank reduced the revolvingline-of-credit by $90,000 for outstanding letters of credit (as described in Note 13 “Contingencies and Commitments”). Interest expense for the six months ended June 30, 2006 was $178,454.

Note Payable — Related Parties

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

Mortgage Payable

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

Mezzanine Financing

On December 8, 2005, the Company entered into an Amended Note Purchase Agreement, to increase its five-year mezzanine credit facility with Trust Company of the West (“TCW”) from $30 million to $50 million for the Michigan Antrim drilling program. The borrower is North. Upon closing of the BNP Paribas (“BNP”) senior secured credit facility discussed below, TCW now holds a second lien position in the Michigan Antrim natural gas properties. The interest rate is fixed at 11.5% per year, calculated and payable in arrears. Beginning September 28, 2006 and quarterly thereafter, the required principal payment is 75% (100% if coverage deficiency or default occurs) of “adjusted net cash flow” determined by deducting specified expenses including capital expenditures from “gross cash revenue”. The maturity date is September 29, 2009. The borrowing capacity 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 capacity as 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).

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

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

overriding royalty interest, net to its interest, in any new leases acquired in these counties while the loan is outstanding.

For the six months ended June 30, 2006, interest expense for the mezzanine credit facility was $2,351,111 of which $555,522 was capitalized. For the six months ended June 30, 2005 interest expense was $641,221 of which $456,667 was capitalized.

Senior Secured Credit Facility

On January 31, 2006, the Company entered into a senior secured credit facility with BNP for drilling, development, and acquisitions as well as other general corporate purposes. The borrower is North. The initial borrowing base is $40 million without hedges. As proved reserves are added, this borrowing base may increase to $50 million without TCW consent, and $100 million with TCW consent. A required semi-annual reserve report may result in an increase or decrease in credit availability. The security for this facility is a first lien position in certain Michigan Antrim assets; a guarantee from Aurora; and a guarantee from AOG 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. This facility provides for borrowings tied to BNP’s prime rate (or, if higher, the federal funds effective rate plus 0.5%) or a LIBOR-based rate (LIBOR multiplied by a statutory reserve rate) plus 1.25 to 2.0% depending on the borrowing base utilization under the facility. For the six months ended June 30, 2006, interest expense was $1,106,397 of which $91,455 was capitalized and interest paid was $746,327.

On July 14, 2006, the senior secured credit facility was amended in two respects. The credit availability was increased to $50 million. In addition, the trailing12-month interest coverage ratio covenant was amended to defer this requirement until the fourth quarter of 2006, and to provide for a reduced ratio for that quarter. The latter 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 describe 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 first quarter of 2006.

The senior secured 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 a current ratio and an interest coverage ratio.

NOTE 8.   COMMON STOCK

From late December 2005 through early February 2006, the Company reduced the exercise price of certain outstanding options and warrants in order to encourage the early exercise of these securities. Each holder who took advantage of the reduced exercise price was required to execute a six-month lock up agreement with respect to the shares issued in the exercise. As a result of the options and warrants exercised pursuant to this reduced exercise price arrangement, and pursuant to other exercises of outstanding options, an additional 20,315,422 shares were issued during the six months ended June 30, 2006 representing 15,565,457 shares issued for cash proceeds of $18,144,449, and 4,749,965 shares issued pursuant to cashless exercises of the applicable and other warrants or options. In December 2005 an additional 2,160,000 shares were issued for cash proceeds of $2,916,000.

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

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

F-48

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 9.   STOCK-BASED COMPENSATION

On January 1, 2006, the Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment,” (SFAS No. 123R) to account for stock-based employee compensation. Among other items, SFAS No. 123R eliminates the use of Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and the intrinsic value method of accounting and requires companies to recognize the cost of employee services received in exchange for stock-based awards based on the grant date fair value of those awards in their financial statements. The Company elected to use the modified prospective method for adoption, which requires compensation expense to be recorded for all unvested stock options beginning in the first quarter of adoption. For stock-based awards granted or modified subsequent to January 1, 2006, compensation expense, based on the fair value on the date of grant, will be recognized in the financial statements over the vesting period.

For the six months ended June 30, 2006, the Company recorded stock-based compensation of $757,442 under the 2006 Stock Incentive Plan (as described in Note 10 “Common Stock Options”) and a certain employment agreement (as described in Note 13 “Contingencies and Commitments”). Of that amount, $392,149 has been included in general and administrative expense on the condensed consolidated statement of operations and $365,293 has been capitalized in oil and gas properties. The impact on future net income is estimated to be $4,538,193 recognized over the applicable requisite service period of approximately three years.

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

	2005
Net loss	$	(736,997	)
Deduct total stock-based compensation expense determined under fair value based method for all awards, net of relaxed tax effects		—
Pro forma net loss	$	(736,997	)
Loss per share — basic and diluted
As reported	$	(0.02	)
Pro forma	$	(0.02	)

There were no options granted during the six months ended June 30, 2005.

NOTE 10.   COMMON STOCK OPTIONS

Stock Option Plans

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

On March 16, 2006, the Company’s Board of Directors adopted an incentive stock option plan as part of a larger equity incentive plan (the “2006 Stock Incentive Plan”) that also provides for non-statutory stock options, stock bonuses and restricted stock awards. The stockholders approved the Plan at the annual meeting of the stockholders on May 19, 2006. The purpose of the Plan is to promote the interests of the Company by aligning the interests of employees (including directors and officers who are employees) of the Company, consultants and non-

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

employee directors of the Company and to provide incentives for such persons to exert maximum efforts for the success of the Company and affiliates. The 2006 Stock Incentive Plan provides that no more than 8,000,000 shares of stock may be issued in equity awards under the plan, the exercise price for incentive stock options shall not be less than 100% of fair market value on the date of grant, and unless otherwise determined by the Board, the exercise price for non-statutory stock options shall be not less than 100% of fair market value on the date of grant. The maximum term of options granted is 10 years.

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

	2006			2005
Options outstanding at beginning of period		1,205,000			344,000
Options granted		2,333,500			—
Options forfeited and other adjustments		(419,266	)		—
Options exercised		(254,734	)		—
Options outstanding at end of period		2,864,500			344,000

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

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

For six months ended June 30, 2006, the Company recorded stock-based compensation of $722,757 for the 2006 Stock Incentive Plan. Of that amount, $357,464 has been included in general and administrative expense on the consolidated statement of operations and $365,293 has been capitalized.

All Stock Options

Activity with respect to all stock options is presented below for six months ended June 30, 2006 and 2005:

	2006					2005
				Weighted Average				Weighted Average
	Shares			Exercise Price		Shares		Exercise Price
Options outstanding at beginning of period		6,448,468		$	0.72		2,700,664	$	0.99
Options granted		2,333,500			3.96		—		—
Options exercised		(3,642,926	)		0.67		—		—
Forfeitures and other adjustments		(344,266	)		4.76		—		—
Options outstanding at end of period		4,794,776			2.05		2,700,664		0.99
Exercisable at end of period		2,751,609
Weighted average fair value of options granted				$	4.84			$	0.81

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 June 30, 2006 was

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AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

approximately $9,942,000 and intrinsic value of the options exercisable at June 30, 2006 was approximately $8,605,000. The intrinsic value of the options exercised during the six months ended June 30, 2006 was $12,118,000.

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

	Outstanding		Average		Exercisable		Average
Range of Exercise Prices	Shares		Life		Shares		Life
$0.25 - $0.38		857,996		3.9		857,996		3.9
$0.50 - $0.75		1,580,000		2.5		1,580,000		2.5
$1.25 - $1.75		402,000		7.4		110,000		2.2
$2.45 - $2.55		150,280		3.5		60,280		3.0
$3.62		1,000,000		4.4		—		—
$4.55 - $4.70		554,500		9.6		3,333		8.8
$5.19 - $5.54		250,000		6.2		140,000		4.7
		4,794,776		4.5		2,751,609		3.0

NOTE 11.   COMMON STOCK WARRANTS

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

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

As of June 30, 2006, these common stock warrants had an average remaining contractual life of 2.39 years and weighted average exercise price per share of $1.71.

NOTE 12.   NET INCOME (LOSS) PER SHARE

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

During the six months ended June 30, 2006 and 2005, stock options, warrants and convertible preferred stock were excluded in the computation of diluted loss per share because their effect was anti-dilutive.

F-51

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 13.   CONTINGENCIES AND COMMITMENTS

Environmental Risk

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

Letters of Credit

For each salt water disposal well drilled in the State of Michigan, the Company is required to issue a letter of credit to the Michigan Supervisor of Wells. The Supervisor of Wells may draw on the letter of credit if the Company fails to comply with the regulatory requirements relating to the locating, drilling, completing, producing, reworking, plugging, filling of pits, and clean up of the well site. The letter of credit or a substitute financial instrument is required to be in place until the salt water disposal well is plugged and abandoned. For drilling natural gas wells, the Company is required to issue a blanket letter of credit to the Michigan Supervisor of Wells. This blanket letter of credit allows the Company to drill an unlimited number of gas wells. The existing letters of credit have been issued by Northwestern Bank of Traverse City, Michigan, and are secured only by a Reimbursement and Indemnification Commitment issued by the Company, together with a right of set-off against all of the Company’s deposit accounts with Northwestern Bank. At June 30, 2006, a total of $852,500 letters of credit to the Michigan Supervisor of Wells were outstanding.

Employment Agreement

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

NOTE 14.   RETIREMENT BENEFITS

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

NOTE 15.   OIL AND GAS PROPERTIES HELD FOR SALE

Management is currently in the process of evaluating the Company’s property portfolio to ensure that the oil and gas properties portfolio properly matches the Company’s long-term strategic plan. During the second quarter of 2006, the Company identified certain leasehold properties as held for sale due to their high probability of being sold within the next 12 months. Total oil and gas properties held for sale amounted to $21,365,575 at June 30, 2006 of which $11,857,821 is proved and $9,507,754 is unproved. These properties are carried at the lower of historical cost

F-52

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

or fair value. Under the full cost method, sales of oil and gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The Company has evaluated the proved reserves of these properties and determined that there is no significant effect on the proved reserves regarding the assets held for sale. At June 30, 2005, no properties were classified as held for sale.

NOTE 16.   SUBSEQUENT EVENTS

Pending Acquisition

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

Bach Acquisition

On July 10, 2006, the Company entered into a binding letter of intent to purchase all the assets of Bach Enterprises, Inc., certain assets owned by Bach Energy, LLC and a limited liability company known as Kingsley Development LLC (together “Bach”). The letter of intent contemplates a 60 day due diligence period followed by notice and a 30 day cure period if material issues are identified in the due diligence process. Closing is expected to occur within 90 days. Bach is primarily an oil and 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.

DeSoto Parish, Louisiana Disposition

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

F-53

APPENDIX A

Reserve and Economic Evaluation of
Proved Reserves of Certain
Aurora Oil & Gas Corporation
Michigan Properties
As of July 1, 2006

Unescalated Prices and Costs

Prepared For

Aurora Oil & Gas Corporation

Traverse City, Michigan

Prepared By

Data & Consulting Services

Division of Schlumberger Technology Corporation

Pittsburgh, Pennsylvania

September 2006

A-1

Data & Consulting Services

Division of Schlumberger Technology Corporation

1310 Commerce Drive

Park Ridge One

Pittsburgh, PA15275-1011

Tel: 412-787-5403

Fax: 412-787-2906

14 September 2006

Aurora Oil & Gas Corporation
4110 Copper Ridge Drive
Suite 100
Traverse City, MI 49684

Dear Gentlemen:

At the request of Aurora Oil & Gas Corporation (AURORA), Schlumberger Data & Consulting Services, Division of Schlumberger Technology Corporation (DCS) has prepared a reserve and economic evaluation of certain proved reserves in several Antrim Shale projects as of July 1, 2006. Certain data from this project are required for disclosure as required by the Securities and Exchange Commission (SEC)Regulation S-K. The SEC recognizes only proved reserves. As such the value of the pipeline revenue and financial hedges should not be included in filings with the SEC or summarized with the Proved values. Unescalated prices and costs were used for all properties contained in this evaluation. These projects were evaluated to a maximum remaining reserve life of 40 years. All economics presented are before federal income taxes (BFIT). The proved net reserves and economic valuation thereof are summarized inTable 1.

TABLE 1
ESTIMATED NET RESERVES & INCOME
CERTAIN PROVED OIL & GAS INTERESTS
AURORA OIL & GAS CORPORATION
AS OF JULY 1, 2006

	Proved		Proved				Total
	Developed		Developed		Proved		Proved
	Producing		Non-Producing		Undeveloped		Reserves
Remaining Net Reserves
Gas — MMscf		57,645.62		13,293.90		30,471.95		101,411.47
Income Data (M$)
Future Net Revenue		329,156.47		75,908.18		173,994.81		579,059.46
Deductions:
Net Production Taxes		19,749.39		4,554.49		10,439.69		34,743.57
Net AdValorem Taxes		0.00		0.00		0.00		0.00
Net Investment		0.00		1,062.69		24,886.80		25,949.49
Net Well Costs		71,002.85		10,657.69		32,656.49		114,317.03
Other Costs		69,262.60		16,779.97		34,041.61		120,084.18
Future Net Income (FNI)		169,141.64		42,853.98		71,970.23		283,965.85
Discounted PV@10% (M$)		81,252.03		20,508.01		23,714.66		125,474.70

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Division of Schlumberger Technology Corporation

14 September 2006

Page 2

RESERVE ESTIMATE

Reservoir simulation and history matching of analogous offset projects provide the basis for the production forecasts for the projects. The reservoir simulation was conducted using SHALEGAS^tm, DCS’s multi-phase reservoir simulator designed specifically for evaluating fractured shale formations. We used SHALEGAS^tm to history match the data from existing wells as supplied by AURORA in the respective projects or offset projects. Using the resulting reservoir properties and the proposed well spacing for each project, we used SHALEGAS^tm to forecast a typical curve shape from which we could construct a type curve for each project. The estimates of reserves are in theReserve Summaries andReserve Detailssections of this report. We utilized PhdWin to generate these reports.

Reserve estimates are strictly technical judgments. The accuracy of any reserve estimate is a function of the quality of data available and of the engineering and geological interpretations. The reserve estimates presented in this report are believed reasonable; however, they are estimates only and should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify their revision.

RESERVE CATEGORIES

Reserves were assigned to the proved developed producing (PDP), proved non-producing (PDNP), and proved undeveloped (PUD) reserve categories. Oil and gas reserves by definition fall into one of the following categories: proved, probable, and possible. The proved category is further divided into: developed and undeveloped. The developed reserve category is even further divided into the appropriate reserve status subcategories: producing and non-producing. Non-producing reserves include shut-in and behind-pipe reserves. All reserve categories used in this report conform to the definitions approved by the Securities and Exchange Commission (SEC);Regulation S-X,Rule 4-10 (A). These are presented inReserves Definitionssection of this report.

The reserves and income attributable to the various reserve categories included in this report have not been adjusted to reflect the varying degrees of risk associated with them.

ECONOMIC TERMS

Net revenue (sales) is defined as the total proceeds from the sale of oil, condensate, natural gas liquids (NGL), and natural gas before any deductions. Future net income (cashflow) is future net revenue less net lease operating, transportation, processing, and marketing expenses, and state severance or production taxes. No provisions for State or Federal income taxes are made in this evaluation. The present worth (discounted cashflow) at various discount rates is calculated on a monthly basis. ‘Net well costs’ represent the per well lease operating costs and ‘other costs’ include variable operating expenses together with PPC costs on a per unit basis. These costs are listed inTable 2. State and local production and AdValorem taxes are listed inTable 3. All costs and prices were unescalated.

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Division of Schlumberger Technology Corporation

14 September 2006

Page 3

TABLE 2
OPERATING COSTS

				LOE		LOE		PPC
State	Field	Unit	Operator	($/Well/Mo.)		($/MCF)		($/MCF)
Michigan	1500 Antrim	Greenwood 11/12	O.I.L. Energy Corp.		2,000		0.000		0.282
	400 Antrim	Silver	Aurora Energy, Ltd.		850		0.500		1.500
	Alcona	Mt. Mohican	Samson Resources Co.		2,000		0.000		0.520
	Alpena	Beyer	Samson Resources Co.		1,900		0.000		0.520
		Black Bean #1	Samson Resources Co.		1,725		0.000		0.520
		Black Bean #2	Samson Resources Co.		1,250		0.000		0.520
		Black Bean #3	Samson Resources Co.		1,775		0.000		0.520
		Black Bean #4	Samson Resources Co.		1,775		0.000		0.520
		Discard	Samson Resources Co.		1,775		0.000		0.520
		El Dorado	Samson Resources Co.		1,775		0.000		0.520
		Gehrke	Samson Resources Co.		1,200		0.000		0.520
		Green Bean #1	Samson Resources Co.		1,775		0.000		0.520
		Green Bean #2	Samson Resources Co.		1,775		0.000		0.520
		Leeseberg #1	Samson Resources Co.		1,775		0.000		0.520
		Leeseberg #2	Samson Resources Co.		1,775		0.000		0.520
		Mackinaw #1	Samson Resources Co.		1,775		0.000		0.520
		Mackinaw #2	Samson Resources Co.		2,475		0.000		0.520
		Nicholson Hill #1	Samson Resources Co.		1,775		0.000		0.520
		Nicholson Hill #2	Samson Resources Co.		1,775		0.000		0.520
		Nicholson Hill #3	Samson Resources Co.		1,775		0.000		0.520
		Paxton Quarry	Samson Resources Co.		2,125		0.000		0.520
		Seguin	Samson Resources Co.		1,300		0.000		0.520
		Spruce Up	Samson Resources Co.		1,775		0.000		0.520
		Treasure Island	Samson Resources Co.		2,200		0.000		0.520
		Werth While	Samson Resources Co.		1,775		0.000		0.520
	Arrowhead	Arrowhead South	Aurora Energy, Ltd.		850		0.500		0.250
		Blue Chip	Aurora Energy, Ltd.		850		0.500		0.250
		Blue Lakes	Aurora Energy, Ltd.		850		0.500		0.250
		Gaylord Fishing Club	Aurora Energy, Ltd.		850		0.500		0.250
	Black Bear	Black Bear Central	Aurora Energy, Ltd.		850		0.500		1.366
		Black Bear West	Aurora Energy, Ltd.		850		0.500		1.366
	Clear Lake	Clear Lake	Samson Resources Co.		1,775		0.000		0.520
	Dover	Dover	Savoy Energy, LP		6,000		0.000		0.247
	Hudson	Boyne Valley	Aurora Energy, Ltd.		850		0.500		0.936
		Chandler	Aurora Energy, Ltd.		850		0.500		0.936
		Corwith	Aurora Energy, Ltd.		850		0.500		0.936
		Hudson 13	Aurora Energy, Ltd.		850		0.500		0.936
		Hudson 19	Aurora Energy, Ltd.		850		2.110		1.280
		Hudson 34	Aurora Energy, Ltd.		1,600		0.000		0.572
		Hudson NE	Aurora Energy, Ltd.		1,050		0.414		0.623
		Hudson North	Aurora Energy, Ltd.		850		0.500		0.939
		Hudson NW	Aurora Energy, Ltd.		650		0.651		0.939
		Hudson SW	Aurora Energy, Ltd.		1,600		0.000		0.855
		Hudson West	Aurora Energy, Ltd.		700		2.620		1.284
	Warner 36 VII	Warner 36 VII	O.I.L. Energy Corp.		1,650		0.000		0.344

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Data & Consulting Services

Division of Schlumberger Technology Corporation

14 September 2006

Page 4

TABLE 3
TAXES

State Production Tax Rate 6% of Revenue

PRICING AND ECONOMIC PARAMETERS

AURORA supplied all product prices, costs, and economic parameters used in this report. Data from AURORA were accepted as presented. All economics were run to economic life or 40 years which ever occurs first utilizing the gas price deck provided to us by AURORA. Gas prices were held constant through the evaluation life at $5.71/MMBtu

OTHER INCOME (NOT TO BE REPORTED IN SEC FILINGS)

[Intentionally Omitted]

TABLE 4
ESTIMATED NET INCOME FROM PIPELINES & FINANCIAL HEDGES
(NOT FOR INCLUSION IN SEC RESERVE REPORTS)
AURORA OIL & GAS CORPORATION
AS OF JULY 1, 2006

[Table Intentionally Omitted]

OWNERSHIP

The leasehold interests were supplied by AURORA and were accepted as presented. No leasehold purchase costs were included in this evaluation. No attempt was made by the undersigned to verify the title or ownership of the interests evaluated.

GENERAL

All data used in this study were obtained from AURORA, public industry information sources, or the non-confidential files of DCS. A field inspection of the properties was not made in connection with the preparation of this report.

The potential environmental liabilities attendant to ownershipand/or operation of the properties have not been addressed in this report. Abandonment andclean-up costs and possible salvage value of the equipment were not considered in this report.

In evaluating the information at our disposal related to this report, we have excluded from our consideration all matters which require a legal or accounting interpretation, or any interpretation other than those of an engineering or geological nature. In assessing the conclusions expressed in this report pertaining to all aspects of oil and gas evaluations, especially pertaining to reserve evaluations, there are uncertainties inherent in the interpretation of engineering data, and such conclusions represent only informed professional judgments.

Data and worksheets used in the preparation of this evaluation will be maintained in our files in Pittsburgh and will be available for inspection by anyone having proper authorization by AURORA.

This report was prepared solely for the use of the party to whom it is addressed and any disclosure made of this reportand/or the contents by said party thereof shall be solely the responsibility of said party, and shall in no way constitute any representation of any kind whatsoever of the undersigned with respect to the matters being addressed.

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Data & Consulting Services

Division of Schlumberger Technology Corporation

14 September 2006

Page 5

We appreciate the opportunity to perform this evaluation and are available should you need further assistance in this matter.

Sincerely yours,
Jeron R. Williamson Senior Petroleum Engineer	David A. Wozniak, P.E. Senior Petroleum Engineer	Charles M. Boyer II, P.G. Principle Consultant — Group Leader

A-6

SECURITIES AND EXCHANGE COMMISSION
REGULATION S-X,RULE 4-10 (A)

RESERVES DEFINITIONS

Oil and Gas Producing Activities

Such activities include (A) the search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations; (B) the acquisition of property rights or properties for the purpose of further explorationand/or for the purpose of removing the oil or gas from existing reservoirs on those properties; and (C) the construction, drilling and production activities necessary to retrieve oil and gas from its natural reservoirs, and the acquisition, construction, installation, and maintenance of field gathering and storage systems — including lifting the oil and gas to the surface and gathering, treating, field processing (as in the case of processing gas to extract liquid hydrocarbons) and field storage. For purposes of this section, the oil and gas production function shall normally be regarded as terminating at the outlet valve on the lease or field storage tank; if unusual physical or operational circumstances exist, it may be appropriate to regard the production functions as terminating at the first point at which oil, gas, or gas liquids are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal.

Oil and gas producing activities do not include (A) the transporting, refining and marketing of oil and gas; (B) activities relating to the production of natural resources other than oil and gas; (C) the production of geothermal steam or the extraction of hydrocarbons as a by-product of the production of geothermal steam or associated geothermal resources as defined in the Geothermal Steam Act of 1970; and (D) the extraction of hydrocarbons from shale, tar sands, or coal.

The SEC stated in a September 18, 1989 accounting bulletin “since coalbed methane gas can be recovered from coal in its natural state and location, it should be included in proved reserves, provided that it complies in all other respects with the SEC definitions of proved oil and gas reserves including the requirement that methane production be economical at current prices, costs (net of the tax credit) and existing operating conditions.” We have also interpreted this bulletin to include shale gas.

Proved Oil and Gas Reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oiland/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled

A-7

prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved Developed Oil and Gas Reserves

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Undeveloped Reserves

Proved undeveloped oil and gas reserves are 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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

A-8

APPENDIX B

Reserve and Economic Evaluation of
Proved Reserves of Certain
Aurora Oil & Gas Corporation
Indiana Properties
As of July 1, 2006

Unescalated Prices and Costs

Prepared For

Aurora Oil & Gas Corporation

Traverse City, Michigan

Prepared By

Data & Consulting Services

Division of Schlumberger Technology Corporation

Pittsburgh, Pennsylvania

September 2006

B-1

Data & Consulting Services

Division of Schlumberger Technology Corporation

1310 Commerce Drive

Park Ridge One

Pittsburgh, PA15275-1011

Tel: 412-787-5403

Fax: 412-787-2906

6 September 2006

Aurora Oil & Gas Corporation

4110 Copper Ridge Drive

Suite 100

Traverse City, MI 49684

Dear Gentlemen:

At the request of Aurora Oil & Gas Corporation (AURORA), Schlumberger Data & Consulting Services, Division of Schlumberger Technology Corporation (DCS) has prepared a reserve and economic evaluation of certain proved reserves in several New Albany shale projects as of July 1, 2006. These projects were evaluated to a maximum remaining reserve life of 40 years. The economics presented are before federal income taxes (BFIT). The results of this study for the proved reserves are summarized inTable 1.

TABLE 1
ESTIMATED NET RESERVES & INCOME
CERTAIN PROVED OIL & GAS INTERESTS
AURORA OIL & GAS CORPORATION
AS OF JULY 1, 2006

	Proved		Proved				Total
	Developed		Developed		Proved		Proved
	Producing		Non-Producing		Undeveloped		Reserves
Remaining Net Reserves
Gas — MMscf		452.17		204.34		1,265.60		1,922.11
Income Data (M$)
Future Net Revenue		2,577.36		1,164.73		7,213.92		10,956.01
Deductions:
Net Production Taxes		25.77		11.65		72.14		109.56
Net AdValorem Taxes		38.66		17.47		108.21		164.34
Net Investment		0.00		0.00		0.00		0.00
Net Well Costs		429.44		191.04		1,168.26		1,788.74
Other Costs		158.26		71.52		442.96		672.74
Future Net Income (FNI)		1,925.23		873.06		5,422.35		8,220.64
Discounted PV@10% (M$)		862.67		385.86		2,208.44		3,456.97

RESERVE ESTIMATE

Reservoir simulation and history matching of analogous offset projects provide the basis for the production forecasts for the projects. The reservoir simulation was conducted using SHALEGAS^tm, DCS’s multi-phase reservoir simulator designed specifically for evaluating fractured shale formations. We used SHALEGAS^tm to history match the wellhead production data from existing wells as supplied by AURORA in the respective projects or offset projects. Using the resulting reservoir properties and the proposed well spacing for each project, we used SHALEGAS^tm to forecast a typical curve shape from which we could construct a type curve for each project. The

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Data & Consulting Services

Division of Schlumberger Technology Corporation

6 September 2006

Page 2

resultant production forecasts were input into PhdWin to facilitate the generation of the economic valuation. To account for the expected increase of carbon dioxide in the produced gas, shrinkage values (Table 2) as supplied by AURORA were applied to the forecasted wellhead volumes. The estimates of reserves and economic valuation are in theReserve SummariesandReserve Detailssections of this report.

TABLE 2
GAS SHRINKAGE FACTORS

Date	% Shrink
from 07/2006		3.00
from 07/2010		4.00
from 07/2012		5.00
from 07/2014		6.00
from 07/2016		7.00
from 07/2018		8.00
from 07/2020		9.00
from 07/2022		10.00
from 07/2024		11.00
from 07/2006		12.00

Reserve estimates are strictly technical judgments. The accuracy of any reserve estimate is a function of the quality of data available and of the engineering and geological interpretations. The reserve estimates presented in this report are believed reasonable; however, they are estimates only and should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify their revision.

RESERVE CATEGORIES

Reserves were assigned to the proved developed producing (PDP), proved non-producing (PDNP), and proved undeveloped (PUD) reserve categories. Oil and gas reserves by definition fall into one of the following categories: proved, probable, and possible. The proved category is further divided into: developed and undeveloped. The developed reserve category is even further divided into the appropriate reserve status subcategories: producing and non-producing. Non-producing reserves include shut-in and behind-pipe reserves. All reserve categories used in this report conform to the definitions approved by the Securities and Exchange Commission (SEC),Regulation S-X,Rule 4-10 (A). These are presented inReserves Definitionssection of this report.

The reserves and income attributable to the various reserve categories included in this report have not been adjusted to reflect the varying degrees of risk associated with them.

ECONOMIC TERMS

Net revenue (sales) is defined as the total proceeds from the sale of oil, condensate, natural gas liquids (NGL), and natural gas before any deductions. Future net income (cashflow) is future net revenue less net lease operating, transportation, processing, and marketing expenses, and state severance or production taxes. No provisions for State or Federal income taxes are made in this evaluation. The present worth (discounted cashflow) at various discount rates is calculated on a monthly basis. Total annual operating expenses are represented by a fixed per well lease operating cost, “net well cost” and a variable per unit cost, “other cost”.

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Data & Consulting Services

Division of Schlumberger Technology Corporation

6 September 2006

Page 3

PRICING AND ECONOMIC PARAMETERS

AURORA supplied all product prices, costs, and economic parameters used in this report. Data from AURORA were accepted as presented. All economics were run to economic life or 40 years which ever occurs first utilizing the gas price deck provided to us by AURORA. All gas prices are net of any transportation, marketing, and regional basis adjustments. The operating costs, state and local production taxes and gas prices are listed inTables 3,4, and5 respectively. All costs and prices were unescalated.

TABLE 3
OPERATING COSTS

State	Field		Operator		LOE		LOE
					($/Well/Mo.)		($/MCF)
Indiana		Plainville		El Paso		2,000		0.35

TABLE 4
TAXES

State Production Tax Rate	1	%
Ad Valorem Tax Rate	1.5	%

CAPITAL EXPENDITURES

Under pre-existing agreements, AURORA is carried for all capital expenditures associated with the Proved Developed and Undeveloped assets

TABLE 5
GAS PRICE ($/MMbtu)

Escalation	NYMEX
None	5.70

OWNERSHIP

The leasehold interests were supplied by AURORA and were accepted as presented. No leasehold purchase costs were included in this evaluation. No attempt was made by the undersigned to verify the title or ownership of the interests evaluated.

GENERAL

All data used in this study were obtained from AURORA, public industry information sources, or the non-confidential files of DCS. A field inspection of the properties was not made in connection with the preparation of this report.

The potential environmental liabilities attendant to ownershipand/or operation of the properties have not been addressed in this report. Abandonment andclean-up costs and possible salvage value of the equipment were not considered in this report.

In evaluating the information at our disposal related to this report, we have excluded from our consideration all matters which require a legal or accounting interpretation, or any interpretation other than those of an engineering or geological nature. In assessing the conclusions expressed in this report pertaining to all aspects of oil and gas

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Data & Consulting Services

Division of Schlumberger Technology Corporation

6 September 2006

Page 4

evaluations, especially pertaining to reserve evaluations, there are uncertainties inherent in the interpretation of engineering data, and such conclusions represent only informed professional judgments.

Data and worksheets used in the preparation of this evaluation will be maintained in our files in Pittsburgh and will be available for inspection by anyone having proper authorization by AURORA.

This report was prepared solely for the use of the party to whom it is addressed and any disclosure made of this reportand/or the contents by said party thereof shall be solely the responsibility of said party, and shall in no way constitute any representation of any kind whatsoever of the undersigned with respect to the matters being addressed.

We appreciate the opportunity to perform this evaluation and are available should you need further assistance in this matter.

Sincerely yours,

/s/  Jeron R. Williamson
Jeron R. Williamson
Senior Petroleum Engineer
/s/  David A. Wozniak
David A. Wozniak, P.E.
Senior Petroleum Engineer
/s/  Charles M. Boyer II
Charles M. Boyer II, P.G.
Principal Consultant/Group Leader

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SECURITIES AND EXCHANGE COMMISSION
REGULATION S-X,RULE 4-10 (A)

RESERVES DEFINITIONS

Oil and Gas Producing Activities

Such activities include (A) the search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations; (B) the acquisition of property rights or properties for the purpose of further explorationand/or for the purpose of removing the oil or gas from existing reservoirs on those properties; and (C) the construction, drilling and production activities necessary to retrieve oil and gas from its natural reservoirs, and the acquisition, construction, installation, and maintenance of field gathering and storage systems — including lifting the oil and gas to the surface and gathering, treating, field processing (as in the case of processing gas to extract liquid hydrocarbons) and field storage. For purposes of this section, the oil and gas production function shall normally be regarded as terminating at the outlet valve on the lease or field storage tank; if unusual physical or operational circumstances exist, it may be appropriate to regard the production functions as terminating at the first point at which oil, gas, or gas liquids are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal.

Oil and gas producing activities do not include (A) the transporting, refining and marketing of oil and gas; (B) activities relating to the production of natural resources other than oil and gas; (C) the production of geothermal steam or the extraction of hydrocarbons as a by-product of the production of geothermal steam or associated geothermal resources as defined in the Geothermal Steam Act of 1970; and (D) the extraction of hydrocarbons from shale, tar sands, or coal.

The SEC stated in a September 18, 1989 accounting bulletin “since coalbed methane gas can be recovered from coal in its natural state and location, it should be included in proved reserves, provided that it complies in all other respects with the SEC definitions of proved oil and gas reserves including the requirement that methane production be economical at current prices, costs (net of the tax credit) and existing operating conditions.” We have also interpreted this bulletin to include shale gas.

Proved Oil and Gas Reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oiland/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled

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prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved Developed Oil and Gas Reserves

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Undeveloped Reserves

Proved undeveloped oil and gas reserves are 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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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APPENDIX C

January 30, 2006

Cadence Resources Corporation

11211 Katy Freeway; Suite 400

Houston, Texas 77079

Gentlemen:

In accordance with your request, we have appraised the interests owned by Cadence Resources Corporation (Cadence) in certain oil and gas properties. The subject properties are located in the states of Kansas, Louisiana and Texas.

We have prepared estimates of the reserves, future production and the income attributable to the leasehold interests as of December 31, 2005. The income data has been estimated using constant price and cost parameters. The results of our study are summarized as follows:

ESTIMATED NET RESERVES AND INCOME DATA
CERTAIN LEASEHOLD INTERESTS OF
CADENCE RESOURCES CORPORATION
AS OF DECEMBER 31, 2005
USING SEC GUIDELINES

	Net Remaining				Income Data (M$)
	Reserves				Future
	Oil		Gas		Gross				Oper.		Net		FNR
	Mbbls.		Mmcf		Revenue		Taxes		Costs		Revenue		@ 10%
FIELD:
Seifried		18.4		0.0		1025.5		74.9		123.7		826.9		727.1
Bethany Longstreet		0.2		758.8		8247.0		77.7		1586.6		6582.7		4756.8
Markham		0.0		176.2		1236.8		115.6		14.4		1106.7		1018.3
Virgin Reef
Cadence A & B Leases		2.0		0.0		111.6		7.3		38.3		66.0		63.1
Wilbarger Co. Regular
W. Electra Lake Lease		41.4		0.0		2365.0		153.9		503.5		1707.6		1402.4
N. Electra Lake Lease		8.0		0.0		455.0		29.6		199.1		226.3		169.2
Sub Total		49.4		0.0		2820.0		183.5		702.6		1933.9		1571.6
Total		70.0		935.0		13440.9		459.0		2465.6		10516.3		8137.0

Note: Errors in addition are due to rounding.

Oil and condensate volumes are expressed in standard 42 gallon barrels. Gas volumes have been appropriately reduced to sales volumes and are expressed in million cubic feet (MMcf) at the official temperature and pressure measuring bases of the States where the gas reserves are located.

METHOD OF APPRAISAL

The properties have been evaluated on the basis of future net cash flow which is defined as the amount of future net income, which will accrue to the appraised interests by operating the properties to the estimated limit of profitable operation. The future net cash flow has been discounted at an annual effective rate of 10 percent to determine the present worth. The future net cash flow has also been discounted at various other rates, as shown in the schedules. The present worth is shown to indicate the effect of time on the value of money and should not be construed to be the fair market value of the properties.

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RESERVE DEFINITIONS

Reserves — are estimated volumes of crude oil, condensate, natural gas, natural gas liquids and associated substances anticipated to be commercially recoverable from known accumulations from a given date forward, under existing economic conditions, by established operating practices, and under current government regulations. Reserve estimates are based on interpretation of geologicand/or engineering data available at the time of the estimate.

Proved Reserves — are quantities of crude oil, condensate, natural gas and natural gas liquids that can be estimated with reasonable certainty to be recoverable under current economic conditions. Current economic conditions include prices and costs prevailing at the time of the estimate. Reserves are considered proved if commercial producibility of the reservoir is supported by actual production or formation tests. In certain instances proved reserves may be assigned on the basis of electrical and other type logsand/or core analysis that indicate that the subject reservoir is hydrocarbon bearing and is analogous to reservoirs in the same area that are producing, or have demonstrated the ability to produce on a formation test.

The area of a reservoir considered proved includes (1) the area delineated by drilling and defined by fluid contracts, if any and (2) the undrilled areas that can be reasonably judged as commercially productive on the basis of available geological and engineering data. In the absence of data on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limits. Proved reserves do not include volumes of crude oil, condensate, natural gas or natural gas liquids being held in inventory.

CLASSIFICATION OF RESERVES

The reserves considered in this report are defined as proved and were estimated in accordance with the definitions outlined in the Securities and Exchange Commission (SEC) regulations S-XPart 4-10 and Financial Accounting Standards Board Statement No. 69.

PRODUCING STATUS CATEGORIES

Proved Producing Reserves — As used herein, are those reserves that are expected to be produced from completion interval(s) open to production equipment and producing to market.

Proved Non-Producing Reserves — As used herein, are those reserves which are shut in or are behind pipe. Shut in reserves are reserves which are expected to be produced from completion intervals open to production equipment but which have not started producing or were shut in for mechanical, pipeline or market reasons. Behind pipe reserves are reserves which are expected to recovered from zones behind casing in existing wells, which will need to be recompleted prior to the start of production.

Proved Undeveloped Reserves — As used herein, are those reserves that are expected to be recovered from new wells on undrilled acreage or from recompletion of existing wells which require a relatively large expenditure.

RESERVE DETERMINATION

The reserves presented herein have been determined by geological and engineering procedures widely accepted in the industry. In the estimation of these reserves, all available data relating to pressure and production history, geologic and well test information were utilized. Reserves were estimated by performance methods, volumetrically or by analogy to surrounding wells producing from the same productive horizon.

In general most of the properties have been producing for a sufficient length of time to establish a definitive performance trend. Reserves for these properties were determined by extrapolation of the trend into the future. Additionally, consideration has been given to water-oil ratio trends and production characteristics generally exhibited in the area. Where there was insufficient or inadequate performance data, reserve estimates were determined by the volumetric method or by analogy to nearby producing properties.

Actual production history was available through November, 2005. The reserve estimates, at the effective date of the report, should be accepted with the understanding that actual production performance subsequent to the data that production history was available, might require a reserve revision.

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Future production rates may be subject to regulation by various governmental agencies, changes in market demand or other factors; consequently, actual producing rates may differ materially from volumes predicted.

DISCUSSION

Production on the Waggoner Ranch leases are reported on a lease basis. Production from the Cadence A & B lease wells,1-A and 1-B is now comingled at the surface. Production from the nine completions on the W. Electra Lake lease is reported on a total lease basis. Production from the two wells on the N. Electra Lake lease is also reported on a lease basis.

ECONOMIC PARAMETERS

Prices — The oil and gas prices used throughout this report were the actual sales prices received on December 31, 2005. Prices were supplied by Cadence.

Costs — Producing well operating costs utilized were provided on a lease basis or an individual well basis by Cadence. We have used the average of the period from January, 2005 through November, 2005. For newer wells having produced less than six months, the average of the available operating costs was used. Operating costs were held constant over the remaining producing life of the properties. No provision has been made for the value of salvable equipment or the leases at abandonment, nor were costs included to properly plug and abandon the wells. It is considered that these costs are minimal and generally offset each other.

GENERAL

No consideration has been given to Cadence’s corporate overhead, income taxes, depletion, depreciation, or any other indirect costs.

Titles to the appraised properties have not been examined by Ralph E. Davis Associates, Inc., nor has the actual degree or type of interest owned been independently confirmed. The data used in our evaluation were obtained from Cadence, published industry information sourcesand/or the nonconfidential files of Ralph E. Davis Associates, Inc., and were considered to be accurate. A field inspection of the properties was not made.

The reliability of any reserve estimate is a function of the quality of available information and of engineering interpretation and judgement. In our opinion, the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are believed to be reasonable. These reserves should be accepted with the understanding that drilling activity or additional information subsequent to the effective date of this report might require their revision.

In evaluating the information at our disposal concerning this appraisal, we have excluded from our consideration all matters as to which legal or accounting, rather than engineering interpretation may be controlling. Finally, in assessing the conclusions herein expressed, as in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering data and such conclusions necessarily represent only informed professional judgment.

Yours very truly,

RALPH E. DAVIS ASSOCIATES, INC.

/s/  Joseph Mustacchia, Jr.

Joseph Mustacchia, Jr.

Executive Vice President

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Appendix D

ESTIMATE
of
RESERVES AND FUTURE REVENUE
to the
AURORA ENERGY, LTD. INTEREST
in
CERTAIN OIL AND GAS PROPERTIES
located in
MICHIGAN
as of
DECEMBER 31, 2005

BASED ON CONSTANT PRICES AND COSTS
in accordance with
SECURITIES AND EXCHANGE COMMISSION GUIDELINES

D-1

February 2, 2006

Mr. John V. Miller, Jr.

Aurora Energy, Ltd.

4110 Copper Ridge Dr., Suite 100

Traverse City, Michigan 49684

Dear Mr. Miller:

In accordance with your request, we have estimated the proved undeveloped and probable reserves and future revenue, as of December 31, 2005, to the Aurora Energy, Ltd. (Aurora) interest in certain oil and gas properties located in Michigan, as listed in the accompanying tabulations. This report has been prepared using constant prices and costs, as discussed in subsequent paragraphs of this letter. The estimates of proved reserves and future revenue in this report conform to the guidelines of the Securities and Exchange Commission (SEC). However, inasmuch as the SEC does not recognize probable reserves, the sections of this report dealing with such reserves should not be used in filings with the SEC.

As presented in the accompanying summary projections, Tables I and II, we estimate the net reserves and future net revenue to the Aurora interest in these properties, as of December 31, 2005, to be:

	Net Reserves				Future Net Revenue ($)
	Oil		Gas				Present Worth
Category	(Barrels)		(MCF)		Total		at 10%
Proved Undeveloped		28,564		624,072		4,660,900		3,697,500
Probable(1)		79,928		3,086,716		27,202,500		17,987,200

(1) These reserves and future revenue are not risk-weighted.

The oil reserves shown include condensate only. Oil volumes are expressed in barrels that are equivalent to 42 United States gallons. Gas volumes are expressed in thousands of cubic feet (MCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved and probable undeveloped reserves. Our estimates do not include any possible reserves that may exist for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Definitions of all reserve categories are presented immediately following this letter.

As shown in the Table of Contents, for each reserve category this report includes a summary projection of reserves and revenue; one-line summaries of reserves, economics, and basic data by lease; and individual lease projections. Graphs showing gross historical and projected production are presented opposite the individual lease projections.

4500 Thanksgiving Tower • 1601 Elm Street • Dallas, Texas 75201-4754 • Ph: 214-969-5401 • Fax: 214-969-5411 nsai@nsai-petro.com

1221 Lamar Street, Suite 1200 • Houston, Texas 77010-3072 • Ph: 713-654-4950 • Fax: 713-654-4951 netherlandsewell.com

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Future gross revenue to the Aurora interest is prior to deducting state production taxes and ad valorem taxes. Future net revenue is after deductions for these taxes, future capital costs, and operating expenses but before consideration of federal income taxes. In accordance with SEC guidelines, the future net revenue has been discounted at an annual rate of 10 percent to determine its “present worth.” The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. Also, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

Oil prices used in this report are based on a December 31, 2005, West Texas intermediate posted price of $57.75 per barrel and are adjusted by lease for quality and regional price differentials. Gas prices used in this report are based on a December 31, 2005, Henry Hub spot market price of $10.08 per MMBTU and are adjusted for the regional price differential. Since there are currently no sales from these properties, a BTU content of 1,000 BTU per cubic foot of gas was used. All prices are held constant in accordance with SEC guidelines.

Based on our knowledge of similar wells in the area, we estimate lease and well operating costs at $6,000 per completion per month. These costs do not include the per-well overhead expenses allowed under joint operating agreements, nor do they include headquarters general and administrative overhead expenses of Aurora. Lease and well operating costs are held constant in accordance with SEC guidelines. Capital costs are included as required for workovers, new development wells, and production equipment.

The reserves shown in this report are estimates only and should not be construed as exact quantities. The reserves may or may not be recovered; if they are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. All of these reserves are for undeveloped locations; therefore, they are based on estimates of reservoir volumes and recovery efficiencies along with analogies to similar production. Because such reserve estimates are usually subject to greater revision than those based on substantial production and pressure data, it may be necessary to revise these estimates as performance data become available. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report. Also, estimates of reserves may increase or decrease as a result of future operations.

In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geologic. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geologic data; therefore, our conclusions necessarily represent only informed professional judgment.

D-3

The titles to the properties have not been examined by Netherland, Sewell & Associates, Inc., nor has the actual degree or type of interest owned been independently confirmed. The data used in our estimates were obtained from Aurora Energy, Ltd.; other interest owners; public data sources; and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting geologic, field performance, and work data are on file in our office. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties and are not employed on a contingent basis.

Very truly yours,

NETHERLAND, SEWELL & ASSOCIATES, INC.

By: 

Frederic D. Sewell, P.E.

Chairman and Chief Executive Officer

By:  /s/  G. Lance Binder

G. Lance Binder

Executive Vice President

Date Signed: February 2, 2006

GLB:KBD

D-4

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from Securities and Exchange CommissionRegulation S-XRule 4-10(a) and
the 1997 Society of Petroleum Engineers and World Petroleum Council Reserves Definitions

PROVED RESERVES

The following definitions of proved reserves are set forth in Securities and Exchange Commission (SEC)Regulation S-XSection 210.4-10(a). Also included (in italics) are certain subsequent interpretations set forth in the SEC’s Corporate Finance Accounting Interpretations and Guidance [SEC Interpretations]; SEC Staff Accounting Bulletins: Topic 12 [SEC Topic 12]; and the 1997 reserves definitions approved by the Society of Petroleum Engineers and World Petroleum Council [SPE/WPC Definitions].

Proved Oil and Gas Reserves.  Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

The determination of reasonable certainty is generated by supporting geological and engineering data. There must be data available which indicate that assumptions such as decline rates, recovery factors, reservoir limits, recovery mechanisms and volumetric estimates, gas-oil ratios or liquid yield are valid. If the area in question is new to exploration and there is little supporting data for decline rates, recovery factors, reservoir drive mechanisms etc., a conservative approach is appropriate until there is enough supporting data to justify the use of more liberal parameters for the estimation of proved reserves. The concept of reasonable certainty implies that, as more technical data becomes available, a positive, or upward, revision is much more likely thananegative, or downward, revision.

Existing economic and operating conditions are the product prices, operating costs, production methods, recovery techniques, transportation and marketing arrangements, ownershipand/or entitlement terms and regulatory requirements that are extant on the effective date of the estimate. An anticipated change in conditions must have reasonable certainty of occurrence; the corresponding investment and operating expense to make that change must be included in the economic feasibility at the appropriate time. These conditions include estimated net abandonment costs to be incurred and duration of current licenses and permits.

If oil and gas prices are so low that production is actually shut-in because of uneconomic conditions, the reserves attributed to the shut-in properties can no longer be classified as proved and must be subtracted from the proved reserve data base as a negative revision. Those volumes may be included as positive revisions to a subsequent year’s proved reserves only upon their return to economic status. [SEC Interpretations]

Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oiland/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

Proved reserves may be attributed to a prospective zone if a conclusive formation test has been performed or if there is production from the zone at economic rates. It is clear to the SEC staff that wireline recovery of small volumes (e.g. 100 cc) or production of a few hundred barrels per day in remote locations is not necessarily conclusive. Analyses of open-hole well logs which imply that an interval is productive are not sufficient for attribution of proved reserves. If there is an indication of economic producibility by either formation test or production, the reserves in the legal and technically justified drainage area around the well

D-5

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from Securities and Exchange CommissionRegulation S-XRule 4-10(a) and
the 1997 Society of Petroleum Engineers and World Petroleum Council Reserves Definitions

projected down to a known fluid contact or the lowest known hydrocarbons, or LKH may be considered to be proved.

In order to attribute proved reserves to legal locations adjacent to such a well (i.e. offsets), there must be conclusive, unambiguous technical data which supports reasonable certainty of production of such volumes and sufficient legal acreage to economically justify the development without going below the shallower of the fluid contact or the LKH. In the absence of a fluid contact, no offsetting reservoir volume below the LKH from a well penetration shall be classified as proved.

Upon obtaining performance history sufficient to reasonably conclude that more reserves will be recovered than those estimated volumetrically down to LKH, positive reserve revisions should be made. [SEC Interpretations]

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. [SEC Topic 12]

Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

If an improved recovery technique which has not been verified by routine commercial use in the area is to be applied, the hydrocarbon volumes estimated to be recoverable cannot be classified as proved reserves unless the technique has been demonstrated to be technically and economically successful by a pilot project or installed program in that specific rock volume. Such demonstration should validate the feasibility study leading to the project. [SEC Interpretations]

Estimates of proved reserves do not include the following:

(A)  oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B)	crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;
(C)	crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D)  crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Geologic and reservoir characteristic uncertainties such as those relating to permeability, reservoir continuity, sealing nature of faults, structure and other unknown characteristics may prevent reserves from being classified as proved. Economic uncertainties such as the lack of a market (e.g. stranded hydrocarbons), uneconomic prices and marginal reserves that do not show a positive cash flow can also prevent reserves from

D-6

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from Securities and Exchange CommissionRegulation S-XRule 4-10(a) and
the 1997 Society of Petroleum Engineers and World Petroleum Council Reserves Definitions

being classified as proved. Hydrocarbons “manufactured” through extensive treatment of gilsonite, coal and oil shales are mining activities reportable under Industry Guide 7. They cannot be called proved oil and gas reserves. However, coal bed methane gas can be classified as proved reserves if the recovery of such is shown to be economically feasible.

In developing frontier areas, the existence of wells with a formation test or limited production may not be enough to classify those estimated hydrocarbon volumes as proved reserves. Issuers must demonstrate that there is reasonable certainty that a market exists for the hydrocarbons and that an economic method of extracting, treating and transporting them to market exists or is feasible and is likely to exist in the near future. A commitment by the company to develop the necessary production, treatment and transportation infrastructure is essential to the attribution of proved undeveloped reserves. Significant lack of progress on the development of such reserves may be evidence of a lack of such commitment. Affirmation of this commitment may take the form of signed sales contracts for the products; request for proposals to build facilities; signed acceptance of bid proposals; memos of understanding between the appropriate organizations and governments; firm plans and timetables established; approved authorization for expenditures to build facilities; approved loan documents to finance the required infrastructure; initiation of construction of facilities; approved environmental permits etc. Reasonable certainty of procurement of project financing by the company is a requirement for the attribution of proved reserves. An inordinately long delay in the schedule of development may introduce doubt sufficient to preclude the attribution of proved reserves.

The history of issuance and continued recognition of permits, concessions and commerciality agreements by regulatory bodies and governments should be considered when determining whether hydrocarbon accumulations can be classified as proved reserves. Automatic renewal of such agreements cannot be expected if the regulatory body has the authority to end the agreement unless there is a long and clear track record which supports the conclusion that such approvals and renewal are a matter of course. [SEC Interpretations]

Companies should report reserves of natural gas liquids which are net to their leasehold interests, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instructions to Item 3 of Securities Act Industry Guide 2 and report such reserves separately and describe the nature of the ownership. [SEC Topic 12]

Proved Developed Oil and Gas Reserves.  Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or bore hole stimulation treatment would be examples of properties with proved developed reserves since the majority of the expenditures to develop the reserves has already been spent.

Proved developed reserves from improved recovery techniques can be assigned after either the operation of an installed pilot program shows a positive production response to the technique or the project is fully installed and operational and has shown the production response anticipated by earlier feasibility studies. In the case with a pilot, proved developed reserves can be assigned only to that volume attributable to the pilot’s

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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from Securities and Exchange CommissionRegulation S-XRule 4-10(a) and
the 1997 Society of Petroleum Engineers and World Petroleum Council Reserves Definitions

influence. In the case of the fully installed project, response must be seen from the full project before all the proved developed reserves estimated can be assigned. If a project is not following original forecasts, proved developed reserves can only be assigned to the extent actually supported by the current performance. An important point here is that attribution of incremental proved developed reserves from the application of improved recovery techniques requires the installation of facilities and a production increase. [SEC Interpretations]

Proved Developed Producing Reserves.  Reserves subcategorized as producing are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Proved Developed Non-Producing Reserves.  Reserves subcategorized as non-producing include shut-in and behind-pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production. [SPE/WPC Definitions]

Proved Undeveloped Reserves.  Proved undeveloped oil and gas reserves are 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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

The SEC staff points out that this definition contains no mitigating modifier for the word certainty. Also, continuity of production requires more than the technical indication of favorable structure alone (e.g. seismic data) to meet the test for proved undeveloped reserves. Generally, proved undeveloped reserves can be claimed only for legal and technically justified drainage areas offsetting an existing productive well (but structurally no lower than LKH). If there are at least two wells in the same reservoir which are separated by more than one legal location and which show communication (reservoir continuity), proved undeveloped reserves could be claimed between the two wells, even though the location in question might be more than an offset well location away from any of the wells. In this illustration, seismic data could be used to help support this claim by showing reservoir continuity between the wells, but the required data would be the conclusive evidence of communication from production or pressure tests. The SEC staff emphasizes that proved reserves cannot be claimed more than one offset location away from a productive well if there are no other wells in the reservoir, even though seismic data may exist The use of high-quality, well calibrated seismic data can improve reservoir description for performing volumetrics (e.g. fluid contacts). However, seismic data is not an indicator of continuity of production and, therefore, can not be the sole indicator of additional proved reserves beyond the legal and technically justified drainage areas of wells that were drilled. Continuity of production would have to be demonstrated by something other than seismic data.

In a new reservoir with only a few wells, reservoir simulation or application of generalized hydrocarbon recovery correlations would not be consideredareliable method to show increased proved undeveloped

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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from Securities and Exchange CommissionRegulation S-XRule 4-10(a) and
the 1997 Society of Petroleum Engineers and World Petroleum Council Reserves Definitions

reserves. With only a few wells as data points from which to build a geologic model and little performance history to validate the results with an acceptable history match, the results of a simulation or material balance model would be speculative in nature. The results of such a simulation or material balance model would not be considered to be reasonably certain to occur in the field to the extent that additional proved undeveloped reserves could be recognized. The application of recovery correlations which are not specific to the field under consideration is not reliable enough to be the sole source for proved reserve calculations.

Reserves cannot be classified as proved undeveloped reserves based on improved recovery techniques until such time that they have been proved effective in that reservoir or an analogous reservoir in the same geologic formation in the immediate area. An analogous reservoir is one having at least the same values or better for porosity, permeability, permeability distribution, thickness, continuity and hydrocarbon saturations.

(g) Topic 12 of Accounting Series Release No. 257 of the Staff Accounting Bulletins states:

In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test.

If the combination of data from open-hole logs and core analyses is overwhelmingly in support of economic producibility and the indicated reservoir properties are analogous to similar reservoirs in the same field that have produced or demonstrated the ability to produce on a conclusive formation test, the reserves may be classified as proved. This would probably be a rare event especially in an exploratory situation. The essence of the SEC definition is that in most cases there must at least be a conclusive formation test in a new reservoir before any reserves can be considered to be proved. [SEC Interpretations]

PROBABLE AND POSSIBLE RESERVES

Reserves definitions approved by the Society of Petroleum Engineers and World Petroleum Council in 1997 set forth additional classifications for probable and possible reserves. However, inasmuch as the SEC does not recognize probable or possible reserves, the sections of this report dealing with such reserves should not be used in filings with the SEC.

Probable Reserves.  Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable. In this context, when probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves.

In general, probable reserves may include (1) reserves anticipated to be proved by normal step-out drilling where sub-surface control is inadequate to classify these reserves as proved, (2) reserves in formations that appear to be productive based on well log characteristics but lack core data or definitive tests and which are not analogous to producing or proved reservoirs in the area, (3) incremental reserves attributable to infill drilling that could have been classified as proved if closer statutory spacing had been approved at the time of the estimate, (4) reserves attributable to improved recovery methods that have been established by repeated commercially successful applications when (a) a project or pilot is planned but not in operation and (b) rock, fluid, and reservoir characteristics appear favorable for commercial application, (5) reserves in an area of the formation that appears to be separated from the proved area by faulting and the geologic interpretation indicates the subject area is structurally higher than the proved area, (6) reserves attributable to a future workover, treatment, re-treatment,

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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from Securities and Exchange CommissionRegulation S-XRule 4-10(a) and
the 1997 Society of Petroleum Engineers and World Petroleum Council Reserves Definitions

change of equipment, or other mechanical procedures, where such procedure has not been proved successful in wells which exhibit similar behavior in analogous reservoirs, and (7) incremental reserves in proved reservoirs where an alternative interpretation of performance or volumetric data indicates more reserves than can be classified as proved.

Possible Reserves.  Possible reserves are those unproved reserves which analysis of geological and engineering data suggests are less likely to be recoverable than probable reserves. In this context, when probabilistic methods are used, there should be at least a 10% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable plus possible reserves.

In general, possible reserves may include (1) reserves which, based on geological interpretations, could possibly exist beyond areas classified as probable, (2) reserves in formations that appear to be petroleum bearing based on log and core analysis but may not be productive at commercial rates, (3) incremental reserves attributed to infill drilling that are subject to technical uncertainty, (4) reserves attributed to improved recovery methods when (a) a project or pilot is planned but not in operation and (b) rock, fluid, and reservoir characteristics are such that a reasonable doubt exists that the project will be commercial, and (5) reserves in an area of the formation that appears to be separated from the proved area by faulting and geological interpretation indicates the subject area is structurally lower than the proved area.

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APPENDIX E

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 featureand/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.

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.

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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 oiland/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%.

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.

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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 gasand/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.  Data & Consulting Services Division of 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 calculatePV-10. Standardized measure differs fromPV-10 because standardized measure includes the effect of future income taxes.

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.

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3,919,540 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 November 1, 2006.

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 officersand/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.

Under the Underwriting Agreement, the underwriters are obligated, under certain circumstances, to indemnify directors and officers of the registrant against certain liabilities, including liabilities under the Securities Act of 1933, as amended. Reference is made to the form of Underwriting Agreement to be filed as Exhibit 1.1 to this Registration Statement.

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	$	2,500
Fees and expenses of legal counsel	$	2,500
Fees and expenses of engineers	$	1,000
Printing and engraving expenses	$	10,000
Miscellaneous expenses	$	1,000
Total	$	17,000

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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 recentForm 10-KSB, all quarterly and periodic reports filed subsequent to suchForm 10-KSB and our most recent proxy materials.

Between April and June 2002, we sold an aggregate of 1,932,802 units to five accredited investors, each unit consisting of one share of common stock and a warrant to purchase one share of common stock, for aggregate proceeds of $579,840.60. Each warrant was exercisable at a price of $.15 per share and all of the warrants have been exercised. No sales commissions were paid in connection with this transaction. The units were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act. On October 23, 2002, we issued 1,815,316 shares of common stock to four accredited investors upon the cashless exercise of the warrants granted in the April through June 2002 offering. On September 15, 2003, we issued 141,668 shares of common stock to three accredited investors upon the cashless exercise of the warrants granted in the April through June 2002 offering. No sales commissions were paid in connection with the exercise of the warrants. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

Between November 2002 and March 2003, we issued 34,950 shares of Class A Preferred Stock to eight investors who were not U.S. persons under Regulation S of the Securities Act for aggregate sales proceeds of $52,425. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Regulation S of the Securities Act.

During fiscal 2003, Howard M. Crosby made two loans to us. One loan was made in December 2002 in the principal amount of $70,000, bearing interest at 5% and the other loan was made in February 2003 in the principal amount of $50,000 bearing interest at a rate of 8%. We issued 14,000 shares of common stock as an inducement to making the $70,000 loan and 20,000 shares as an inducement to making the $50,000 loan. We repaid $60,000 of the $70,000 loan in cash and issued 4,000 shares of common stock in repayment of the remaining $10,000 principal amount outstanding on the $70,000 loan. We repaid $25,000 of the $50,000 loan in cash and issued 25,000 shares of common stock to repay the remaining $25,000 principal amount outstanding. No sales commissions were paid in connection with these transactions. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

In February 2003, Kevin Stulp, one of our directors, made a bridge loan to us in the principal amount of $50,000, bearing interest of 8% per annum. We issued 20,000 shares of common stock to Mr. Stulp as an inducement to making the loan. On May 28, 2003, we repaid $25,000 of the loan in cash. On September 30, 2004, we issued 25,000 shares of common stock in full payment of the remaining loan principal of $25,000. In July 2003, we issued 100,000 shares of common stock to Mr. Stulp upon the exercise of a warrant at $.75 per share. No sales commissions were paid in connection with these transactions. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On February 4, 2003, we issued an aggregate of 150,000 shares of common stock to four of our officersand/or directors in consideration of services provided. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On February 19, 2003, we issued 5,000 shares of common stock to one sophisticated investor in consideration of certain consulting services provided. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On February 19, 2003, we issued 40,000 shares of common stock to an accredited investor as an inducement for making a loan to us of $100,000. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On February 19, 2003, we issued 6,000 shares of common stock to one sophisticated investor in consideration for a loan of $30,000, which was subsequently repaid.

Between April and May 2003, we issued an aggregate of 44,000 shares of common stock to two sophisticated investors in consideration of certain consulting services provided. No sales commissions were paid in connection

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with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On May 7, 2003, we issued an aggregate of 75,000 shares of common stock to four of our officersand/or directors in consideration of services provided. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On May 7, 2003, we issued 10,000 shares of common stock to one sophisticated investor in consideration of certain consulting services provided. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

Between May and August 2003, we sold an aggregate of 730,000 shares of common stock to 16 accredited investors for aggregate sales proceeds of $710,000. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

In June 2003, Nathan Low loaned $300,000 to Cadence Resources Corporation Limited Partnership, of which we were the sole general partner and Mr. Low was the sole limited partner. As partial inducement for making this loan, we issued Mr. Low 120,000 shares of common stock. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

In July 2003, CGT Management, Ltd. loaned us $300,000 at 10% interest. As an inducement for making the loan, we issued 120,000 shares of common stock to CGT Management. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On July 1, 2003, we issued an aggregate of 95,000 shares of common stock to four of our officersand/or directors in consideration of services provided. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

In August 2003, we issued 102,000 shares of common stock to four sophisticated investors in consideration of certain consulting services provided. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On September 15, 2003, we issued an aggregate of 95,000 shares of common stock to four of our officersand/or directors in consideration of services provided. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

Between September and October 2003, we sold an aggregate of 1,721,400 shares of common stock to 29 accredited investors for aggregate sales proceeds of $4,303,500. Sales commissions consisting of (i) $376,565 in cash, (ii) 11,000 shares of common stock valued at $2.90 per share ($31,900 in the aggregate) and (iii) options to purchase 162,140 shares of common stock at $2.50 per share to one finder or an entity controlled by the finder, and additional fees totaling $11,250 to two other finders. All finders are accredited investors. The shares and options were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On January 23, 2004, we issued 5,000 shares of common stock and an option to purchase 75,000 shares of common stock to each of Glenn DeHekker and Jeffrey M. Christian in consideration of their becoming directors. The shares and options were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On January 23, 2004, we issued an option to purchase 250,000 shares of common stock to Douglas Newby in consideration of his becoming a Vice President. The options were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

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On February 25, 2004, we issued 15,000 shares of common stock to David Nahmias and 15,000 shares of common stock to Lyons Capital, LLC in consideration of services provided. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On April 2, 2004, we sold 120 units, each of which consisted of a note in the principal amount of $50,000 and a warrant to purchase 6,375 shares of common stock exercisable at $4.00 per share, to seven accredited investors for an aggregate sales price of $6,000,000. As compensation for his services in connection with this private placement, we paid Nathan A. Low, an accredited investor, $300,000 and issued him a warrant to purchase 76,500 shares of common stock, exercisable at $4.00 per share. On January 31, 2004, we paid off the notes without a prepayment penalty in exchange for the exercise price of the warrants being reduced to $1.25. The shares and warrant were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On April 15, 2004, we issued 10,000 shares of common stock each to Glenn DeHekker, Jeff Christian, and Kevin Stulp for Director services for two quarters. On the same date, we also issued 5,000 shares of common stock each to Howard Crosby and John Ryan for Director services for one quarter, and 5,000 shares of common stock each to Howard Crosby, John Ryan, and Doug Newby for Officer services for one quarter. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On June 2, 2004, we issued 6,000 shares of common stock to Proteus Capital Corp. in consideration of services rendered to us. On the same date, we issued 10,000 shares of common stock to Robert Denison upon exercise of warrants at $1.35. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On August 20, 2004 we issued 25,000 shares of common stock to Howard Schraub and 17,500 shares of common stock to Lyons Capital LLC for professional services rendered. On the same date, we issued 5,000 shares of common stock to Glenn DeHekker, Kevin Stulp and Jeff Christian for quarterly services as Directors and issued 5,000 shares of common stock to Douglas Newby for quarterly services as an Officer. Also on the same date, we issued 15,000 shares of common stock to RMB International (Dublin), Limited as abreak-up fee for a proposed debt financing. In each case the shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On January 31, 2005, we issued 7,810,000 shares of common stock and warrants to purchase 14,050,000 shares of common stock at an exercise price of $1.75 per share to 22 accredited investors for aggregate sales proceeds of $9,762,500. Sunrise Securities Corporation, an affiliate of Nathan Low (a shareholder of Cadence), received a cash commission equal to $976,250 and a warrant to purchase 1,821,000 shares of common stock at an exercise price of $1.75 per share for services rendered as the placement agent in the transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On September 30, 2005, we issued options to purchase 50,000 shares of our common stock to each of the five members of our board of directors (i.e., options to purchase an aggregate of 250,000 shares). These options are exercisable for $1.42 per share. The options were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On October 31, 2005, we issued warrants to purchase 37,500 shares of our common stock to each of three individuals (i.e., warrants to purchase an aggregate of 112,500 shares) upon the individuals’ resignations from our Board of Directors. Of the warrants issued to each such individual, warrants to purchase 12,500 shares (or an aggregate of 37,500 for all three individuals) were exercisable for $2.23 a share, warrants to purchase 12,500 shares (or an aggregate of 37,500 for all three individuals) were exercisable for $2.53 a share and warrants to purchase 12,500 shares (or an aggregate of 37,500 for all three individuals) were exercisable for $3.28 a share. The warrants were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

From October through mid December, 2005, we issued 355,000 shares of common stock upon exercise of outstanding warrants for cash, and 245,068 shares of common stock upon cashless exercise of outstanding options and warrants held by previous directors of the Company. All of these shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended.

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-monthlock-up

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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 theS-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.

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 closed on the acquisition of certain assets for which we paid some cash and issued 1,378,299 shares of common stock. These shares are unregistered, restricted stock, and were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended.

ITEM 27.  EXHIBITS

INDEX OF EXHIBITS

3	.1(1)	Restated Articles of Incorporation of Aurora Oil & Gas Corporation.
3	.2(1)	Bylaws of Aurora Oil & Gas Corporation.
4	.1	Articles of Amendment to Articles of Incorporation, relating to the Class A Preferred Stock. (Filed as Exhibit 4 to ourForm 10-KSB for the fiscal year ended September 30, 2003, filed with the SEC on January 13, 2004, 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 onForm 8-K filed with the SEC on April 5, 2004, and incorporated herein by reference.)
10	.2	Agreement and Plan of Merger dated as of January 31, 2005 between Cadence Resources Corporation, Aurora Acquisition Corp. and Aurora Energy, Ltd. (Filed as Exhibit 10.3 to ourForm S-4 Registration Statement filed with the SEC on May 13, 2005, and incorporated herein by reference.)
10	.3(2)	Asset Purchase Agreement with Nor Am Energy, L.L.C., Provins Family, L.L.C. and O.I.L. Energy Corp. dated January 10, 2006.
10	.4	Note Purchase Agreement between Aurora Antrim North, LLC et al. and TCW Asset Management Company, dated August 12, 2004 (filed as an Exhibit to the Registrant’s Form S-4 registration statement filed with the SEC on May 13, 2005, and incorporated herein by reference.)
10	.5	First Amended and Restated Note Purchase Agreement between Aurora Antrim North, LLC et al. and TCW Asset Management Company, dated December 8, 2005 (filed as an Exhibit to the Registrant’s Annual Report on Form 10-KSB for the fiscal year ended September 30, 2005 filed with the SEC on December 29, 2005 and incorporated herein by reference.)
10	.6(2)	First Amendment to First Amended and Restated Note Purchase Agreement between Aurora Antrim North, L.L.C., et al., and TCW Asset Management Company, dated January 31, 2006.
10	.7(2)	Credit Agreement among Aurora Antrim North, L.L.C., et al. and BNP Paribas, et al., dated January 31, 2006.
10	.8(2)	Intercreditor and Subordination Agreement among BNP Paribas, et al., TCW Asset Management Company, and Aurora Antrim North, L.L.C., dated January 31, 2006.
10	.9(2)	Promissory Note from Aurora Energy, Ltd. to Northwestern Bank dated January 31, 2006.

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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 ourForm S-8 Registration Statement filed with the SEC on May 15, 2006 and incorporated herein by reference.)
10	.12(1)	Employment Agreement with Ronald E. Huff dated June 19, 2006.
10	.13	Letter Agreement with Bach Enterprises dated July 10, 2006. This Agreement is confidential, has been omitted from this filing, and has been filed separately with the SEC.
10	.14(1)	First Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated July 14, 2006.
10	.15(1)	The Denthorn Trust Commercial Guaranty of obligations to Northwestern Bank.
10	.16(1)	William W. Deneau Commercial Guaranty of obligations to Northwestern Bank.
10	.17(1)	The Denthorn Trust Commercial Pledge Agreement to Northwestern Bank.
10	.18(5)	LLC Membership Interest Purchase Agreement dated October 6, 2006 relating to Kingsley Development Company, L.L.C.
10	.19(5)	Asset Purchase Agreement with Bach Enterprises, Inc., et al., dated October 6, 2006.
10	.20(5)	Promissory Note from Aurora Energy, Ltd. to Northwestern Bank dated October 15, 2006.
10	.21(5)	Form of Indemnification letter agreement between Aurora Oil & Gas Corporation and Rubicon Master Fund.
10	.22(5)	Patricia A. Deneau Trust Commercial Guaranty of obligations to Northwestern Bank.
10	.23(5)	Patricia A. Deneau Trust Commercial Pledge Agreement to Northwestern Bank.
15		Awareness letter from Rachlin Cohen & Holtz LLP.
21	(5)	Subsidiaries of Aurora Oil & Gas Corporation.
23	.1(6)	Consent of Ralph E. Davis Associates, Inc.
23	.2(6)	Consent of Schlumberger Technology Corporation.
23	.3(6)	Consent of Netherland, Sewell & Associates, Inc.
23	.4	Consent of Rachlin Cohen & Holtz LLP.
23	.5	Consent of Fraser Trebilcock Davis & Dunlap, P.C. (included in Exhibit 5.1).

(1)	Filed as an exhibit to ourForm 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 ourForm 10-KSB for the fiscal year ended December 31, 2005, filed with the SEC on March 31, 2006 and incorporated herein by reference.
(3)	Filed on September 8, 2006 with our Form SB-2 registration statement filing, registration no. 333-137176.
(4)	Filed on October 18, 2006 with our Amendment No. 1 to Form SB-2 registration statement filing, registration no. 333-137176.
(5)	Filed on October 27, 2006 with our Amendment No. 3 to Form SB-2 registration statement filing, registration no. 333-137176.

(6) Filed on November 3, 2006 with our post effective amendment no. 3 to this registration statement.

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

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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.

The small business issuer will:

(1) File, during any period in which it offers or sells securities, a post-effective amendment to this registration statement to:

(i) Include any prospectus required by section 10(a)(3) of the Securities Act;

(ii) Reflect in the prospectus any facts or events which, individually or together, represent a fundamental change in the information in the registration statement; and notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in the volume and price represent no more than a 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement.

(iii) Include any additional or changed material information on the plan of distribution.

(2) For determining liability under the Securities Act, treat each post-effective amendment as a new registration statement of the securities offered, and the offering of the securities at that time to be the initial bona fide offering.

(3) File a post-effective amendment to remove from registration any of the securities that remain unsold at the end of the offering.

(4) For determining liability of the undersigned small business issuer under the Securities Act to any purchaser in the initial distribution of the securities, the undersigned small business issuer undertakes that in a primary offering of securities of the undersigned small business issuer pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned small business issuer will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(i) Any preliminary prospectus or prospectus of the undersigned small business issuer relating to the offering required to be filed pursuant to Rule 424;

(ii) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned small business issuer or used or referred to by the undersigned small business issuer;

(iii) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned small business issuer or its securities provided by or on behalf of the undersigned small business issuer; and

(iv) Any other communication that is an offer in the offering made by the undersigned small business issuer to the purchaser.

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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 onForm SB-2 and authorized this Post Effective AmendedForm SB-2 Registration Statement to be signed on its behalf by the undersigned, in the city of Traverse City, State of Michigan, on this 13^th day of November, 2006.

AURORA OIL & GAS CORPORATION

By:  /s/  William W. Deneau

William W. Deneau, President and Chairman

Pursuant to the requirements of the Securities Act of 1933, this AmendedForm 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	President, Chairman and Director (Principal Executive Officer)	November 13, 2006
/s/  Ronald E. Huff Ronald E. Huff	Chief Financial Officer and Director (Principal Financial Officer and Principal Accounting Officer)	November 13, 2006
/s/  Kevin D. Stulp Kevin D. Stulp	Director	November 13, 2006
/s/  Richard M. Deneau Richard M. Deneau	Director	November 13, 2006
/s/  Gary J. Myles Gary J. Myles	Director	November 13, 2006
/s/  Earl V. Young Earl V. Young	Director	November 13, 2006

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INDEX OF EXHIBITS

3	.1(1)	Restated Articles of Incorporation of Aurora Oil & Gas Corporation.
3	.2(1)	Bylaws of Aurora Oil & Gas Corporation.
4	.1	Articles of Amendment to Articles of Incorporation, relating to the Class A Preferred Stock. (Filed as Exhibit 4 to ourForm 10-KSB for the fiscal year ended September 30, 2003, filed with the SEC on January 13, 2004, 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 onForm 8-K filed with the SEC on April 5, 2004, and incorporated herein by reference.)
10	.2	Agreement and Plan of Merger dated as of January 31, 2005 between Cadence Resources Corporation, Aurora Acquisition Corp. and Aurora Energy, Ltd. (Filed as Exhibit 10.3 to ourForm S-4 Registration Statement filed with the SEC on May 13, 2005, and incorporated herein by reference.)
10	.3(2)	Asset Purchase Agreement with Nor Am Energy, L.L.C., Provins Family, L.L.C. and O.I.L. Energy Corp. dated January 10, 2006.
10	.4	Note Purchase Agreement between Aurora Antrim North, LLC et al. and TCW Asset Management Company, dated August 12, 2004 (filed as an Exhibit to the Registrant’s Form S-4 registration statement filed with the SEC on May 13, 2005, and incorporated herein by reference.)
10	.5	First Amended and Restated Note Purchase Agreement between Aurora Antrim North, LLC et al. and TCW Asset Management Company, dated December 8, 2005 (filed as an Exhibit to the Registrant’s Annual Report on Form 10-KSB for the fiscal year ended September 30, 2005 filed with the SEC on December 29, 2005 and incorporated herein by reference.)
10	.6(2)	First Amendment to First Amended and Restated Note Purchase Agreement between Aurora Antrim North, L.L.C., et al., and TCW Asset Management Company, dated January 31, 2006.
10	.7(2)	Credit Agreement among Aurora Antrim North, L.L.C., et al. and BNP Paribas, et al., dated January 31, 2006.
10	.8(2)	Intercreditor and Subordination Agreement among BNP Paribas, et al., TCW Asset Management Company, and Aurora Antrim North, L.L.C., dated January 31, 2006.
10	.9(2)	Promissory Note from Aurora Energy, Ltd. to Northwestern Bank dated January 31, 2006.
10	.10(2)	Confirmation from BNP Paribas to Aurora Antrim North, L.L.C., dated February 22, 2006 relating to gas sale commitment.
10	.11	2006 Stock Incentive Plan. (Filed as Exhibit 99.1 to ourForm S-8 Registration Statement filed with the SEC on May 15, 2006, and incorporated herein by reference.)
10	.12(1)	Employment Agreement with Ronald E. Huff dated June 19, 2006.
10	.13	Letter Agreement with Bach Enterprises dated July 10, 2006. This Agreement is confidential, has been omitted from this filing, and has been filed separately with the SEC.
10	.14(1)	First Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated July 14, 2006.
10	.15(1)	The Denthorn Trust Commercial Guaranty of obligations to Northwestern Bank.
10	.16(1)	William W. Deneau Commercial Guaranty of obligations to Northwestern Bank.
10	.17(1)	The Denthorn Trust Commercial Pledge Agreement to Northwestern Bank.
10	.18(5)	LLC Membership Interest Purchase Agreement dated October 6, 2006 relating to Kingsley Development Company, L.L.C.
10	.19(5)	Asset Purchase Agreement with Bach Enterprises, Inc., et al, dated October 6, 2006.
10	.20(5)	Promissory Note from Aurora Energy, Ltd. to Northwestern Bank dated October 15, 2006.
10	.21(5)	Form of Indemnification letter agreement between Aurora Oil & Gas Corporation and Rubicon Master Fund.
10	.22(5)	Patricia A. Deneau Trust Commercial Guaranty of obligations to Northwestern Bank.
10	.23(5)	Patricia A. Deneau Trust Commercial Pledge Agreement to Northwestern Bank.
15		Awareness letter from Rachlin Cohen & Holtz LLP.
21	(5)	Subsidiaries of Aurora Oil & Gas Corporation.

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23	.1(6)	Consent of Ralph E. Davis Associates, Inc.
23	.2(6)	Consent of Schlumberger Technology Corporation.
23	.3(6)	Consent of Netherland, Sewell & Associates, Inc.
23	.4	Consent of Rachlin Cohen & Holtz LLP.
23	.5	Consent of Fraser Trebilcock Davis & Dunlap, P.C. (included in Exhibit 5.1).

(1)	Filed as an exhibit to ourForm 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 ourForm 10-KSB for the fiscal year ended December 31, 2005, filed with the SEC on March 31, 2006, and incorporated herein by reference.
(3)	Filed on September 8, 2006 with our Form SB-2 registration statement filing, registrationno. 333-137176.
(4)	Filed on October 18, 2006 with our Amendment No. 1 to Form SB-2 registration statement filing, registrationno. 333-137176.
(5)	Filed on October 27, 2006 with our Amendment No. 3 to Form SB-2 registration statement filing, registrationno. 333-137176.

(6) Filed on November 3, 2006 with our post effective amendment no. 3 to this registration statement.

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