e424b4

Rule 424(b)(4)

Registration Statement No. 333-137176

24,000,000 Shares

Common Stock

We are selling 16,000,000 shares and one of our principal shareholders is selling 8,000,000 shares. See “Principal and Selling Shareholders” on page 56.

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.


							Proceeds to
	Public		Underwriting		Proceeds to Company		Selling Shareholder
	Offering Price		Discount		(Before Expenses)		(Before Expenses)

Per Share	$	3.00	$	0.18	$	2.82	$	2.82
Total	$	72,000,000	$	4,320,000	$	45,120,000	$	22,560,000

The underwriters may also purchase up to an additional 3,600,000 shares from the Company at the public offering price, less the underwriting discount, within 30 days of the date of this prospectus to cover any over-allotments.

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.

Delivery of the shares of common stock will be made on or about November 7, 2006.

Johnson Rice & Company L.L.C.


KeyBanc Capital Markets		Morgan Keegan & Company, Inc.

The date of this prospectus is November 1, 2006.

TABLE OF CONTENTS


PROSPECTUS SUMMARY			1
RISK FACTORS			10
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			21
USE OF PROCEEDS			22
CAPITALIZATION			23
PRICE RANGE OF COMMON STOCK			24
SELECTED HISTORICAL FINANCIAL DATA			25
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			27
BUSINESS			40
MANAGEMENT			50
EXECUTIVE COMPENSATION			52
PRINCIPAL AND SELLING SHAREHOLDERS			56
RELATED PARTY TRANSACTIONS			58
DESCRIPTION OF COMMON STOCK			60
UNDERWRITING			64
LEGAL MATTERS			66
EXPERTS			66
WHERE YOU CAN FIND MORE INFORMATION			66
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

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 the 18-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

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 this offering combined 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

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.

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;


	•	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.

Selling Shareholder

Rubicon Master Fund (referred to as Rubicon or the Selling Shareholder) will sell 8 million shares of our common stock in the offering. Rubicon currently owns 11.75 million shares of our common stock. After this offering, Rubicon will own 3.75 million shares of our common stock, which will represent approximately 4% of our outstanding shares based upon 99,462,966 shares of common stock to be outstanding immediately after completion of this offering. The shares retained by the Selling Shareholder after completion of this offering will be subject to lock-up for a period of 90 days after the date of this prospectus.

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.

The Offering


Common stock offered by us		16,000,000 shares


Common stock offered by selling shareholder		8,000,000


Common stock to be outstanding immediately after completion of this offering		99,462,966 shares


Over-allotment option granted by us		3,600,000 shares


Use of proceeds		We intend to use the proceeds of this offering to fund exploration and development activities and for other general corporate purposes, including acquisitions. Pending such use, we intend to use the proceeds to repay borrowings under our senior credit facility. See “Use of Proceeds.” We will not receive any proceeds from the sale of shares by the Selling Shareholder.


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:


	•	assumes the underwriters do not exercise their over-allotment option;

	•	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.

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


	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


	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 of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of PV-10 to the most directly comparable GAAP measure — standardized measure of discounted future net cash flows — in the following table:


	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 calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes. As noted in footnote (a) above, 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.

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 this offering 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.

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.

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


		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

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

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.

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

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

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

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

We are subject to complex federal, state and local laws and regulations that 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

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 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 October 10, 2006, 83,462,966 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 three shelf registration statements that are currently effective, which together have registered almost 40 million shares of common stock for resale. The sale of a large number of shares of our common stock pursuant to the resale registration statements, the perception that any such sale might occur, or the issuance of a large number of shares of our common stock in connection with future acquisitions, equity financings or otherwise, could cause the market price of our common stock to decline significantly. After the completion of this offering, we will have approximately 99.5 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 an S-8 registration statement, and the balance are or will be eligible for sale under Rule 144 after the expiration of the 90-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 will be subject to lock-up for a period of 90 days after the date of this prospectus. All of the shares of common stock sold in this offering will be freely tradable without restriction or further registration under the Securities Act of 1933, as amended (the “Securities Act”), by persons other than our “affiliates” (within the meaning of Rule 144 under the Securities Act) immediately upon completion of this offering. Additionally, we have filed an S-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.

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.

USE OF PROCEEDS

We estimate that the net proceeds that we will receive from this offering of 16 million shares will be approximately $44.5 million or approximately $54.7 million if the underwriters’ over-allotment option is exercised in full, in each case after deducting underwriting discounts and the estimated offering expenses, based on the public offering price of $3.00 per share.

We expect to use the net proceeds primarily to fund our exploration and development activities and for other general corporate purposes including acquisitions. Pending such use, we intend to use the net proceeds from this offering to repay the current borrowings under our senior credit facility.

We expect to then re-borrow amounts under our senior credit facility when capital or other expenditures exceed our cash flow from operations in periods subsequent to this offering.

As of June 30, 2006, interest on borrowings under our senior credit facility had a weighted average interest rate of 7.02%. The senior credit facility matures on the earlier of January 31, 2010 or 91 days prior to the maturity of the mezzanine credit facility. Interest under our senior credit facility accrues at a rate calculated by reference to LIBOR plus 1.25% to 2.0%. The outstanding balance on our senior credit facility at October 13, 2006 was $50 million against a borrowing base of $50 million.

We will not receive any proceeds from the sale of shares by the Selling Shareholder.

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 16 million shares offered hereby, based on the 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		$	8,134


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; 97,965,017 issued and outstanding as adjusted		820			980
Additional paid-in capital		77,757			122,136
Accumulated other comprehensive income		962			962
Accumulated deficit		(4,614	)		(4,614	)

Total shareholders’ equity		74,925			119,464

Total capitalization	$	157,795		$	162,334

PRICE RANGE OF COMMON STOCK

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


	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.

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.

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


	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.

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.

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


	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.

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

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.

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

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

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.

The Antrim shale gas adsorbs to organic material in a manner similar to gas in coal seams. Water in the natural fractures of the shale provides a trapping mechanism to hold the gas in place. As the water is produced, lowering the fluid and pressure in the reservoir, gases are released from the organic material and are produced to the surface. At depths of less than 1,500 feet, the gas-in-place is typically 90% methane or greater, with the balance being 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 the 18-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.

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 the 18-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 to 12-inch polypipe.

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

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

Oil and natural gas reserves

The following table presents information as of 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,


		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 of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of PV-10 to the most directly comparable GAAP measure — standardized measure of discounted future net cash flow — in the following table:

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

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 a 12-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

prospective properties and our limited number of employees. Gathering systems are the only practical method for the intermediate transportation of natural gas. Therefore, competition for natural gas delivery is presented by other pipelines and gas gathering systems. Competition is also presented by alternative fuel sources, including heating oil and other fossil fuels. Renewable energy sources may become more competitive in the future.

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

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.

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.

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. Deneau has 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. Miller has 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.

Thomas W. Tucker has 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. Stulp has 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. Deneau has served on our Board of Directors since November 21, 2005. Mr. Deneau served as a Director and President of Anchor Glass Container corporation (“Anchor”) from 1997 until his retirement in 2004. He was also the Chief Operating Officer of Anchor from 1997 to 2002, and the Chief Executive Officer of Anchor from 2002 until his retirement. Anchor, which was publicly traded and listed on NASDAQ, 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. Myles has served on our Board of Directors since November 21, 2005. From June 1997 to the present, Mr. Myles has also served as a Director of Aurora. He is currently retired from his primary employment. Prior to his retirement, Mr. Myles served as Vice President and Consumer Loan Manager for Fifth Third Bank of Northern Michigan (previously Old Kent Mortgage Company), a wholly owned subsidiary of Fifth Third Bank (previously Old Kent Financial Corporation). As the Affiliate Consumer Loan Manager, Mr. Myles was based in Traverse City, Michigan, and had full bottom line responsibility for the mortgage and indirect consumer loan departments generating net revenue of $3,500,000 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. Young has served on our Board of Directors since November 21, 2005. From March 2001 to the present, Mr. Young has also served as a Director of Aurora. He is currently President of Earl Young & Associates of Dallas, Texas, which he founded in 1999. Mr. Young is also a Director and chair of the Audit Committee for Diamond Fields International, a Canadian company that is listed on the Toronto Stock Exchange and is a producer of offshore diamonds in Nambia with exploration activity in Sierra Leone and Liberia. Mr. Young is a Director of Madagascar Resources, an Australian public company that is engaged in 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.

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.

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 the Form 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 a Form 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)

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.

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 a Form 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 for out-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.

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.

PRINCIPAL AND SELLING SHAREHOLDERS

Principal shareholders

The following table sets forth, as of October 10, 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

Rubicon Master Fund(c)		11,750,000			14	%
c/o Rubicon Fund Management LLP
P103 Mount Street
London W1K 2TJ, UK
FMR Corp.(d)		9,836,246			12	%
82 Devonshire Street
Boston, Massachusetts 02109
Nathan A. Low Roth IRA and affiliates		7,657,766	(e)		9	%
641 Lexington Avenue
New York, New York 10022
Crestview Capital Master, LLC		5,542,320			7	%
95 Revere Drive, Suite A
Northbrook, Illinois, 60062
William W. Deneau		4,232,500	(f)		5	%
Thomas W. Tucker		3,888,194	(g)		5	%
John V. Miller, Jr.		3,308,262	(h)		4	%
Kevin D. Stulp		527,500	(i)		*
Earl V. Young		416,204	(j)		*
Gary J. Myles		308,798	(k)		*
Richard M. Deneau(l)		—			—
Ronald E. Huff(m)		—			—
All executive officers and directors as a group (8 persons)		12,681,458	(n)		15	%


*		Less than 1%


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

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

(c)		Based on Schedule 13G/A and Form 4 filed with the SEC on August 8, 2006, pursuant to investment agreements, each of Rubicon Fund Management Ltd., a company organized under the laws of the Cayman Islands, which we refer to in this footnote as Rubicon Fund Management Ltd., and Rubicon Fund Management LLP, a limited liability partnership organized under the laws of the United Kingdom, which we refer to in this footnote as Rubicon Fund Management LLP, Mr. Paul Anthony Brewer, Mr. Jeffrey Eugene Brummette, Mr. William Francis Callanan, Mr. Vilas Gadkari, and Mr. Horace Joseph Leitch III, share all investment and voting power with respect to the securities held by Rubicon Master Fund. Mr. Brewer, Mr. Brummette, Mr. Callanan, Mr. Gadkari, and Mr. Leitch control both Rubicon Fund Management Ltd. and Rubicon Fund


		Management LLP. Each of Rubicon Fund Management Ltd., Rubicon Fund Management LLP, Mr. Brewer, Mr. Brummette, Mr. Callanan, Mr. Gadkari, and Mr. Leitch disclaim beneficial ownership of these securities.

(d)		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.

(e)		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.

(f)		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.

(g)		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.

(h)		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.

(i)		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.

(j)		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.

(k)		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.

(l)		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.

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

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

Selling shareholder

Rubicon Master Fund will sell 8,000,000 shares of our common stock in this offering. Rubicon currently owns 11,750,000 shares of our common stock. After this offering, Rubicon will own 3,750,000 shares of our common stock, which will represent approximately 4% of our outstanding shares based upon 99,462,966 shares of common stock to be outstanding immediately after completion of this offering. The shares retained by Rubicon after this offering will be subject to lock-up for a period of 90 days after the date of this prospectus.

Neither Rubicon Master Fund nor any of its affiliates named above have now, or have within the past three years had, any position, office or other material relationship with us or any of our predecessors or affiliates, other than as a shareholder.

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.

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.

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.

DESCRIPTION OF COMMON STOCK

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 October 10, 2006, we had 83,462,966 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.

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.

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,

Plans (Excluding Securities in

Plan Category

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 officers and/or directors not pursuant to a formal plan.

Shares Eligible For Future Sale

Our shares of common stock that are eligible for future sale may have an adverse effect on the price of our stock. At October 10, 2006, we had 83,462,966 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 to lock-up and may not be sold through October 31, 2008.

We have three shelf registration statements that are currently effective, which together 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 October 10, 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.

Upon completion of this offering, we will have outstanding an aggregate of 99,462,966 shares of common stock, assuming no exercise of the underwriters’ over-allotment option and no exercise of outstanding options and warrants. All of the shares sold in this offering will be freely tradable without restriction or further registration under the Securities Act except for shares, if any, which may be acquired by our “affiliates” as that term is defined in Rule 144 under the Securities Act. Persons who may be deemed to be affiliates generally include individuals or entities that control, are controlled by, or are under common control with, us and may include our directors and officers as well as our significant shareholders.

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


	•	1% of the number of shares of our common stock then outstanding, which will equal approximately 994,629 shares immediately after this offering; and


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

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.

UNDERWRITING

We and the Selling Shareholder have entered into an underwriting agreement with the underwriters named below with respect to the shares being offered. Subject to the terms and conditions of the underwriting agreement, we and the Selling Shareholder have agreed to sell to the underwriters, and each underwriter has agreed to purchase from us and the Selling Shareholder the number of shares of common stock listed next to its name in the following table:


Name	Number of Shares

Johnson Rice & Company L.L.C.		12,000,000
KeyBanc Capital Markets, a Division of McDonald Investments Inc.		6,000,000
Morgan Keegan & Company, Inc.		6,000,000

Total		24,000,000

The underwriting agreement provides that the underwriters’ obligation to purchase shares of our common stock depend on the satisfaction of the conditions contained in the underwriting agreement. The conditions contained in the underwriting agreement include the condition that the representations and warranties made by us to the underwriters are true, that there has been no material adverse change to our condition or in the financial markets and that we deliver to the underwriters customary closing documents. The underwriters are obligated to purchase all of the shares of common stock (other than those covered by the over-allotment option described below) if they purchase any of the shares.

The underwriters propose to offer the shares of common stock to the public at the public offering price set forth on the cover of this prospectus. The underwriters may offer the common stock to securities dealers at the price to the public less a concession not in excess of $0.11 per share. After the shares of common stock are released for sale to the public, the underwriters may vary the offering price and other selling terms from time to time.

We have granted to the underwriters an option, exercisable for 30 days from the date of the underwriting agreement, to purchase up to 3,600,000 additional shares at the public offering price per share less the underwriting discounts and commissions shown on the cover page of this prospectus. The underwriters may exercise this option solely to cover over-allotments, if any, made in connection with this offering.

The following table summarizes the compensation to be paid to the underwriters by us, assuming the underwriters’ option is fully exercised, in connection with this offering.


			Total
			Without		With
	Per Share		Over-Allotment		Over-Allotment

Public offering price by us	$	3.00	$	48,000,000	$	58,800,000
Underwriting fees to be paid by us	$	0.18	$	2,880,000	$	3,528,000
Proceeds, before expenses, to us	$	2.82	$	45,120,000	$	55,272,000

We estimate our expenses associated with the offering, excluding underwriting discounts and commissions, will be approximately $580,632, all of which will be paid by us.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the federal securities laws, or to contribute to payments that may be required to be made in respect of these liabilities.

The following table summarizes the compensation to be paid to the underwriters by the Selling Shareholder in connection with this offering.


			Total
			Without		With
	Per Share		Over-Allotment		Over-Allotment

Public offering price by the Selling Shareholder	$	3.00	$	24,000,000	$	24,000,000
Underwriting fees to be paid by the Selling Shareholder	$	0.18	$	1,440,000	$	1,440,000
Proceeds to the Selling Shareholder before expenses	$	2.82	$	22,560,000	$	22,560,000

The Selling Shareholder has delivered certain information for inclusion in this prospectus to us and the underwriters. The Selling Shareholder has agreed to indemnify the underwriters for certain liabilities that arise out of or are based upon any untrue statement or alleged untrue statement of a material fact contained in this prospectus, the registration statement of which it is a part, any preliminary prospectus, the “time of sale prospectus” or any amendment or supplement to any of the foregoing, or the omission or alleged omission from any such document of a material fact required to be stated therein or necessary to make the statements therein not misleading, to the extent but only to the extent arising out of or based upon any such untrue statement or omission or alleged untrue statement or omission made in reliance upon and in conformity with such information relating to the Selling Shareholder furnished to us in writing by the Selling Shareholder expressly for use therein.

We, our officers and directors, and the Selling Shareholder (with respect to the shares not offered by it in this prospectus) have agreed that, for a period of 90 days from the date of this prospectus, we and they will not, without the prior written consent of Johnson Rice & Company L.L.C., directly or indirectly, offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, or otherwise transfer or dispose of any share of common stock or any securities convertible into or exercisable or exchangeable for common stock, or file any registration statement under the Securities Act of 1933 with respect to any of the foregoing or enter into any swap or any other agreement or transaction that transfers, in whole or in part, directly or indirectly, the economic consequence of ownership of the common stock, except for the sale to the underwriters in this offering, the issuance by us of any securities or options to purchase common stock under existing, amended or new employee benefit plans maintained by us and the filing of or amendment to any registration statement related to the foregoing, the issuance by us of securities in exchange for or upon conversion of our outstanding securities described herein, the filing of or an amendment to any registration statement pursuant to registration rights held by third parties not subject to a lock-up agreement or certain transfers in the case of officers, directors or other stockholders in the form of bona fide gifts, intra family transfers and transfers related to estate planning matters. Notwithstanding the foregoing, if (1) during the last 17 days of such 90-day restricted period we issue an earnings release or (2) prior to the expiration of such 90-day restricted period we announce that we will release earnings results during the 16-day period beginning on the last day of the 90-day restricted period, the foregoing restrictions shall continue to apply until the expiration of the 90-day period beginning on the issuance of the earnings release; provided, however, that this sentence will not apply if, as of the expiration of the restricted period, shares of our common stock are “actively-traded securities” as defined in Regulation M. The underwriters have advised us that they do not have any present intent to release the lock-up agreements prior to the expiration of the applicable restricted period.

The underwriters may engage in over-allotment, stabilizing transactions, syndicate covering transactions, penalty bids and passive market making in accordance with Regulation M under the Securities Exchange Act of 1934, as amended. Over-allotment involves syndicate sales in excess of the offering size, which creates a syndicate short position. Covered short sales are sales made in an amount not greater than the number of shares available for purchase by the underwriters under their over-allotment option. The underwriters may close out a covered short sale by exercising their over-allotment option or purchasing shares in the open market. Naked short sales are sales made in an amount in excess of the number of shares available under the over-allotment option. The underwriters must close out any naked short sale by purchasing shares in the open market. Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum. Syndicate covering transactions involve purchases of the shares of common stock in the open market after the distribution has been completed in order to cover syndicate short positions. Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the shares of common stock originally sold by such syndicate member is purchased in a syndicate covering transaction to cover syndicate short positions. Penalty bids may have the effect of deterring syndicate members from selling to people who have a history of quickly selling their shares. In passive market making, market makers in the shares of common stock who are underwriters or prospective underwriters may, subject to certain limitations, make bids for or purchases of the shares of common stock until the time, if any, at which a stabilizing bid is made. These stabilizing transactions, syndicate covering transactions and penalty bids may cause the price of the shares of common stock to be higher than it would otherwise be in the absence of these transactions. The underwriters are not required to engage in these activities, and may end any of these activities at any time.

LEGAL MATTERS

The validity of the shares of common stock offered in this prospectus will be passed upon for us by Fraser Trebilcock Davis & Dunlap, P.C., Lansing, Michigan. Certain legal matters will be passed upon for the underwriters by Vinson & Elkins, L.L.P., Dallas, Texas.

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.

WHERE YOU CAN FIND MORE INFORMATION

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

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

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


	•	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.


	•	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.


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


	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.


		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.


	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