Aurora Oil & Gas Corp - Annual Report (10-K)

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2007

o	TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 000-25170

AURORA OIL & GAS CORPORATION

(Exact Name of Registrant as Specified in its Charter)

Utah		87-0306609
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)
4110 Copper Ridge Dr, Suite 100, Traverse City, Michigan		49684
(Address of Principal Executive Offices)		(Zip code)
(231) 941-0073
(Issuer’s Telephone Number, Including Area Code.)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common stock, par value $0.01		American Stock Exchange

Securities registered pursuant to Section 12(g) of the Exchange Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o No x

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for past 90 days.

Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one).

Large accelerated filer o	Accelerated filer x
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

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

Yes o No x

The aggregate market value of common stock held by non-affiliates of the Registrant as of June 30, 2007, was $162,137,547. The number of outstanding shares of the Registrant’s common stock as of February 29, 2008, was 102,299,456.

Documents Incorporated By Reference:

Portions of the Proxy Statement for the annual shareholders’ meeting to be held on May 30, 2008, are incorporated by reference into Part III.

AURORA OIL & GAS CORPORATION

2007 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

PART I
Item 1.	Business	2
Item 1A.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	26
Item 2.	Properties	26
Item 3.	Legal Proceedings	26
Item 4.	Submission of Matters to a Vote of Security Holders	26
PART II
Item 5.	Market for the Registrant’s Common Stock, Related Shareholder Matters and Issuer Purchases of Equity Securities	27
Item 6.	Selected Financial Data	30
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 8.	Financial Statements and Supplementary Data	49
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	91
Item 9A.	Controls and Procedures	91
Item 9B.	Other Information	92
PART III
Item 10.	Directors, Executive Officers, and Corporate Governance	92
Item 11.	Executive Compensation	92
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	92
Item 13.	Certain Relationships, Related Transactions, and Director Independence	92
Item 14.	Principal Accounting Fees and Services	92
PART IV
Item 15.	Exhibits and Financial Statement Schedules	92
	Index to Exhibits	93
	Signatures	95
	Exhibits	96

Cautionary Note Regarding Forward-Looking Statements

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

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

●

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

●

uncertainties about the estimates of reserves;

●

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

●

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

●

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

●

domestic demand for oil and natural gas;

●

drilling and operating risks;

●

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

●

changes in our drilling plans and related budgets;

●

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

●

other factors discussed under Item 1A Risk Factors with the heading “Risks Related To Our Business”.

Because such statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. You are cautioned not to place undue reliance on such statements, which speak only as of the date of this report.

CERTAIN DEFINITIONS

As used in this report, “mcf” means thousand cubic feet, “mmcf” means million cubic feet, “bcf” means billion cubic feet, “bbl” means barrel, “mbbls” means thousand barrels, and “mmbbls” means million barrels. Also in this report, “boe” means barrel of oil equivalent, “mcfe” means thousand cubic feet of natural gas equivalent, “mmcfe” means million cubic feet of natural gas equivalent, “mmbtu” means million British thermal units, and “bcfe” means billion cubic feet of natural gas equivalent. Natural gas equivalents and crude oil equivalents are determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate, or natural gas liquids. All estimates of reserves and information related to production contained in this report, unless otherwise noted, are reported on a “net” basis. References to “us”, “we” and “our” in this report refer to Aurora Oil & Gas Corporation together with its subsidiaries.

PART I

ITEM 1. DESCRIPTION OF BUSINESS

OVERVIEW

We are a growing independent energy company focused on the exploration and development of unconventional natural gas reserves. Our projects target unconventional shale plays where large acreage blocks can be 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 located in the Antrim shale of Michigan, the New Albany shale of Southern Indiana and Western Kentucky, and the Woodford shale in Oklahoma.

In 1969, we commenced operations 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. On May 11, 2006, the name of Cadence Resources Corporation was changed to Aurora Oil & Gas Corporation (“AOG”).

As an early stage developer of properties, we have successfully accumulated a large acreage base of unconventional shale opportunities. As we develop these leaseholds, 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 as of December 31, 2007:

	Developed				Percentage Developed
Play/Trend	Gross		Net		Gross			Net
Michigan Antrim		310,141		156,481		28	%		34	%
New Albany		833,365		443,456		2	%		1	%
Woodford		37,325		33,219		-			-
Other		102,352		79,059		1	%		1	%
Total		1,283,183		712,215		8	%		8	%

As of December 31, 2007 our proved reserves were approximately 166.6 bcfe, of which 84% was in our Antrim shale properties and 70% was proved developed. The New Albany shale provided the largest increase in proved reserves during the year, adding a net 24 bcfe, which is a 900% increase over the 3.0 bcfe reported on December 31, 2006. The growth in the New Albany shale proved reserves was largely the result of 6 net wells drilled in 2007, which were 100% owned by Aurora. The Antrim shale proved reserves were reduced by a net 10.1 bcfe due to a 24.5 bcfe increase from positive drilling results in the Antrim shale and offset by 34.6 bcfe reduction in certain producing properties. This reduction reflected a lower production curve to be consistent with actual operating experience.

Unconventional shale plays tend to be characterized by high drilling success rates. For the 12-month period ending December 31, 2007, we incurred $52.0 million to drill and participate in 101 (59 net) wells, with a 92% drilling success rate. In addition, we incurred $12.0 million on property and leasehold acquisitions. Average net daily production increased from 8,150 mcfe per day in 2006 to 8,787 mcfe per day in 2007. The table below highlights our portfolio of producing wells as of December 31, 2007.

Play /Trend	Gross Wells Producing		Net Wells Producing		Gross Wells Waiting Hook-Up		Net Wells Waiting Hook-Up
Michigan Antrim		593.00		287.39		19.00		7.00
New Albany		27.00		3.25		7.00		5.36
Other		29.00		14.53		5.00		2.30
Total		649.00		305.17		31.00		14.66

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

Our Strategy

The objective of our business is to maximize shareholder value through the development of our substantial acreage base, which we expect to generate into significant increases in natural gas reserves and production growth. To achieve this objective, we employ the following strategies:

Establish a base of lower risk development projects. We have established an extensive leasehold position in three plays - Antrim shale, New Albany shale and Woodford shale. All of these plays are at varying stages of their respective development life cycle. We believe the New Albany shale and Woodford shale represent emerging plays, as development activity has only been initiated within the last several years. As we invest capital into these plays, we believe that increased information resulting from drilling and production data by all operators will lower the risk profile, enhance results and provide opportunities for creating natural gas reserves and production growth.

Improve financial flexibility. As an early-stage company with extensive development potential, we believe it is very important to have the right capital structure in place to facilitate our drilling activities. We expect to use a combination of internally-generated cash flow, project financing and reserve-based lending to achieve financial flexibility. Our financial structure will evolve as the company grows, fostering stable financing for our producing properties while providing flexibility for pursuing our growth development strategy.

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 majority of our future capital expenditures will be directed toward the drilling and production of wells, though we expect to continue acquiring additional leasehold interests to supplement our exploration and development strategy.

Optimize our asset portfolio . With extensive leasehold positions in three shale plays, as well as several smaller targeted projects in other locations, we believe that we have created a diverse asset portfolio which must be carefully developed to limit our risk profile. We expect to regularly review our projects to optimize the value of this asset portfolio, the result of which will include appropriate joint ventures, farm-outs, equity partnerships, acquisitions, or divestitures.

OPERATING AREAS

Antrim Shale

Our Antrim shale properties are primarily located in northern Michigan and represent the majority of our production and proved reserves. At December 31, 2007, we owned working interests in 640 (320 net) Antrim wells which included 28 (26 net) non-producing wells. In 2007, we drilled or participated in 56 gross (35 net) Antrim wells and completed 54 gross wells for a success rate of 96%. In 2006, we drilled 173 gross (98 net) Antrim wells and completed 164 gross wells for a success rate of 95%. We currently have 156,481 net acres leased, with approximately 52,603 acres developed in the Michigan Antrim shale play.

The Antrim shale underlies the entire Michigan basin. The primary producing trend for the shale runs across the northern portion of the Michigan basin from Lake Michigan to Lake Huron (160 miles). In most situations, Antrim shale is encountered by vertical drilling, though on occasion, we may determine that horizontal drilling is preferred. A simple completion procedure is employed, using industry-proven hydraulic fracturing technology. These wells are produced with a production system that is specifically designed to minimize pressure on the wells, pipelines, facilities, and reservoir. This is expected to increase the recoverability of the shale gas production, thereby providing the maximum recovery of natural gas.

The Antrim shale exhibits a thick shale (140 to 200 feet), with a high organic content (up to 20%). Over 9,000 wells are currently producing in the Antrim shale and are expected to provide an average of 0.5 bcf of natural gas per well, with a productive life between 30 and 50 years.

A typical production curve for the shale suggests a peak rate of gas occurring within the first two years of production, after the shale reservoir has gone through a period of dewatering. Once the gas is able to fully release from the shale, the production will typically decline between 2% and 7% annually.

During the last several years, we have focused on development drilling in the Antrim shale, creating a stable base of production and proved reserves for the company. In 2008, drilling concentration will be directed to our largest undeveloped asset, the New Albany shale.

New Albany shale

Our New Albany shale properties are primarily located in southwestern Indiana and represent the majority of our developable acreage base. As with the Antrim shale, our New Albany shale operations are focused on the unconventional shale play. At December 31, 2007, we owned working interests in 61 (19 net) New Albany shale wells which included 27 (10 net) non-producing wells. In 2007, we drilled or participated in 27 gross (11 net) New Albany wells and completed 27 gross wells for a success rate of 100%. In 2006, we drilled or participated in 26 gross (7.49 net) New Albany shale wells and completed 25 gross wells for a success rate of 96%. We currently have 443,456 net acres leased, with approximately 5,937 net acres developed in the New Albany shale.

The New Albany shale underlies a substantial portion of the Illinois basin. The most productive portion of the trend appears to run across the southeastern portion of Illinois, the southern portion of Indiana and the northwestern portion of Kentucky. Our acreage position is located primarily in the central portion of that trend, crossing approximately 12 counties.

Though the New Albany shale has been successfully drilled and produced using vertical wells, it has been determined that the most productive method of development is horizontal drilling. At this time, the completion methods are very simple, typically open-hole only. These wells are produced with a production system that is specifically designed to minimize pressure on the wells, pipelines, facilities and reservoir. This is expected to increase the recoverability of shale gas production, thereby providing the maximum recovery of natural gas.

The New Albany shale exhibits a thick shale (100 to over 200 feet), with high organic content (up to 25%). Over 200 vertical wells and less than 50 horizontal wells are currently producing in the New Albany shale. Horizontal wells are expected to provide an average of 1.2 bcf of natural gas per well with a productive life between 30 and 50 years.

A typical production curve for the shale suggests a peak rate of gas and water occurs within the first 60 days of production. Together, the natural gas and water decline an average of 2% to 7% annually.

While the New Albany shale is our primary target, our acreage also includes a variety of producible oil and natural gas formations, including those overlying silurian reefs and coalbed methane formations. Our New Albany shale drilling efforts will also provide useful information about these other producible formations for future evaluation strategies. In 2008, drilling concentration will be directed to certain properties in the New Albany shale, as it embodies the largest component of our undeveloped asset base. We believe this will provide further insight into our ability to predict the commerciality of the resource.

Woodford shale

Our Woodford shale properties are located in Oklahoma and are operated by our partner, West Star Operating Company. This is also an unconventional shale play which has recently emerged as a key onshore target of several large independent exploration and production companies. At December 31, 2007, we had 33,219 net acres leased, none of which has been developed.

The Woodford shale underlies most of Oklahoma, which includes the Anadarko, Arkoma, and Ardmore basins-a mature oil and gas area with more than 15 conventional producing reservoirs above and below the Woodford shale. Consequently, excellent well control data exists and was employed in our efforts to concentrate operations where the Woodford shale is the thickest (typically 200 feet thick). In addition, the shale boasts a high organic content and is highly siliceous, a property which lends itself to making the shale more productive.

In recent years, technological developments in completion and stimulation techniques have transformed this play. Horizontal wells and multi-stage fracturing technology will be utilized to provide the best rates of return. These wells are expected to provide an average of 3 bcf of natural gas per well with a productive life between 20 and 40 years.

In 2008, we expect to pursue a testing drilling program which will evaluate the acreage and determine the profitability of our Woodford shale project and other potential formations.

Drilling techniques and natural gas processing

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

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

In the Michigan Antrim, we use a simple proven completion procedure with industry proven hydraulic fracturing technology. This procedure involves drilling through several pay zones, setting and cementing casing, and drilling an extended rat-hole, which is used for gas-water separation. The wells are then hydraulically fractured with a specifically designed fracture procedure incorporating multiple stages with enhanced diversion methods to increase effective vertical coverage. Imaging logs are used to identify which zones are best fractured and will yield commercial gas production. For horizontal New Albany shale wells, minimal stimulation has been required to date to make economic gas wells. In exploratory areas of the New Albany and Antrim, shale log analysis is incorporated to enhance fracturing and completion design.

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

We use skid mounted booster compressors 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 4-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 using localized facilities as described above. We continue to explore innovations in technology and methodologies that will reduce production costs and increase efficiencies. We may use other drilling, completion and operating procedures than those described above if, in our opinion, alternative procedures will generate higher returns.

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

Oil and natural gas reserves

The following table presents information as of December 31, 2007, with respect to our estimated proved reserves. Estimates of our future net revenues from proved reserves are discounted to present value using an annual discount rate of 10% (PV-10), using oil and natural gas prices in effect as of the dates of such estimates, held constant throughout the life of the properties. The information presented is based on a reserve report prepared by Data & Consulting Services Division of Schlumberger Technology Corporation (“Schlumberger”). According to this report, approximately 39% of our proved reserves are classified as either proved developed non-producing or proved undeveloped.

	As of December 31, 2007
Oil and Natural Gas Reserves(a)	Oil		Gas		Total		PV-10(d)		Standardized Measure(e)
	(mbbls)		(mmcf)		(mmcfe)		(In thousands)		(In thousands)
Proved developed producing		74		100,887		101,331	$	127,723	$	110,036
Proved developed non-producing		66		14,894		15,290		22,788		17,332
Proved undeveloped		48		49,686		49,974		39,425		48,175
Total proved (b) (c)		188		165,467		166,595	$	189,936	$	175,543

Oil and Natural Gas Reserves by Play/Trend(a)	Total		Percent of Proved Reserves			PV-10(d)
	(mmcfe)					(In thousands)
Michigan Antrim		139,959		84	%	$	141,798
New Albany		24,982		15	%		37,347
Other		1,654		1	%		10,791
Total		166,595		100	%	$	189,936

Change in reserve quantity information for the year ended December 31, 2007(a)	Oil			Gas			Total
	(mbbls)			(mmcf)			(mmcfe)
Proved reserves as of December 31, 2006		81			152,964			153,450
Revisions of previous estimates		20			(34,651	)		(34,531	)
Purchases of minerals in place		-			2,943			2,943
Extensions and discoveries		131			47,256			48,042
Production		(28	)		(3,034	)		(3,202	)
Sales of minerals in place		(16	)		(11	)		(107	)
Proved reserves as of December 31, 2007		188			165,467			166,595

(a)

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

(b)

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

(c)

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

(d)

Represents the present value, discounted at 10% per annum (PV-10), of estimated future net revenue before income tax of our estimated proved reserves. The estimated future net revenues were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on economic conditions prevailing at December 31, 2007. The estimated future production is priced at December 31, 2007, without escalation, using $90.18 per bbl and $7.18 per mmbtu, in each case adjusted for transportation fees and regional price differentials. PV-10 is a non-GAAP financial measure because it excludes income tax effects. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of PV-10 to the most directly comparable GAAP measure - standardized measure of discounted future net cash flow - in the following table:

	As of December 31,
	2007		2006		2005
Standardized measure of discounted future net cash flows	$	175,543,140	$	130,461,821	$	152,868,240
Add: Present value of future income tax discounted at 10%		14,392,640		28,320,989		46,639,204
PV-10	$	189,935,780	$	158,782,810	$	199,507,444

(e)

The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes. As noted in footnote (a) above, this excludes the impact of our hedges. If the impact of our hedges were included, the standardized measure would have been increased by $7,214,670 to $182,757,810.

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

Acreage

The following table sets forth as of December 31, 2007, the gross and net acres of both developed and undeveloped oil and gas leases which we hold. “Gross” acres are the total number of acres in which we own a working interest. “Net” acres refer to gross acres multiplied by our fractional working interest. Acreage numbers do not include our options to acquire additional leaseholds which have not been exercised.

	Developed(a)				Undeveloped(b)				Total
Play/Trend	Gross		Net		Gross		Net		Gross		Net
Michigan Antrim		87,860		52,603		222,281		103,878		310,141		156,481
New Albany		13,120		5,937		820,245		437,519		833,365		443,456
Woodford		-		-		37,325		33,219		37,325		33,219
Other		1,330		830		101,022		78,229		102,352		79,059
Total		102,310		59,370		1,180,873		652,845		1,283,183		712,215

(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.

Production and price information

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

	Year Ended December 31
Production	2007		2006		2005
Oil (bbls)		27,907		22,588		10,628
Natural gas (mcf)		3,039,714		2,517,897		687,271
Natural gas equivalent (mcfe)		3,207,155		2,653,427		751,039

Oil and natural gas sales
Oil sales	$	1,939,160	$	1,399,445	$	558,455
Natural gas sales		24,784,658		20,192,366		6,184,989
Total	$	26,723,818	$	21,591,811	$	6,743,444

Average sales price (including realized gains or losses from hedging)
Oil ($ per bbl)	$	69.49	$	61.96	$	52.55
Natural gas ($ per mcf)		8.15		8.02		9.00
Natural gas equivalent ($ per mcfe)		8.33		8.14		8.98

Average production expenses ($ per mcfe)
Production taxes	$	0.35	$	0.33	$	0.67
Post-production expenses		0.59		0.55		0.50
Leasing operating expenses		2.14		1.82		1.62
Total	$	3.08	$	2.70	$	2.79

Productive wells

The following table sets forth as of December 31, 2007, information relating to the productive wells in which we owned a working interest. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of productive wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

	Natural Gas				Oil
Play/Trend	Gross Wells		Net Wells		Gross Wells		Net Wells
Michigan Antrim		612		294.39		-		-
New Albany		34		8.61		-		-
Woodford		-		-		-		-
Other		1		0.10		33		16.71
Total		647		303.10		33		16.71

Drilling activities

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

	Gross Wells						Net Wells
Type of Well	Productive ^(b)		Dry ^(c)		Total		Productive ^(b)		Dry ^(c)		Total
Year Ended 12/31/07 ^(d)
Exploratory ^(a)
Michigan Antrim		1		-		1		0.22		-		0.22
New Albany		15		-		15		10.57		-		10.57
Woodford		-		-		-		-		-		-
Other		7		6		13		5.51		5.00		10.51
Total		23		6		29		16.30		5.00		21.30
Development ^(a)
Michigan Antrim		50		2		52		29.43		2.00		31.43
New Albany		12		-		12		0.60		-		0.60
Woodford		-		-		-		-		-		-
Other		8		-		8		5.80		-		5.80
Total		70		2		72		35.83		2.00		37.83
Year Ended 12/31/06
Exploratory ^(a)
Michigan Antrim		2		-		2		2.00		-		2.00
New Albany		13		1		14		6.39		0.50		6.89
Other		1		3		4		0.38		1.25		1.63
Total		16		4		20		8.77		1.75		10.52
Development ^(a)
Michigan Antrim		162		9		171		91.53		4.93		96.46
New Albany		12		-		12		0.60		-		0.60
Other		6		-		6		3.95		-		3.95
Total		180		9		189		96.08		4.93		101.01
Year Ended 12/31/05
Exploratory ^(a)
Michigan 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)
Michigan Antrim		136		5		141		101.37		3.40		104.77
New Albany		3		-		3		0.15		-		0.15
Other		-		-		-		-		-		-
Total		139		5		144		101.52		3.40		104.92

(a)

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

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

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

(d)	At December 31, 2007, we had 3 gross (1 net) wells in the process of being drilled.

Sale of production

We market natural gas and oil production on a competitive basis for our operated properties. In most cases, we connect to nearby high pressure transmission pipelines and utilizes a gas marketing firm for the sale of production. Effective June 1, 2007, we entered into a firm sales contact with Integrys Energy Services, Inc. (formerly WPS) for 5,000 mmbtu per day at MichCon city-gate for the period June 1, 2007, through December 31, 2008. Our average daily production for operated Antrim was 6,277 mmbtu per day for 2007. Integrys Energy Services, Inc. is our primary marketing partner for the majority of our Michigan operated properties. In addition, we have established other base contracts primarily for future natural gas sales in Indiana and Michigan. We set the firm delivery volume obligation under these contracts on either a monthly or a daily basis with the amount of the obligation varying from month to month or day to day. As new wells come online and production volume increases, new production will be sold under the base contracts on a spot market pricing structure.

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

Hedging

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

Other properties

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

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

Employees

As of December 31, 2007, we had 67 full-time employees and 1 part-time employee. We are not a party to any collective bargaining agreements. We believe that our relations with our employees are good.

Executive Officers

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

Name	Age	Position(s) with the Company
William W. Deneau	63	Director, Chairman, and Chief Executive Officer
John E. McDevitt	61	Director, President, and Chief Operating Officer
Barbara E. Lawson	49	Chief Financial Officer
Gilbert A. Smith	60	Vice President, Business Development
John C. Hunter	56	Vice President, Exploration and Production

William W. Deneau has served on our Board of Directors and 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, positions he continued to hold until Aurora was merged into AOG effective January 1, 2008. William W. Deneau is the brother of Richard M. Deneau, another one of our Directors.

John E. McDevitt has served as our Director, President and Chief Operating Officer since January 22, 2008. Since 2006, Mr. McDevitt has been a Manager and President of Acadian Energy, LLC , a private company focused on unconventional natural gas exploration and production in the New Albany shale. From 2003 to 2007, Mr. McDevitt was President of CDX Resources LLC, a rig fleet and directional services company that was owned by CDX Gas, LLC. Prior to that, he held positions with CDX Gas, LLC as Chief Financial Officer and Senior Vice President of Strategic Planning. CDX Gas, LLC was an independent oil and gas company focused on the onshore exploration and production of unconventional natural gas, which was sold in 2006.

Barbara E. Lawson has served as our Chief Financial Officer since January 22, 2008. Ms. Lawson has worked for us since March 2006 as SEC Reporting Manager. From 2005 to 2006, Ms. Lawson was Vice President of Simple Financial Solutions, Inc. providing consulting services that covered public equity offerings and Sarbanes-Oxley Section 404 implementation. From 1988 to 2004, Ms. Lawson was employed with Midland Cogeneration Venture, LLP, an independent power producer, where her last position was Treasurer and Manager of Internal Audit.

Gilbert A. Smith has served as a Vice President since February 1, 2008. Since January 2007, Mr. Smith has been a Manager and Chief Operating Officer of Acadian Energy, LLC. From 2002 to 2006, Mr. Smith was Vice President of Land and Contract Administration for CDX Gas, LLC. From 1999 to 2001, Mr. Smith worked as an independent consultant , performing international strategic contract negotiation and business development. Mr. Smith worked for Sun Exploration and Production Company (subsequently named Oryx Energy Company) from 1978 through 1999 where he served in various senior management positions.

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

Competition and markets

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

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

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

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

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

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

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

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

In the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks of oil or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM are 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.

Where you can find more information

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 Securities and Exchange Commission (“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, DC 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 report, including all exhibits thereto and amendments thereof, has been filed electronically with the SEC.

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 . Our report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are posted on our website as soon as reasonably possible after they are electronically filed with the SEC and are available to you through our website free of charge. You may also request a copy of our SEC filings at no cost by writing or telephoning us at the above address attention investor relations. Information contained on our website does not constitute a part of this report.

ITEM 1A. RISK FACTORS

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, through December 31, 2007, natural gas prices quoted for the near month NYMEX contract have ranged from a low of $4.40 per mmbtu to a high of $11.00 per mmbtu. The prices for natural gas are subject to a variety of factors beyond our control, including:

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the level of consumer product demand;

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weather conditions;

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domestic and foreign governmental regulations;

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the price and availability of alternative fuels;

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political conditions in oil and natural gas producing regions;

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the domestic and foreign supply of oil and natural gas;

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speculative trading and other market uncertainty; and

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worldwide economic conditions.

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

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

We may have difficulty financing our planned growth.

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

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 these regions caused by weather conditions, governmental regulation, lack of field infrastructure, or other events which impact these areas. In addition, a majority of our leaseholds held for development are 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 December 31, 2007, we had over 3,700 net potential drilling locations to be included in our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, seasonal conditions, regulatory approvals, natural gas prices, costs and drilling results. Because of these uncertainties, we do not know if our numerous potential drilling locations will ever be drilled or if we will be able to produce natural gas from these or any other potential drilling locations, which could materially affect our business.

We may continue to incur losses.

We reported a net loss for the years ended December 31, 2007, 2006, and 2005. 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 December 31, 2007, we operated 35% of our gross wells and 67% of our net wells. As a result of these varying levels of management control, for those properties that we do not operate, we have no control over:

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the number of wells to be drilled;

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the location of wells to be drilled;

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the timing of drilling and re-completing of wells;

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the field company hired to drill and maintain the wells;

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the timing and amounts of production;

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the approval of other participants in drilling wells;

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development and operating costs;

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capital calls on working interest owners; and

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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 December 31, 2007, we had acquired approximately 1,283,183 (712,215 net) acres with 166,595 mmcfe in net proved reserves. We may not be able to identify suitable acquisitions in the future or to finance these acquisitions on favorable terms or at all. In addition, we compete against other companies for acquisitions, many of whom have substantially greater managerial and financial resources than we have. The successful acquisition of producing properties and undeveloped natural gas leases requires an assessment of the properties’ potential natural gas reserves, future natural gas prices, development costs, operating costs, potential environmental and other liabilities and other factors beyond our control. These assessments are necessarily inexact and their accuracy inherently uncertain. Such a review may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geological characteristics or geographic location than existing properties. Our acquisitions may not be integrated successfully into our operations and may not achieve desired profitability objectives.

We may lose key management personnel.

Our current management team has substantial experience in the oil and natural gas business. We do not currently have employment agreements with any members of our management team. The loss of any of these individuals could adversely affect our business. If one or more members of our management team dies, becomes disabled or voluntarily terminates employment with us, there is no assurance that a suitable or comparable replacement will be found.

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

Of our proved natural gas reserves as of December 31, 2007, approximately 61% are classified as proved developed producing, 9% 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:

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

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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;

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

●

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

Our oil and natural gas reserve data 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 change from year to year and vary considerably from actual results. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. Information regarding discounted future net cash flows should not be considered as the current market value of the estimated oil and natural gas reserves that will be attributable to our properties. Examples of items that may cause our estimates to be inaccurate include, but are not limited to, the following:

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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;

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

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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;

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

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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 36-month period ending December 31, 2007, approximately 6% 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 previously experienced a delay in receiving permits from the State of Michigan, Department of Environmental Quality ("DEQ"), for drilling horizontal wells, while the DEQ further reviews this drilling methodology. As a result of these delays, we have had to defer the drilling of certain wells in the Antrim shale until the review by the DEQ was completed and permits were issued. The DEQ has also forced producers to discontinue operations in certain areas of the Michigan Antrim so that the DEQ can inspect the salt water disposal wells operated in those areas. We have no control over this type of regulatory delay.

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

In September 2007, the DEQ collected and analyzed water samples from certain wells in the Arrowhead, Blue Chip, and Gaylord Fishing Club projects. On January 31, 2008, we met with the DEQ to review the analyses. Since the water composition in most of the wells fell within the range deemed by the DEQ to be fresh water, the DEQ requested that we plug six wells, plug or remediate an additional 15 wells, and collect water samples from the remaining wells that had not been previously sampled. We are currently preparing to collect a new round of water samples from every producing well, and the potential for remediation is under review.

Adverse weather may postpone 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. As noted above, a well producing too much water may have to be plugged.

We do not own any drilling equipment.

Since we do not own any drilling equipment, we are affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, and personnel which has delayed development drilling and other exploration activities and has caused significant price increases. We are unable to predict when or if such shortages may again occur or how they would affect our development and exploration program.

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. During 2006, our production was hampered by curtailments in a third-party processing facility. We have since completed construction of our own processing facility and built an alternate pipeline route in response to this curtailment.

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. To illustrate this risk, in late December 2006, a well in which we had a 13.33% cost interest experienced a blow-out. Our associated liability was $762,000, only $266,666 of which was covered by insurance.

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

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 December 31, 2007, our outstanding debt included a senior credit facility with a current approved borrowing base of $70 million, $56 million of which was drawn, and a five-year second lien term loan facility with a current approved borrowing base of $50 million, of which $50 million is currently drawn. 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, and we will be unable to draw more funds to use in development. We may not have sufficient funds available to make any required repayment, which could cause us to be in default of our credit facilities.

The value of the assets pledged as collateral under our senior credit facility and second lien term loan facility will depend on the then current commodity prices for natural gas. If prices drop significantly, we may have difficulty satisfying the ratio covenants of these credit facilities. As noted above, oil and natural gas prices are volatile.

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 plans.

Our debt level and the covenants in our credit facility agreements could negatively impact our financial condition, results of operations and business prospects.

Our level of indebtedness, and the covenants contained in our credit facility agreements, could have important consequences for our operations, including:

●

increasing our vulnerability to general adverse economic and industry conditions and detracting from our ability to withstand successfully a downturn in our business or the economy generally;

●

requiring us to dedicate a substantial portion of our cash flow from operations to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;

●

limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities;

●

limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

●

placing us at a competitive disadvantage relative to other less leveraged competitors; and

●

making us vulnerable to increases in interest rates, because borrowings under our credit facility may be at rates prevailing at the time of each borrowing.

We may incur non-cash charges to our operations as a result of current and future financing transactions .

Under current accounting rules and requirements, we may incur additional non-cash charges to future operations beyond the stated contractual interest payments required under our current and potential future credit facilities. While such charges are generally non-cash, they would impact our results of operations and earnings per share and could be material.

We may be required under accounting rules to take write-downs.

Under full cost accounting rules, capitalized costs of proved oil and gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter and requires a write-down for accounting purposes if the ceiling is exceeded. If a write-down is required, it would result in a charge to earnings but would not impact cash flow from operating activities. Once incurred, a write-down of oil and gas properties is not reversible at a later date.

We may incur limitations on the effectiveness of controls.

Our management, including our Chief Executive Officer and Chief Financial Officer, do not expect that our disclosure controls or our internal controls can prevent all possible error or fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations on all control systems, no evaluation of controls can provide absolute assurance that we have detected all control issues and instances of fraud, if any. These inherent limitations include the realities that judgments in decision making can be faulty and that breakdowns can occur because of error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

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

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

●

discharge permits for drilling operations;

●

drilling bonds;

●

reports concerning operations;

●

spacing of wells;

●

unitization and pooling of properties;

●

environmental protection; and

●

taxation.

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

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

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

RISKS RELATED TO THE OWNERSHIP OF OUR STOCK

We may experience volatility in our stock price.

For the 36-month period ending December 31, 2007, our stock traded as high as $7.44 per share and as low as $1.09 per share. The market price of our common stock may fluctuate significantly in response to a number of factors, some of which are beyond our control, including:

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changes in natural gas prices;

●

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

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quarterly variations in operating results;

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changes in financial estimates by securities analysts;

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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;

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

●

future sales of our common stock.

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

A voting block is created by certain voting agreements and irrevocable proxies, and we do not have cumulative voting.

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

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

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

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. Our authorized capital stock consists of 250,000,000 shares of common stock and 20,000,000 shares of preferred stock with such designations, preferences and rights as may be determined by our board of directors. On December 31, 2007, we had 101,769,456 shares of common stock outstanding and no shares of preferred stock outstanding.

At December 31, 2007, we had warrants and options outstanding that were exercisable for 4,892,609 shares of our common stock. We have an additional 5,257,500 shares available for award as either option or stock grants under our existing incentive plans. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock. We may also issue additional shares of our common stock, preferred 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, debt refinancing, or for other business purposes. In the future, we may engage in public offerings of our stock. Future sales of substantial amounts of our common stock, or the perception that sales could occur, could have a material adverse effect on the price of our common stock.

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

We have filed two shelf registration statements that together would register almost 20.6 million shares of common stock for resale. These registration statements are not currently effective. The sale of a large number of shares of our common stock pursuant to the resale registration statements, the perception that any such sale might occur, or the issuance of a large number of shares of our common stock in connection with future acquisitions, equity financings or otherwise, could cause the market price of our common stock to decline significantly. As of December 31, 2007, we had approximately 101.8 million shares of common stock issued and outstanding, including approximately 10.5 million shares of our common stock held or controlled by our executive officers and directors. Of those 10.5 million shares, 8.6 million are subject to lock-up agreements through October 31, 2008, 0.5 million are eligible for resale on two S-8 registration statements, and the balance are eligible for sale under Rule 144 ("Rule 144") under the Securities Act of 1933, as amended (the "Securities Act"). We have two currently effective S-8 registration statements that, combined, include 469,996 shares owned or controlled by our executive officers and directors that are registered for resale.

ITEM 1B. UNRESOLVED STAFF COMMENTS

On December 18, 2007, we received an SEC comment letter pertaining to our Form 10-KSB for the year ended December 31, 2006, and our Form 10-Q for the period ended September 30, 2007. The SEC comments addressed: (i) a presentation issue in the statement of operations; (ii) disclosures relating to asset retirement obligations, income (loss) per share, shareholders’ equity, methodologies for capitalizing interest, changes in standardized measure of discounted future cash flow, and SFAS 69; (iii) clarification on fourth quarter adjustments; and (iv) engineering comments with respect to our oil and gas reserves. On January 17, 2008, we filed our response. On February 13, 2008, we received a letter from the SEC with follow-up engineering comments and, on February 28, 2008, we filed our response. We have not yet received a reply from the SEC addressing our responses. We have incorporated into this Form 10-K several of the changes we suggested in our response to the SEC. We do not currently have reason to believe that there are any material open items but, since the SEC has not yet replied to our accounting response, we cannot be sure if there are any material open items.

ITEM 2. PROPERTIES

Information regarding our properties is included in Item 1 of this report.

ITEM 3. LEGAL PROCEEDINGS

Our management is unaware of any threatened or pending material legal claims or proceedings against us or our properties of a non-routine nature.

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

There were no matters submitted to a vote of our security holders for the quarter ended December 31, 2007.

PART II

ITEM 5. MARKET FOR COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

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 two most recent fiscal years. The prices during the time in which our stock traded over-the-counter are bid prices, without retail mark-up, mark-down or commission, and may not necessarily represent actual transactions. The prices during the time in which our stock traded on AMEX are actual sales prices.

Quarter Ended	High Bid/ Sales Price		Low Bid/ Sales Price
March 31, 2006	$	7.44	$	4.45
June 30, 2006	$	6.10	$	3.76
September 30, 2006	$	4.74	$	2.94
December 31, 2006	$	3.22	$	3.08
March 31, 2007	$	3.30	$	2.06
June 30, 2007	$	2.77	$	1.30
September 30, 2007	$	2.35	$	1.37
December 31, 2007	$	1.75	$	1.16

On February 26, 2008, the last reported sale price of our common stock on AMEX was $0.70 and there were 102,299,456 shares of our common stock outstanding and approximately 517 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 us from declaring dividends.

STOCK PERFORMANCE GRAPH

The graph below compares the monthly performance of our common stock to the Russell 2000 Index and the AMEX Natural Gas Index for the period beginning on the close of our first day of trading on the AMEX on May 24, 2006, and ending on the close of trading on the AMEX on December 31, 2007. The graph assumes a $100 investment in our common stock and each of the indices and reinvestment of dividends.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

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

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

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

In March 2006, our board of directors adopted, and in May 2006 our shareholders approved, the 2006 Stock Incentive Plan. This Plan provides for the award of options or restricted shares for compensatory purposes for up to 8,000,000 shares. As of December 31, 2007, we had awarded restricted stock and options to purchase restricted stock in a total amount of 2,742,500 shares, leaving 5,257,500 shares available for future awards.

We have awarded compensatory options and warrants to individuals that are considered outside the awards issued under our 2004 Equity Incentive Plan. Aurora has also issued compensatory options and warrants to individuals that are considered outside the awards issued under its 1997 Stock Option Plan and Equity Compensation Plan for Non-Employee Directors.

The following chart sets forth certain information as of December 31, 2007 regarding the shares of our common stock (i) issuable upon exercise of options or warrants granted as compensation for services; and (ii) available for grant under existing plans.

Plan Category	No. of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights			Weighted Average Exercise Price of Outstanding Options, Warrants and Rights		No. of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities in the First Column of this Table

Equity compensation plans approved by security holders		2,873,664		$	3.04		5,257,500

Equity compensation plans and awards not approved by security holders		86,280(a	)	$	1.69		-0-

Total/combined		2,959,944		$	3.00		5,257,500

(a)	These options and warrants to purchase shares were issued as follows:

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

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

UNREGISTERED EQUITY SALES/PURCHASES

None.

ITEM 6. SELECTED HISTORICAL FINANCIAL DATA

The following table sets forth our December 31, 2007, 2006, and 2005, year end selected financial data as of and for each of the periods indicated. The data as of and for the years ended December 31, 2007, 2006, and 2005, is derived from our audited consolidated financial statements for the periods indicated. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and audited consolidated financial statements and related notes included elsewhere in this report. The following information is not necessarily indicative of our future financial results.

	2007			2006			2005
Statement of Operations Data
Revenues:
Oil and natural gas sales	$	26,723,818		$	21,591,811		$	6,743,444
Pipeline transportation and marketing		792,587			489,473			-
Field service and sales		390,401			125,611			-
Interest and other		549,149			220,592			666,850
Total revenues		28,455,955			22,427,487			7,410,294

Expenses:
Production taxes		1,123,070			877,319			506,635
Production and lease operating expense		8,761,445			5,966,341			1,587,205
Pipeline operating expense		359,865			265,795			-
Field services expense		321,753			90,913			-
General and administrative expense		8,029,122			7,531,718			3,435,507
Oil and natural gas depletion and amortization		3,769,104			2,681,290			767,511
Other assets depreciation and amortization		2,396,026			2,083,191			308,647
Interest expense		4,582,021			4,573,785			1,307,370
Loss on debt extinguishment		3,448,520			-			-
Taxes, other		19,021			250,884			29,651
Total expenses		32,809,947			24,321,236			7,942,526
Loss before minority interest		(4,353,992	)		(1,893,749	)		(532,232	)
Minority interest in (income) loss of subsidiaries		(67,841	)		(50,898	)		15,960
Net loss	$	(4,421,833	)	$	(1,944,647	)	$	(516,272	)

Net loss per common share-basic and diluted	$	(0.04	)	$	(0.02	)	$	(0.01	)

Weighted average common shares outstanding - basic and diluted		101,633,162			82,288,243			40,622,000

Cash Flow Data
Cash provided by (used in) operating activities	$	10,079,049		$	5,467,910		$	(2,404,739	)
Cash used by investing activities		(61,100,489	)		(89,606,098	)		(39,869,326	)
Cash provided by financing activities		51,711,722			73,892,946			49,075,121

	As of December 31,
	2007		2006
Balance Sheet Data
Cash and cash equivalents	$	2,425,678	$	1,735,396
Other current assets		8,901,774		11,306,797
Oil and natural gas properties, net (using full cost accounting)		209,818,344		161,471,277
Other property and equipment, net		10,365,599		10,465,897
Other assets		23,160,273		27,407,825
Total assets	$	254,671,668	$	212,387,192

Current liabilities	$	8,580,990	$	18,040,082
Long-term debt, net of current maturities		113,835,028		54,538,138
Minority interest in nets assets of subsidiaries		112,661		77,873
Shareholders’ equity		132,142,989		139,731,099
Total liabilities and shareholders’ equity	$	254,671,668	$	212,387,192

ITEM 7. 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 report. 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 report.

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.

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

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.

Operational Highlights

For the year ended December 31, 2007, we continued to shift our focus from acquisition of properties to an early stage developer of unconventional shale development projects. As of December 31, 2007, our leasehold acres were 1,283,183 (712,215 net) which represent a 5% increase over our December 31, 2006 net acres. These leasehold acres are included in the following plays: 310,141 (156,481 net) leasehold acres in the Michigan Antrim shale play, 15,683 (15,683 net) leasehold acres in the Indiana Antrim shale play, 833,365 (443,457 net) acres in the New Albany shale play, 37,325 (33,219 net) acres in the Woodford shale play, and 86,669 (64,175 net) acres in the Other play areas.

With regard to our strategy to generate growth through drilling, we drilled or participated in 101 (59 net) wells for the year ended December 31, 2007, with a 92% success rate. As of December 31, 2007, we had 649 (305 net) producing wells, 31 (15 net) wells awaiting hook-up, 54 (37 net) wells undergoing resource assessment and 9 (2 net) wells temporarily abandoned. We also continued our strategy to have greater control over our projects by operating 258 (240 net) wells, thus, operating 35% of our gross wells and 67% of our net wells.

We began 2007 with estimated proved reserves of 153 bcfe and at December 31, 2007 had 167 bcfe, an increase of 14 bcfe, or 9%. The New Albany shale provided the largest increase in proved reserves during the year, adding a net 27 bcfe, which is a 900% increase over the 3.0 bcfe reported on December 31, 2006. The growth in the New Albany shale proved reserves was largely the result of 6 net wells drilled in 2007, which were 100% owned by Aurora. The Antrim shale proved reserves were reduced by a net 10.1 bcfe due to a 24.5 bcfe increase from positive drilling results in the Antrim shale and offset by a 34.6 bcfe reduction in certain properties. This reduction reflected a lower production projection to be consistent with actual operating experience.

Oil and natural gas production for 2007 was 3,207,155 mcfe, or a 21% increase over the 2,653,427 mcfe produced in 2006. During 2007, production continued to be hampered by delays in bringing wells into production, weather, dewatering, and certain properties not meeting expected production targets. Our average daily production for 2007 was 8,787 mcfe per day compared to 7,270 mcfe per day in 2006.

On September 10, 2007, we announced that we have established an acreage position of over 30,000 net acres in the Woodford shale natural gas play of Oklahoma. The identified target area is focused in central Oklahoma, which is experiencing a significant increase in leasing and drilling activity. It is positioned among geological provinces with active Woodford shale development, with average depths over 5,000 feet and organic shale thickness up to 300 feet. We currently have expended approximately $8.0 million for an 89% working interest in over 37,000 gross acres in the play. The early leasing activities have allowed us to establish this competitive position in the targeted play area. Leasing activities are continuing. We have targeted 2008 for a pilot program of 5 test wells in the project area. Since our current capital expenditure budget has been dedicated to further development of the Antrim and New Albany shales, we have been in discussions with potential financing sources and joint venture partners to facilitate testing and development of this acreage. No financing for this development has been procured as of the date of this filing.

In the third quarter of 2007, we drilled six wells in the South Knox project area of the New Albany shale and began construction of our first operated sales outlet in the New Albany Shale. Our wholly-owned subsidiary, Bach Services and Manufacturing Company (“Bach”) was responsible for building the sales outlet. Bach completed a pipeline which included trenching 10.6 miles with installation of 20 miles of poly piping and 10 miles of steel piping as well as building a processing and compression facility. The facility is tapped into the Ohio Valley Hub, LLC pipeline system, a wholly-owned subsidiary of ProLiance Energy, LLC. We began test flowing gas from these wells on December 31, 2007.

Other Developments

On August 20, 2007, we entered into a second lien term loan agreement with BNP, as the arranger and administrative agent, and several other lenders forming a syndication. The initial term loan is $50 million for a 5-year term which may increase up to $70 million under certain conditions over the life of the loan facility. The proceeds of the loan were used to pay off our existing mezzanine financing with TCW and for general corporate purposes. In connection with the loan, we also agreed to the amendment and restatement of our senior secured credit facility with BNP and other lenders, pursuant to which the borrowing base under the senior secured credit facility was increased from the current authorized borrowing base of $50 million to $70 million.

In September 2007, we retained Johnson Rice & Company, L.L.C. (“JRCO”) to investigate our strategic alternatives. The alternatives, among other things, were to include revisions to our strategic plan, asset divestitures, operating partnerships, identifying additional capital sources, or a sale, merger, or other business combination. During this investigative period, we reduced our drilling activities, postponed significant asset divestitures, and focused on maintaining our current operations pending the outcome of the evaluation process.

With the assistance of JRCO, our Board of Directors determined that the best way to create value was to strengthen our management team, increase our capital availability, focus on drilling our undeveloped properties, and optimize our asset portfolio through the sale, joint venture, farm-out, or development of our non-core leasehold.

On January 25, 2008, we announced the signing of a non-binding Letter of Intent to acquire Acadian Energy, LLC, a private company focused on development of the unconventional resources found in the New Albany shale. The proposed acquisition is valued at approximately $12.5 million and will include over 10,000 acres of New Albany shale properties, four development wells, and approximately 7 bcf in proved reserves. The company is jointly owned and operated by John E. McDevitt and Gilbert A. Smith (60% and 40% beneficial ownership, respectively).

As part of that announcement, we also noted that, effective January 22, 2008, the Board of Directors named Mr. McDevitt President, Chief Operating Officer, and Director. Mr. Smith was named Vice President of Business Development, effective as of February 1, 2008. Each of these gentlemen offers approximately 40 years of experience, which includes executive-level experience, some of it at large exploration and production companies. In addition, Mr. McDevitt has spent the bulk of his career specializing in structured finance for emerging enterprises.

With Mr. McDevitt’s assistance, we have determined that our existing capital structure is not adequate to continue our planned growth. In fact, we believe that the best way to pursue the development of our acreage base is to install project financing directed toward each play or subset of each play. At this time, we are negotiating several term sheets with certain recognized energy lenders offering credit facilities for a minimum of at least $50 million per project for at least two of our development projects—one for the New Albany shale and one for the Woodford shale. Upon closing, we expect to have to establish separate financing for these projects which will be non-recourse to our other businesses. Our goal is to have these term sheets signed within approximately 30 days and closed, subject to BNP consent, within 90 days. We anticipate announcing the terms of the respective credit facilities upon the closing of such agreements. There can be no assurance that we will be able to successfully procure the project financings that we are seeking.

Also, our Board of Directors is in the process of completing its work with JRCO. This evaluation process did not lead to an asset divestiture, operating partnership, or identification of additional capital sources. It did, however, lead to a revision in our strategic plan, the related non-binding Letter of Intent to acquire Acadian Energy, LLC, and the change in our management team. We believe that, despite the operational slowdown we experienced over the past 6 months, this process has enabled the Board of Directors to retain a more experienced management team, has led to the receipt of term sheets from new financial institutions which are expected to increase our capital availability, and has established a more disciplined focus on optimizing our entire asset base.

RESULTS OF OPERATIONS

Operating Statistics

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

	Year Ended December 31,
	2007		2006		2005
Net wells drilled
Antrim		33		93		105
New Albany		11		7		-
Other		8		5		1
Dry		7		7		7
Total		59		112		113

Total producing net wells
Antrim – producing		287		199		110
Antrim – awaiting hookup		7		51		52
NAS – producing		3		1		-
NAS – awaiting hookup		5		7		2
Other – producing		15		14		13
Other – awaiting hookup		3		1		6
Total		320		273		183

Production
Natural gas (mcf)		3,039,714		2,517,897		687,271
Crude oil (bbls)		27,907		22,588		10,628
Natural gas equivalent (mcfe)		3,207,155		2,653,427		751,039

Average daily production
Natural gas (mcf)		8,328		6,898		1,883
Crude oil (bbls)		76		62		29
Natural gas equivalent (mcfe)		8,787		7,270		2,057

Average sales prices (including realized gains or losses from hedging)
Natural gas ($ per mcf)	$	8.15	$	8.02	$	9.00
Crude oil ($ per bbl)	$	69.49	$	61.96	$	52.55
Natural gas equivalent ($ per mcfe)	$	8.33	$	8.14	$	8.98

Production revenue
Natural gas	$	24,784,658	$	20,192,366	$	6,184,989
Crude oil		1,939,160		1,399,445		558,455
Total	$	26,723,818	$	21,591,811	$	6,743,444

Average expenses ($ per mcfe)
Production taxes	$	0.35	$	0.33	$	0.67
Post-production expenses		0.59		0.46		0.50
Leasing operating expenses		2.14		1.78		1.61
General and administrative expense		2.50		2.84		4.57
General and administrative expense excluding stock-based compensation		1.81		2.00		4.57
Oil and natural gas depreciation, depletion and amortization expense		1.18		1.01		1.02
Other assets depreciation and amortization		0.75		0.79		0.41
Interest expense		1.43		1.72		1.74
Taxes		0.01		0.09		0.04

Number of employees including Bach employees		68		90		36

Year Ended December 31, 2007, compared with Year Ended December 31, 2006

General . For the year ended December 31, 2007, we had a net loss of $4.4 million, or $(0.04) per diluted common share, on total revenues of $28.5 million. This compares to a net loss of $1.9 million, or $(0.02) per diluted common share, on total revenue of $22.4 million during the year ended December 31, 2006. The $6.1 million increase in revenue represents increased production and improved price realization as a result of higher market prices and financial hedging. In addition, the net loss of $4.4 million in 2007 included a $3.4 million in a one time charge on debt extinguishment and $2.2 million in stock-based compensation expense.

Oil and Natural Gas Sales . During 2007, oil and natural gas sales were $26.7 million compared to $21.6 million in 2006. We produced 3,207,155 mcfe at a weighted average price of $8.33 compared to 2,653,427 mcfe at a weighted average price of $8.14. This increase in production was due to new wells placed on-line and production growth of existing wells. We had 305 net wells producing as of December 31, 2007 as compared to 214 net wells producing as of December 31, 2006. The 2007 weighted average price included $3.9 million of realized gains from the gas derivative contracts. Production from the Antrim shale play represented approximately 91% of our oil and natural gas revenue for 2007.

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

	Year Ended December 31, 2007				Year Ended December 31, 2006
Play/Trend	(mcfe)		Amount		(mcfe)		Amount
Antrim		2,975,715	$	24,346,250		2,353,691	$	18,948,300
New Albany		57,186		404,967		28,517		190,079
Other		174,254		1,972,601		271,219		2,453,432
Total		3,207,155	$	26,723,818		2,653,427	$	21,591,811

Other Revenues . Other revenues increased by $0.9 million, or 107% to $1.7 million in 2007 from $0.8 million in 2006. This increase is attributed to two acquisitions completed in 2006 and the sale of mining claims in 2007. The first acquisition is the Hudson gas properties with pipeline business component and the second acquisition is Bach which provides oil and natural gas field services.

Production Taxes. Production taxes were $1.1 million in 2007 compared to $0.9 million in 2006. This increase is attributed to production growth and the state mix of production. On a unit of production basis, production taxes were $0.35 per mcfe in 2007 compared to $0.33 per mcfe in 2006.

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

Production and lease operating expenses were $8.8 million in 2007 compared to $6.0 million in 2006. On a unit of production basis, production and lease operating expenses were $2.73 per mcfe in 2007 compared to $2.24 per mcfe in 2006. The increase in 2007 was primarily attributable to our expanding operations which increased energy costs, property taxes, pumping costs, repair, and maintenance associated with meters, compressors and pumps, and outside labor. On a component basis, post-production expenses were $1.9 million, or $0.59 per mcfe in 2007 compared to $1.2 million or $0.46 per mcfe in 2006 and lease operating expenses were $6.9 million, or $2.14 per mcfe in 2007 compared to $4.7 million, or $1.78 per mcfe in 2006.

Production and lease operating expenses for operated properties were $2.64 per mcfe in 2007 compared to $2.23 per mcfe in 2006. Non-operated production and lease operating expenses were $2.91 per mcfe in 2007 compared to $2.74 in 2006. Our operated Arrowhead and Chandler North projects negatively impacted our operating cost controls and efficiency due to extensive dewatering needs. Production and lease operating expenses for operated properties excluding Arrowhead and Chandler North were $2.51 per mcfe in 2007.

Pipeline Operating Expense and Field Services Expenses . Pipeline operating expenses were $0.4 million in 2007 compared to $0.3 million in 2006. Field services expenses were $0.3 million in 2007 compared to $0.1 million in 2006, which was attributable to the Bach acquisition in October 2006.

Payroll and related costs increased by $1.5 million to $6.3 million in 2007. This included staffing additions and merit increases ($0.8 million), stock-based compensation ($0.3 million), 2007 retention bonuses ($0.2 million) and health care ($0.2 million). Legal, accounting, and other consulting services were reduced by $0.4 million to $1.4 million in 2007 compared to $1.8 million in 2006, even though Section 404 of the Sarbanes-Oxley Act of 2002 was implemented for $0.2 million. Insurance had a slight increase of $65,000 due to coverage associated with Bach, while there were offsets of $0.4 million from the disposal of legacy Cadence stock investments and a correction of the stock ledger associated with a prior Cadence transaction.

We follow the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We capitalized certain internal costs that can be directly identified with our acquisition, exploration and development activities and did not include any costs related to production, general corporate overhead or similar activities. During the year ended December 31, 2007, we capitalized $1.3 million of payroll and benefit costs to oil and natural gas properties.

Oil and Natural Gas Depletion, Depreciation and Amortization (“DD&A”) . DD&A of oil and natural gas properties was $3.8 million and $2.7 million during 2007 and 2006, respectively. DD&A is a function of capitalized costs in the full cost pool and related underlying reserves in the periods presented. This increase is the result of $46.1 million being added to proved properties in the full cost pool, production growth, and the underlying reserves increasing by 13.1 bcfe. The average DD&A cost per mcfe was $1.18 and $1.01 in 2007 and 2006, respectively

Other Assets Depreciation and Amortization (“D&A”) . D&A of other assets was $2.4 million in 2007, compared to $2.1 million in 2006. This increase was primarily the result of additions in other assets.

Interest Expense . Interest expense was $4.6 million in 2007 and $4.6 million in 2006 which remain relatively stable given higher utilization of debt to continue our growth strategy of acquiring and developing operating interests in the Antrim shale and the New Albany shale.

Loss on Debt Extinguishment. We recorded $3.4 million as a loss on debt extinguishment due to the termination of the mezzanine debt held by TCW. Under the termination provisions, we were required to pay certain fees and prepayment charges associated with early termination. The following represents the expenses incurred: (i) $0.35 million payment of interest make-whole provision from August 21, 2007, through September 27, 2007; (ii) $1.25 million payment of prepayment premium; (iii) $0.2 million payment for a make-whole provision on principal greater than $30 million; and (iv) $1.6 million write-off of unamortized debt issuance cost

Taxes, Other. Tax expense was $19,021 in 2007, compared to $0.3 million in 2006. This decrease represents a 2005 Indiana tax refund of approximately $46,000 and a $45,000 reduction in estimated Louisiana state taxes. We have significant net operating loss carry forwards, thus no federal income tax expense has been recognized.

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

General . For the year ended December 31, 2006, we had a net loss of $1.9 million, or $(0.02) per diluted common share, on total revenues of $22.4 million. This compares to a net loss of $0.5 million, or $(0.01) per diluted common share, on total revenue of $7.4 million during the year ended December 31, 2005. The $15.0 million increase in revenue represents our initial steps as an early stage developer of oil and natural gas properties.

Oil and Natural Gas Sales . During 2006, oil and natural gas sales were $21.6 million compared to $6.7 million in the 2005. We produced 2,653,427 mcfe at a weighted average price of $8.14 compared to 751,039 mcfe at a weighted average price of $8.98. This increase in production was due to new wells placed on-line, acquisition of additional working interest in the Hudson properties and the producing assets from the Cadence reverse merger. We had 214 net wells producing as of December 31, 2006 as compared to 123 net wells producing as of December 31, 2005. The weighted average price included $2.7 million of realized gains from the gas derivative contract entered into 2006. Production from the Antrim shale play represented approximately 88% of our oil and natural gas revenue for the 2006.

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

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

Other Revenues . Other revenues increased by $0.2 million, or 25% to $0.8 million in 2006 from $0.7 million in 2005. This increase is attributed to two acquisitions completed in 2006. The first acquisition is the Hudson gas properties with pipeline business component and the second acquisition is Bach which provides oil and natural gas field services.

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

Production and lease operating expenses were $6.0 million in 2006 compared to $1.6 million in 2005. On a unit of production basis, production and lease operating expenses were $2.24 per mcfe in 2006 compared to $2.11 per mcfe in 2005. The increase in 2006 was primarily attributable to increased energy costs, pumping costs, repair, and maintenance associated with compressors and pumps and road and location maintenance. On a component basis, post-production expenses were $1.2 million, or $0.46 per mcfe in 2006 compared to $0.4 million or $0.50 per mcfe in 2005 and lease operating expenses were $4.8 million, or $1.78 per mcfe in 2006 compared to $1.2 million, or $1.61 per mcfe in 2005.

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

Pipeline Operating Expense and Field Services Expenses . Pipeline operating expenses were $0.3 million in 2006 compared to no expense in 2005 which are attributable to the Hudson acquisition. Field services expenses were $0.1 million in 2006 compared to no expense in 2005 which are attributable to the Bach acquisition.

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

Payroll and related costs increased by $2.1 million to $4.6 million in 2006. This included stock-based compensation of $2.2 million in 2006 which consists of $0.8 million for directors, $0.8 for senior management and $0.6 for employees. Fiscal year 2005 did not have any stock-based compensation. We incurred $1.8 million in legal, accounting and other consulting services as a result of our growth strategy including development costs associated with becoming a public entity and on-going public costs.

We follow the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We capitalized certain internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. During the year ended December 31, 2006, we capitalized $1.4 million of payroll and benefit costs to oil and natural gas properties.

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

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

In September 2007, we retained Johnson Rice & Company, L.L.C. (“JRCO”) to assist the Board of Directors with investigating our strategic alternatives. These alternatives, among other things, were to include revisions to our strategic plan, asset divestitures, operating partnerships, identifying additional capital sources, or a sale, merger, or other business combination. During this investigative period, we reduced our drilling activities, postponed asset divestitures, and focused on maintaining current operations pending the outcome of the evaluation process. Based upon the alternatives presented by JRCO, our Board of Directors have determined the best way to create value is as follows: (i) to strengthen our management team; (ii) adjust our capital structure to improve capital availability; (iii) focus on drilling our undeveloped properties; and (iv) optimize our asset portfolio through a combination of asset divestitures, joint venture, or farm-out of our non-core assets.

Currently, we are able to maintain our existing operations through the existing cash balances and internally generated cash flows from sales of oil and natural gas production. However, we have determined that our existing capital structure is not adequate to fund our planned growth. We believe the best way to pursue our growth strategy is with project financing for our emerging plays in the New Albany shale and the Woodford shale. At this time, we are in the process of negotiating several term sheets with certain recognized energy lenders offering mezzanine/project equity financing for at least two areas in our emerging plays. Our goal is to establish separate financing entities for each emerging play while ensuring the financing structure is non-recourse to our parent entity. Our current credit facilities are reserve-based lending which is appropriate for a mature development play like our Antrim shale. We are currently in discussion to improve our existing credit facilities. As of the date of this filing, no project financing or amendments to our existing credit facilities have been procured. There can be no assurance that we will be successful in procuring the financing and amendments we are seeking. Future cash flows are subject to a number of variables, including the level of production, natural gas prices and successful drilling efforts. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures.

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

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

The loan contains, among other things, a number of financial and non-financial covenants relating to restricted payments (as defined), loans or advances to others, additional indebtedness, incurrence of liens, geographic limitations on operations to the United States, and maintenance of certain financial and operating ratios, including (i) maintenance of a maximum of indebtedness to earnings before interest, income taxes, depreciation, depletion and amortization and non-cash expenses, and (ii) maintenance of minimum reserve value to indebtedness. Any event of default under the senior secured credit facility that accelerates the maturity of any indebtedness thereunder is also an event of default under the second lien term loan. As of December 31, 2007, we were in compliance with all of the applicable covenants.

In both the loan and senior secured credit facility, we agreed to an affirmative covenant regarding production exit rates. The production exit target is 12.0 MMcfe per day as December 31, 2007 (which has been achieved), and as of the last day of each quarter thereafter. In addition, we were required to purchase financial hedges at prices and aggregate notional volumes satisfactory to BNP, as administrative agent which requirement has been satisfied.

Our senior secured credit facility is a $100 million senior secured credit facility with BNP. In connection with the second lien term loan, we also agreed to the amendment and restatement of our senior secured credit facility with BNP and other lenders, pursuant to which the borrowing base under the senior secured credit facility was increased from the previous authorized borrowing base of $50 million to $70 million. The amount of the borrowing base is based primarily upon the estimated value of our oil and natural gas reserves. The borrowing base amount is redetermined by the lenders semi-annually on or about April 1 and October 1 of each year or at other times required by the lenders or at our request. The required semiannual reserve report may result in an increase or decrease in credit availability. The security for this facility is substantially all of our oil and natural gas properties, guarantees from all material subsidiaries, and a pledge of 100% of the stock or member interest of all material subsidiaries.

The senior secured credit facility provides for borrowings tied to BNP’s prime rate (or, if higher, the federal funds effective rate plus 0.5%) or LIBOR-based rate plus 1.25% to 2.0% depending on the borrowing base utilization, as selected by us. The borrowing base utilization is the percentage of the borrowing base that is drawn under the senior secured credit facility from time to time. As the borrowing base utilization increases, the LIBOR-based interest rates increase under this facility. As of December 31, 2007, interest on the borrowings had a weighted average interest rate of 6.93%. The maturity date of the outstanding loan may be accelerated by the lenders upon occurrence of an event of default under the senior secured credit facility.

The senior secured credit facility contains, among other things, a number of financial and non-financial covenants relating to restricted payments (as defined), loans or advances to others, additional indebtedness, incurrence of liens, geographic limitations on operations to the United States, and maintenance of certain financial and operating ratios, including (i) maintenance of a minimum current ratio, and (ii) maintenance of a minimum interest coverage ratio. Any event of default under the second lien term loan that accelerates the maturity of any indebtedness thereunder is also an event of default under the senior secured credit facility. As of December 31, 2007, we were in compliance with all of the applicable covenants.

In both the loan and senior secured credit facility, the Company agreed to an affirmative covenant regarding production exit rates. The production exit target is 12.0 MMcfe per day as of December 31, 2007 (which was achieved), and as of the last day of each quarter thereafter. In addition, the Company was required to purchase financial hedges at prices and aggregate notional volumes satisfactory to BNP, as administrative agent.

Our total capitalization was as follows for the periods set forth:

	As of December 31
	2007		2006
Short-term bank borrowings	$	-	$	542,788
Obligations under capital lease		7,784		17,096
Notes payable		219,478		280,321
Mortgage payable		3,082,196		3,175,298
Mezzanine financing		-		40,000,000
Senior secured credit facility		56,000,000		10,000,000
Second lien term loan		50,000,000		-
Total debt		109,309,458		54,015,503
Minority interest in net assets of subsidiaries		112,661		77,873
Shareholders’ equity		132,142,989		139,731,099
Total capitalization	$	241,565,108	$	193,824,475

Cash Flows from Operating Activities

Cash provided by operating activities increased 84% to $10.1 million in 2007, compared to $5.5 million in 2006. This $4.6 million increase in net cash provided by operating activities was due to an increase in production revenues as well as increases in other service income. See “Results of Operations” for discussion of changes in revenues and expenses. Non-cash charges increased due to higher depreciation, depletion and amortization and a one-time charge on debt extinguishment. Changes in current operating assets and liabilities decreased cash flow from operations by $2.5 million.

Cash provided by operating activities was $5.5 million in 2006, compared to cash used of $2.4 million in 2005. This $7.9 million increase in net cash provided by operating activities was substantially due to a 220% increase in production revenues. See “Results of Operations” for discussion of changes in revenues and expenses. Non-cash charges increased due to higher depreciation, depletion and amortization as well as recognition of stock-based compensation in 2006. Changes in current operating assets and liabilities decreased cash flow from operations by $0.8 million.

Cash Flows used in Investing Activities

Cash flows used in investing activities was $61.1 million in 2007, $89.6 million in 2006, and $39.9 million in 2005. The following table describes our significant investing transactions that we completed in the periods set forth below:

	Year Ended December 31
	2007			2006			2005
Acquisitions of leasehold
Michigan Antrim shale	$	1,443,243		$	5,325,872		$	5,747,079
Indiana Antrim shale		491,127			4,631			-
New Albany shale ^(a)		3,476,568			15,567,504			8,488,834
Woodford shale		5,413,132			2,063,181			-
Other		172,459			1,233,485			4,047,089

Drilling and development of oil and natural gas properties
Michigan Antrim shale		22,123,120			20,449,950			20,981,270
Indiana Antrim shale		1,398,811			500			-
New Albany shale		10,318,178			2,808,030			9,422
Other		1,502,129			5,918,128			321,416

Infrastructure properties
Michigan Antrim shale		10,128,646			10,988,527			6,523,298
New Albany shale		1,791,091			1,789,816			105,770
Other		10,438			350,268			-

Capitalized interest and general and administrative cost on exploration, development and leasehold		5,646,672			5,252,900			1,146,084

Acquisitions of oil and natural gas properties		2,405,609			24,011,335			-
Acquisitions/additions for pipeline, property and equipment		1,586,328			4,647,497			4,523,706
Other, net		186,334			855,070			485,741
Subtotal of capital expenditures	$	68,093,885		$	101,266,694		$	52,379,709

Sale of oil and natural gas properties ^(a)		(2,079,518	)		(11,489,456	)		(11,504,428	)
Sale and leaseback of gas compression equipment		(3,844,500	)		-			-
Sale of other investments		(1,069,378	)		(171,140	)		(48,935	)
Net cash acquired in merger		-			-			(957,020	)
Subtotal of capital divestitures		(6,993,396	)		(11,660,596	)		(12,510,383	)

Total	$	61,100,489		$	89,606,098		$	39,869,326

(a) On February 2, 2006, Aurora closed an acquisition of certain New Albany shale acreage located in Indiana, commonly called the Wabash project. Aurora acquired 64,000 acres of oil and natural gas leases from Wabash Energy Partners, L.P. for a purchase price of $11,840,000. We were required to deposit into escrow for the sellers $3.2 million in 2005. Aurora then sold half its interest in a combined 95,000 acre lease position in the Wabash project to New Albany-Indiana, L.L.C., an affiliate of Rex Energy Operating Corporation (“Rex”) for a sale price of $10,500,000. Rex placed $3.5 million in an escrow account in 2005 as a deposit until the closing in February 2006. Internal funds of Aurora were used to pay the net transaction cost of these transactions.

Cash Flows Provided by Financing Activities

Cash flows provided by financing activities were $51.7 million in 2007 compared to $73.9 million in 2006. Cash flows provided in 2007 included: 1) $55.0 million of senior secured credit borrowing; 2) $50.0 million of second lien term loan; and 3) $0.2 million of net proceeds received from exercise of common stock options and warrants. Cash flows used in 2007 included: 1) $40.0 million pay-down of the mezzanine financing; 2) net pay-down of $0.5 million in short-term bank borrowings; 3) $9.0 million pay-down of the senior secured credit facility; 4) pay-down of $0.3 million in mortgage obligations; 5) payment of $1.9 million of prepayment penalties associated with debt extinguishment; and 6) payment of $1.75 million in financing fees.

Cash flows provided by financing activities were $73.9 million in 2006 compared to $49.1 million in 2005. Cash flows provided in 2006 included: 1) $60.0 million of senior secured credit borrowing, of which, $27.6 million was paid directly for the Hudson acquisition; 2) $54.5 million of proceeds from public equity offering; and 3) $17.6 million of net proceeds received from exercise of common stock options and warrants and rescission of certain officer exercised stock options. Cash flows used in 2006 included: 1) net pay-down of $5.8 in short-term bank borrowings; 2) $50.0 million pay-down of the senior secured credit facility; 3) pay-down of $0.1 million in mortgage obligations; and 4) payment of $2.5 million in financing fees.

Cash flows provided by financing activities in 2005 included: 1) $14.7 million of proceeds received from sales of common stock; 2) $30.0 million of mezzanine borrowing; 3) $2.9 million of mortgage obligation to purchase office space; and 4) $5.9 million of net short-term bank borrowings. Cash flows used by financing in 2005 included: 1) pay-off of $3.0 million of certain related-party notes; 2) distributions of $0.8 million to minority interest members for their proportionate share of the El Paso sale proceeds; and 3) pay-down of $0.5 million in financing fees.

CRITICAL ACCOUNTING POLICIES

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. The reported financial results and disclosures were determined using the significant accounting policies, practices and estimates described in the notes to the consolidated financial statements. We believe that the reported financial results are reliable and the ultimate actual results will not differ materially from those reported. Uncertainties associated with the methods, assumptions and estimates underlying our critical accounting measurements are discussed below.

Use of Estimates

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

Oil and Gas Properties

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

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

Oil and Gas Reserves

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

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

Stock-Based Compensation

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

For the years ended December 31, 2007 and 2006, we recorded the following stock-based compensation:

For the Years Ended December 31,	2007		2006
General and administrative expenses	$	2,222,200	$	2,206,801
Oil and natural gas properties		175,795		457,013
Total	$	2,397,995	$	2,663,814

The impact on future net income is estimated to be $1,105,949 recognized over the applicable requisite service period of approximately 3 years.

Income Taxes

We have adopted the provisions of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (“SFAS No. 109”). Under the asset and liability method of SFAS No. 109, deferred tax assets and liabilities are recognized for future tax consequences attributable to the differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted income tax rates to apply to taxable income in the years in which those differences are expected to be recovered or settled. Under SFAS No. 109, the effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. At December 31, 2007, we had approximately $85.1 million of net operating loss carryforwards which expire between 2010 and 2027.

SIGNIFICANT ACCOUNTING PRINCIPLES RELATING TO THE MERGER

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

●

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

●

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

●

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

●

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

RECENTLY ISSUED ACCOUNTING STANDARDS

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

On February 15, 2007, the FASB issued SFAS 159, “Fair Value Option for Financial Assets and Financial Liabilities”—including an amendment of SFAS Statement No. 115 (“SFAS 115”). SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value. The FASB believes the statement will improve financial reporting by providing companies the opportunity to mitigate volatility in reported earnings by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Use of the statement will expand the use of fair value measurements for accounting for financial instruments. The provisions of SFAS 159 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Management does not anticipate the adoption of this standard to have a material impact on our consolidated financial statements.

In November 2007, the FASB issued SFAS 141 (revised 2007), “Business Combination” (“SFAS 141R”) and SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (“SFAS 160”). SFAS 141R will change how business acquisitions are accounted for and will impact financial statements both on the acquisition date and in subsequent periods. SFAS 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 141R and SFAS 160 are effective for fiscal years beginning on or after December 15, 2008. SFAS 141R will be applied prospectively. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 will be applied prospectively. Early adoption is prohibited for both standards. Management is currently evaluating the requirements of SFAS 141R and SFAS 160 and has not yet determined the impact on its consolidated financial statements.

OFF BALANCE SHEET ARRANGEMENTS

We have no special purpose entities, financing partnerships, guarantees, or off-balance sheet arrangements other than the $1.2 million of outstanding letters of credit discussed in Note 11 “Commitments and Contingencies” to our consolidated financial statements.

CONTRACTUAL OBLIGATIONS

The following summarizes our contractual obligations as of December 31, 2007, and the effect such obligations are expected to have on our liquidity and cash flow in future periods (in thousands):

	Total		2008		2009		2010		2011		2012		2013 and thereafter
Long-term debt	$	106,000		-		-	$	56,000		-	$	50,000		-
Interest on long-term debt (a)		34,493		9,206		9,223		6,342		5,953		3,769		-
Notes and mortgage payable		3,302		189		550		171		2,392		-		-
Capital leases		7		6		1		-		-		-		-
Land and mineral leases (b)		6,626		476		1,364		2,553		1,693		540		-
Operating leases		3,784		649		612		611		611		611		690
Total contractual cash obligations	$	154,212	$	10,526	$	11,750	$	65,677	$	10,649	$	54,920	$	690

(a) Amounts estimated based on current interest rates.

(b) Amount represents lease renewal options available to the Company. Renewal options are evaluated on a periodic basis and, based on those evaluations, the amount stated above may be lower.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Period	Type of Contract		Natural Gas Volume per Day		Price per mmbtu		Fair Value Asset (Liability)
April 2007—December 2008		Swap		5,000 mmbtu	$	9.00	$	1,881,500
April 2007—December 2008		Collar		2,000 mmbtu	$	7.55/$ 9.00		45,770
January 2008—December 2008		Swap		2,000 mmbtu	$	8.41		320,720
January 2009—December 2009		Swap		7,000 mmbtu	$	8.72		104,899
January 2010—March 2011		Swap		7,000 mmbtu	$	8.68		(534,402	)
April 2011—September 2011		Swap		7,000 mmbtu	$	7.62		(944,668	)
Total estimated fair value							$	873,819

Interest Rate Risk

Our use of debt directly exposes us to interest rate risk. Our policy is to manage interest rate risk through the use of a combination of fixed and floating rate debt. Interest rate swaps may be used to adjust interest rate exposure when appropriate. In August 2007, we entered into a 3-year interest rate swap agreement in the notional amount of $50 million with BNP to hedge our exposure to the floating interest rate on the $50 million second lien term loan. The swap converted the debt’s floating 3-month LIBOR base to 4.86% fixed base. This swap on $50 million will yield an effective interest rate of 11.86% for the period from August 23, 2007 through August 23, 2010, on the second lien term loan. Fair value liability of the interest rate swap agreement at December 31, 2007, amounted to $1,258,861.

The following table sets forth our principal financing obligation and the related interest rates as of December 31, 2007:

	Expected Maturity		Average Interest Rate as of December 31, 2007		Principal Outstanding
Obligations under capital lease		01/10/09		8.25%	$	7,784
Notes payable		08/01/07-04/25/11		5.50% - 7.50%		219,478
Mortgage payable		10/15/09		Fixed at 6.00%		369,408
Mortgage payable		2/08/11		Fixed at 6.50%		2,712,788
Second lien term loan		08/20/12		Hedged at 11.86%		50,000,000
Senior secured credit facility		01/31/10		Variable - 6.93%		56,000,000
Total debt					$	109,309,458

While our senior secured facility exposes us to the risk of rising interest rates, management does not believe that the potential exposure is material to our overall financial position or results of operations. Based on current borrowing levels, a 1.0% increase or decrease in current market interest rates would have the effect of causing $0.6 million additional charge or reduction to our statement of operations.

ITEM 8. FINANCIAL STATEMENTS

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page

Management’s Report on Internal Control Over Financial Reporting	50
Reports of Independent Registered Public Accounting Firms	51-52

Consolidated Financial Statements
Consolidated Balance Sheets as of December 31, 2007 and 2006	53-54
Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005	55
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2007, 2006 and 2005	56
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005	57-58
Notes to Consolidated Financial Statements	59
Supplemental Oil and Natural Gas Information (Unaudited)	85

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

It is the responsibility of management of Aurora Oil & Gas Corporation to establish and maintain adequate internal control over the financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Management utilized the Committee of Sponsoring Organizations of the Treadway Commission’s Internal Control—Integrated Framework (COSO framework) in conducting the required assessment of effectiveness of the Company’s internal control over financial reporting.

Management has performed an assessment of the effectiveness of the Company’s internal control over financial reporting and has determined the Company’s internal control over financial reporting was effective as of December 31, 2007.

Our management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007, has been attested by Weaver and Tidwell, L.L.P., an independent registered public accounting firm, as stated in its report which appears herein.

William W. Deneau

Chairman, Director, and Chief Executive Officer

Barbara E. Lawson

Chief Financial Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Aurora Oil & Gas Corporation

Traverse City, Michigan

We have audited the accompanying consolidated balance sheet of Aurora Oil & Gas Corporation (the Company) as of December 31, 2007, and the related consolidated statements of operations, shareholders’ equity and cash flows for the year then ended. We have also audited Aurora Oil & Gas Corporation’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Aurora Oil & Gas Corporation’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting . Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the company’s internal control over financial reporting 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of the financial statements included 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, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Aurora Oil & Gas Corporation at December 31, 2007, and the consolidated results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America. Also i n our opinion, Aurora Oil & Gas Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.

WEAVER AND TIDWELL, L.L.P.

Fort Worth, Texas

March 7, 2008

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Aurora Oil & Gas Corporation and Subsidiaries

Traverse City, Michigan

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

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

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

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

RACHLIN LLP

(formerly known as Rachlin Cohen & Holtz LLP)

Miami, Florida

March 13, 2007

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS


	December 31,			December 31,
	2007			2006
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,425,678		$	1,735,396
Accounts receivable:
Oil and natural gas sales		5,036,416			4,082,231
Joint interest owners		851,638			3,079,715
Notes receivable		-			341,698
Prepaid expenses and other current assets		765,730			251,093
Short-term derivative instruments		2,247,990			3,552,060
Total current assets		11,327,452			13,042,193

PROPERTY AND EQUIPMENT:
Oil and natural gas properties, using full cost accounting:
Proved properties		167,282,245			121,178,499
Unproved properties		56,937,683			42,024,648
Properties held for sale		-			8,896,568
Less: accumulated depletion and amortization		(14,401,584	)		(10,628,438	)
Total oil and natural gas properties, net		209,818,344			161,471,277
Other property and equipment:
Pipelines, processing facilities, and compression		6,469,336			6,125,909
Other property and equipment		5,450,452			5,093,777
Less: accumulated depreciation		(1,554,189	)		(753,789	)
Total other property and equipment, net		10,365,599			10,465,897
Total property and equipment, net		220,183,943			171,937,174

OTHER ASSETS:
Long-term derivative instruments		-			1,668,573
Goodwill		19,373,264			19,373,264

Intangibles (net of accumulated amortization of $4,497,920 and $2,946,250, respectively)		457,080			2,008,750
Other investments		733,836			985,706
Debt issuance costs (net of accumulated amortization of $360,972 and $892,535, respectively)		1,661,603			2,363,898
Other		934,490			1,007,634
Total other assets		23,160,273			27,407,825

TOTAL ASSETS	$	254,671,668		$	212,387,192

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

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS


	December 31,			December 31,
	2007			2006
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	6,490,981		$	5,623,591
Accrued exploration, development, and leasehold costs		1,341,917			11,587,850
Short-term bank borrowings		-			542,788
Current portion of obligations under capital leases		6,288			8,868
Current portion of note payable		76,416			161,774
Current portion of mortgage payable		112,326			95,828
Drilling advances		168,356			19,383
Short-term derivative instruments		384,706			-
Total current liabilities		8,580,990			18,040,082

LONG-TERM LIABILITIES:
Obligations under capital leases, net of current portion		1,496			8,228
Asset retirement obligation		1,494,745			1,331,893
Notes payable		143,062			118,547
Mortgage payable		2,969,870			3,079,470
Senior secured credit facility		56,000,000			10,000,000
Second lien term loan		50,000,000			-
Mezzanine financing		-			40,000,000
Long-term derivative instruments		2,248,326			-
Other long-term liabilities		977,529			-
Total long-term liabilities		113,835,028			54,538,138
Total liabilities		122,416,018			72,578,220

Minority interest in net assets of subsidiaries		112,661			77,873

COMMITMENTS, CONTINGENCIES, AND SUBSEQUENT EVENTS (Note 11 and Note 16)

SHAREHOLDERS' EQUITY:
Common stock, $0.01 par value; authorized 250,000,000 shares; issued and outstanding 101,769,456 and 101,412,966 shares, respectively		1,017,695			1,014,130
Additional paid-in capital		140,541,460			138,105,626
Accumulated other comprehensive income (loss)		(385,043	)		5,220,633
Accumulated deficit		(9,031,123	)		(4,609,290	)
Total shareholders' equity		132,142,989			139,731,099

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	254,671,668		$	212,387,192

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

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2007			2006			2005
REVENUES:
Oil and natural gas sales	$	26,723,818		$	21,591,811		$	6,743,444
Pipeline transportation and processing		792,587			489,473			-
Field service and sales		390,401			125,611			-
Interest and other		549,149			220,592			666,850
Total revenues		28,455,955			22,427,487			7,410,294

EXPENSES:
Production taxes		1,123,070			877,319			506,635
Production and lease operating expenses		8,761,445			5,966,341			1,587,205
Pipeline and processing operating expenses		359,865			265,795			-
Field services expenses		321,753			90,913			-
General and administrative expenses		8,029,122			7,531,718			3,435,507
Oil and natural gas depletion and amortization		3,769,104			2,681,290			767,511
Other assets depreciation and amortization		2,396,026			2,083,191			308,647
Interest expense		4,582,021			4,573,785			1,307,370
Loss on debt extinguishment		3,448,520			-			-
Taxes, other		19,021			250,884			29,651
Total expenses		32,809,947			24,321,236			7,942,526

LOSS BEFORE MINORITY INTEREST		(4,353,992	)		(1,893,749	)		(532,232	)

MINORITY INTEREST IN (INCOME) LOSS OF SUBSIDIARIES		(67,841	)		(50,898	)		15,960

NET LOSS	$	(4,421,833	)	$	(1,944,647	)	$	(516,272	)

NET LOSS PER COMMON SHARE—BASIC and DILUTED	$	(0.04	)	$	(0.02	)	$	(0.01	)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING—BASIC and DILUTED		101,633,162			82,288,243			40,622,000

Supplemental Information

Net loss for the years ended December 31, 2007, 2006, and 2005, included stock-based compensation expense of $2,222,200, $2,206,801, and none, respectively, under Statement of Financial Accounting Standards No. 123 (revised 2004). See Note 10 “Common Stock Options” for additional information.

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

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

	Year Ended December 31,
	2007						2006						2005
	Shares			Amount			Shares			Amount			Shares		Amount
COMMON STOCK:
Balance, beginning		101,412,966		$	1,014,130			61,536,261		$	615,363			13,775,933	$	13,776
Cashless exercise of stock options and warrants		78,158			782			3,280,105			32,801			245,068		2,451
Conversion of redeemable convertible preferred stock to common stock		-			-			34,984			349			298,050		298
Issuance of stock in private placement, net of commissions and fees		-			-			-			-			4,972,200		4,972
Exercise of stock options prior to merger		-			-			-			-			10,000		10
Issuance of stock in connection with the merger between Cadence and Aurora		-			-			-			-			39,592,510		567,431
Exercise of stock options and warrants		353,332			3,533			15,823,457			158,235			2,642,500		26,425
Issuance of stock in connection with public equity offering		-			-			19,600,000			196,000			-		-
Issuance of stock in connection with an acquisition		-			-			1,378,299			13,783			-		-
Issuance of stock to officers and directors in lieu of compensation		-			-			90,000			900			-		-
Issuance of stock to related parties in lieu of commission relating to exercise of warrants		-			-			1,469,860			14,699			-		-
Rescission of stock option exercises by certain officers		-			-			(1,800,000	)		(18,000	)		-		-
Adjustment to stock ledger		(75,000	)		(750	)		-			-			-		-
Balance, ending		101,769,456			1,017,695			101,412,966			1,014,130			61,536,261		615,363
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning					138,105,626						58,670,698					8,183,025
Cashless exercise of stock options and warrants					(782	)					(32,801	)				(2,451	)
Conversion of redeemable convertible preferred stock to common stock					-						59,576					148,727
Issuance of stock in private placement, net of commissions and fees					-						-					11,020,028
Exercise of stock options prior to merger					-						-					7,490
Issuance of stock in connection with the merger between Cadence and Aurora					-						-					35,706,179
Stock-based compensation					2,397,995						2,663,814					-
Exercise of stock options and warrants					194,967						18,143,714					3,607,700
Issuance of stock in connection with public equity offering					(10,096	)					54,309,807					-
Issuance of stock in connection with an acquisition					-						4,686,217					-
Issuance of stock to officers and directors in lieu of compensation					-						348,300
Issuance of stock to related parties in lieu of commission relating to exercise of warrants					-						(14,699	)				-
Rescission of stock option exercises by certain officers					-						(729,000	)				-
Adjustment to stock ledger					(146,250	)					-					-
Balance, ending					140,541,460						138,105,626					58,670,698
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
Balance, beginning					5,220,633						-					-
Changes in fair value of derivative instruments					(1,679,507	)					7,903,933					-
Recognition of gain on derivative instruments					(3,926,169	)					(2,683,300	)				-
Balance, ending					(385,043	)					5,220,633					-
ACCUMULATED DEFICIT:
Balance, beginning					(4,609,290	)					(2,660,134	)				(2,099,522	)
Dividends accrued on redeemable convertible preferred stock					-						(4,509	)				(44,340	)
Net loss					(4,421,833	)					(1,944,647	)				(516,272	)
Balance, ending					(9,031,123	)					(4,609,290	)				(2,660,134	)
TOTAL SHAREHOLDERS’ EQUITY				$	132,142,989					$	139,731,099				$	56,625,927

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

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2007			2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(4,421,833	)	$	(1,944,647	)	$	(516,272	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization		6,165,130			4,764,481			1,076,158
Amortization of debt issuance costs		779,943			813,715			79,096
Accretion of asset retirement obligation		76,768			74,097			-
Loss on debt extinguishment		3,448,520			-			-
Stock-based compensation		2,222,200			2,206,801			-
Equity loss of other investments and other		(317,367	)		291,890			116,372
Realized gain on sale of other investments		(434,849	)		-			-
Minority interest income (loss) of subsidiaries		67,841			50,899			(15,960	)
Changes in operating assets and liabilities:
Accounts receivable—oil and natural gas sales		(954,185	)		(785,126	)		(516,624	)
Accounts receivable—joint interest owners		2,562,020			1,182,819			(3,294,953	)
Drilling advance—liabilities		148,973			19,383			(387,175	)
Notes receivable		221,788			20,720			(12,621	)
Prepaid expenses and other assets		(1,838	)		(1,105,539	)		41,634
Accounts payable and accrued liabilities		515,938			(121,583	)		1,025,606
Net cash provided by (used in) operating activities		10,079,049			5,467,910			(2,404,739	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and natural gas properties		(51,955,565	)		(42,776,914	)		(29,087,260	)
Leasehold expenditures, net		(11,960,049	)		(28,975,878	)		(18,283,002	)
Acquisition of oil and natural gas properties		(2,405,609	)		(24,011,335	)		-
Sale of oil and natural gas properties		2,079,518			11,489,456			11,504,428
Sale and leaseback of gas compression equipment		3,844,500			-			-
Acquisitions/additions for pipeline, property, and equipment		(1,586,328	)		(4,647,497	)		(4,523,706	)
Additions in other investments		(186,334	)		(855,070	)		(485,741	)
Sales of other investments		1,069,378			171,140
Other		-			-			48,935
Net cash acquired in merger		-			-			957,020
Net cash used in investing activities		(61,100,489	)		(89,606,098	)		(39,869,326	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term bank borrowings		16,412,822			5,580,199			6,210,000
Short-term bank payments		(16,955,610	)		(11,355,827	)		(350,000	)
Advances on senior secured credit facility		55,000,000			60,000,000			-
Payments on senior secured credit facility		(9,000,000	)		(50,000,000	)		-
Advances on mezzanine financing		-			-			30,000,000
Payments on mezzanine financing		(40,000,000	)		-			-
Advances on second lien term loan		50,000,000			-			-
Payments on mortgage obligations and notes payable		(272,471	)		(73,205	)		2,865,477
Payments of financing fees on credit facilities		(1,691,371	)		(2,452,786	)		(508,542	)
Prepayment penalties on debt extinguishment		(1,866,580	)		-			-
Capital contributions from minority interest members		16,786			-			-
Distributions to minority interest members		(49,839	)		-			(805,000	)
Proceeds from sales of common stock		-			54,505,807			14,666,625
Proceeds from exercise of options and warrants		198,500			17,554,949			-
Dividends paid on preferred stock		-			(20,250	)		(44,340	)
Other		(80,515	)		154,059			(2,959,099	)
Net cash provided by financing activities		51,711,722			73,892,946			49,075,121

Net increase (decrease) in cash and cash equivalents		690,282			(10,245,242	)		6,801,056
Cash and Cash equivalents, beginning of the period		1,735,396			11,980,638			5,179,582
Cash and cash equivalents, end of the period	$	2,425,678		$	1,735,396		$	11,980,638

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2007		2006		2005
NONCASH FINANCING AND INVESTING ACTIVITIES:
Oil and natural gas properties asset retirement obligation	$	116,324	$	1,257,796	$	-
Accrued exploration and development costs on oil and natural gas properties		947,109		11,161,730		1,464,032
Accrued leasehold costs		394,808		426,120		516,890
Properties acquired in connection with Cadence merger in exchange for equity
—Oil and natural gas properties		-		-		14,647,614
—Intangibles and goodwill		-		-		20,578,346
—Other investments		-		-		1,701,238
Field service acquisition through common stock issuance, including $600,000 of unproven leasehold		-		4,686,217		-
Pipeline acquisition, transfer of investment to pipeline costs		-		1,100,973		-
Processing facilities and compression, transfer from unproven properties		1,244,669		-		-
Oil and natural gas properties capitalized stock-based compensation		175,795		457,013		-
Oil and natural gas properties acquisition through other long-term liability		600,000		-		-
Conversion of redeemable convertible preferred stock to common stock		-		59,925		-
Conversion of accounts receivable to notes receivable		35,469		118,072		-
Vehicle purchase through financing		118,526		-		-
SUPPLEMENTAL INFORMATION OF INTEREST AND INCOME TAXES PAID:
Interest, net of amount capitalized of $4,508,767, $3,896,645, and $1,146,084, respectively	$	2,811,714	$	3,389,966	$	1,069,661
Income taxes		107,700		6,629		40,994

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

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS

Aurora Oil & Gas Corporation (“AOG”) and its wholly owned subsidiaries (collectively, the “Company”) is a growing independent energy company focused on the exploration, development, and production of unconventional natural gas reserves. The Company generates most of its revenue from the production and sale of natural gas. The Company is currently focused on acquiring and developing operating interests in unconventional drilling programs in the Michigan Antrim shale, the New Albany shale of Indiana and Kentucky and the Woodford shale in Oklahoma. The Company is a Utah corporation whose common stock is listed and traded on the American Stock Exchange.

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

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

Principles of Consolidation

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

As a result of the reverse acquisition discussed in Note 6 “Merger with Aurora Energy, Ltd.,” the historical financial statements presented for the period prior to the acquisition date of October 31, 2005 are the financial statements of Aurora. The operations of the former Cadence Resources Corporation (“Cadence”) businesses have been included in the financial statements from the date of acquisition. The common stock per share information in the consolidated financial statements for the year ended December 31, 2005, and related notes have been retroactively adjusted to give effect to the reverse merger on October 31, 2005.

Use of Estimates

Reclassifications

Certain reclassifications have been made to consolidated financial statements for 2006 and 2005 in order to conform to the presentation used for the 2007 consolidated financial statements. These reclassifications had no effect on net loss or net cash flows as previously reported.

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Cash and Cash Equivalents

The Company considers all highly liquid investments with an initial maturity of 3 months or less to be cash equivalents. The Company’s bank accounts periodically exceed federally insured limits. As of December 31, 2007, cash in excess of FDIC limits amounted to approximately $1.7 million. The Company maintains its deposits with high quality financial institutions and, accordingly, believes its credit risk exposure associated with cash is remote.

Accounts Receivable and Credit Policy

Accounts receivable generally consist of amounts due from the sale of oil and natural gas and from working interest partners for their proportionate share of expenses related to certain oil and natural gas projects. Each customer and/or partner is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. When collections of specific amounts due are no longer reasonably assured, an allowance for doubtful accounts is established.

The Company extends credit, primarily in the form of uncollateralized oil and natural gas sales and joint interest owner's receivables, to various companies in the oil and natural gas industry which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within the industry and may accordingly impact the Company’s overall credit risk. However, the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which the Company extends credit.

Capitalized Interest

The Company capitalizes interest on debt related to expenditures made in connection with exploration and development projects that are not subject to the full cost amortization pool. Interest is capitalized only for the period that exploration and development activities are in progress. Interest is capitalized using a weighted average interest rate based on the outstanding borrowing and cost of equity of the Company. Capitalized interest was $4,508,767, $3,896,645, and $1,146,084 for the years ended December 31, 2007, 2006, and 2005, respectively.

Oil and Natural Gas Properties

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

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

The following table sets forth financial data associated with unproved oil and natural gas properties costs at December 31, 2007:

	Balance as of		Net Costs Incurred During the Year Ended December 31,
	December 31, 2007		2007		2006			2005		2004 and prior
Acquisition costs	$	37,004,553	$	6,516,149	$	8,695,056		$	13,811,621	$	7,981,727
Development costs		19,933,130		5,458,271		(1,011,683	)		15,486,542		-
Total unproved properties	$	56,937,683	$	11,974,420	$	7,683,373		$	29,298,163	$	7,981,727

Interest costs capitalized on unproved properties during the years ended December 31, 2007, and 2006, totaled $5,596,880 and $3,805,503, respectively. No interest was capitalized during the year ended December 31, 2005.

Asset Retirement Obligation

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

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

Effective January 1, 2007, the accretion of the ARO on producing wells was adjusted for a change in the estimated life of the wells based on a reserve study prepared by Data & Consulting Services, Division of Schlumberger Technology Corporation, an independent reserve engineering firm. The estimated life of the wells was increased by 10 years to an estimated life of 50 years per well resulting in a reduction of $625,241 to estimated liabilities. In addition, revisions of estimated liabilities included increases due to removal of equipment salvage value totaling $97,062 and a decrease in the estimated well plugging costs for certain non-Antrim wells totaling $32,409. Revisions of estimated liabilities for 2006 included reductions in well working interest totaling $55,358 and increases in the salvage value of equipment totaling $94,900.

The change in the ARO for the year ended December 31, 2007 and 2006 is as follows:

	2007			2006

Beginning balance	$	1,331,893		$	812,634
Liabilities incurred		707,926			719,229
Liabilities settled		(62,254	)		(123,809	)
Accretion expense		76,768			74,097
Revisions of estimated liabilities		(559,588	)		(150,258	)
Ending balance	$	1,494,745		$	1,331,893

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Other Property and Equipment

Other property and equipment are recorded at original cost and depreciated using the straight-line method over the estimated useful lives. Major improvements, replacements, and renewals are capitalized while ordinary maintenance and repairs are expensed as incurred. Long-lived assets, other than oil and natural gas properties, are evaluated annually for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses for the years ended December 31, 2007, 2006 and 2005. A summary of the other property and equipment for the year ended December 31, 2007 and 2006 and the useful lives are as follows:

	2007			2006			Useful Life in Years

Pipelines	$	5,071,144		$	4,881,240			15
Processing facilities and compression		1,389,121			1,241,162			10
Building		9,071			3,507			30
Total pipelines, processing facilities and compression		6,469,336			6,125,909
Less: accumulated depreciation		(818,138	)		(412,591	)
Pipelines, processing facilities, and compression, net	$	5,651,198		$	5,713,318

Land	$	78,000		$	78,000			N/A
Buildings		3,552,392			3,552,392			40
Furniture and fixtures		328,841			328,173			5-10
Office equipment		68,321			65,781			5
Computer equipment		251,894			234,782			5
Software		256,578			188,434			3-5
Vehicles and other equipment		914,427			646,215			5
Total other property and equipment		5,450,452			5,093,777
Less: accumulated depreciation		(736,051	)		(341,198	)
Other property and equipment, net	$	4,714,401		$	4,752,579

Other Investments

The Company uses the equity method of accounting for investments in entities in which the Company has an ownership interest between 20% and 50% and exercises significant influence. Under the equity method of accounting, the Company’s proportionate share of the investees’ net income or loss is included in the results of operations as other income. A summary of the other investments for the years ended December 31, 2007 and 2006, are as follows:

	2007		2006
Investments in equity method investees:
GeoPetra Partners, LLC	$	528,136	$	721,596
Mineral properties		204,628		197,406
Other		1,072		66,704
Total other investments	$	733,836	$	985,706

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Equity investments are deemed immaterial. Therefore, financial information is not presented.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of net assets acquired. The Company follows SFAS No. 142, “Goodwill and Other Intangible Assets,” which requires that goodwill and intangible assets with indefinite useful lives not to be amortized but written down, as needed, based on an impairment test that must occur at least annually or sooner if an event occurs or circumstances change that would more likely than not result in an impairment loss. The amount of goodwill impairment, if any, is measured on projected discounted future operating cash flows using a 10% discount rate. Future impairment of goodwill could result if the Company’s estimated future operating cash flows are not achieved. No impairment loss was recorded for the years ended December 31, 2007, 2006 and 2005, respectively.

Intangible Assets

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

2008	$	194,581
2009		66,666
2010		66,666
2011		66,667
2012		62,500
	$	457,080

Revenue Recognition

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

Sales and Major Customers

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

For the year ended December 31, 2007, two gas marketing firms accounted for 56% of total oil and natural gas revenues. For the year ended December 31, 2006, one gas marketing firm accounted for 62% of total oil and natural gas revenues. For the year ended December 31, 2005, one gas marketing firm accounted for 56% of total oil and natural gas revenues.

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Stock-Based Compensation

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

Prior to 2006, the Company applied APB No. 25 and related interpretations in accounting for its plans. Under APB 25, if the exercise price of the stock options was greater than the market value of the shares at the date of grant, no compensation cost was recognized in the consolidated financial statements. If the Company had applied the fair value recognition provisions of SFAS 123R during the year ended December 31, 2005, there would have been additional stock-based compensation expense of $298,745 with a pro forma net loss of $815,017 or $(0.02) per share based on basic and diluted.

For the years ended December 31, 2007 and 2006, the Company recorded the following stock-based compensation:

For the Years Ended December 31,	2007		2006
General and administrative expenses	$	2,222,200	$	2,206,801
Oil and natural gas properties		175,795		457,013
Total	$	2,397,995	$	2,663,814

The following table provides the unrecognized compensation expense related to unvested stock options as of December 31, 2007. The expense is expected to be recognized over the following remaining periods indicated:

Period to be Recognized	2008		2009		2010
1 ^st Quarter	$	441,781	$	37,255	$	1,146
2 ^nd Quarter		371,364		16,532		-
3 ^rd Quarter		125,070		6,284		-
4 ^th Quarter		103,561		2,956		-
Total	$	1,041,776	$	63,027	$	1,146

Income Taxes

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. With few exceptions, the Company is no longer subject to U.S. federal, state, and local examinations by tax authorities for years before 2003. The Company is currently not under an examination by any U.S. federal, state, or local tax authorities.

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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

In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of SFAS 109” (“FIN 48”). This interpretation clarifies the application of SFAS 109 by defining the criterion that an individual tax position must meet for any part of the benefit of that position to be recognized in an entity’s financial statements and also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, and disclosure. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. The Company adopted the provisions of FIN 48 on January 1, 2007. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements. No liabilities or assets have been recognized as a result of the implementation of Interpretation 48.

As of December 31, 2007, the Company had approximately $10 million of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the Company’s significant unutilized tax net operating loss carry-forwards, the disallowance of the shorter deductibility period would not accelerate the payment of cash to the taxing authorities to an earlier period or result in any interest of penalty for tax underpayment. In addition, because of the impact of deferred tax accounting, the disallowance of the shorter deductibility period would not affect the annual effective tax rate of the Company. Accordingly, the Company has not recognized any penalty, interest or tax impact from this uncertain tax position.

Comprehensive Income (Loss)

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

	Years Ended December 31,
	2007			2006			2005
Net Loss	$	(4,421,833	)	$	(1,944,647	)	$	(516,272	)
Other comprehensive income:
Changes in fair value of natural gas derivative instruments		(472,335	)		7,903,933			-
Changes in fair value of interest rate derivative instruments		(1,207,172	)		-			-
Recognition of gains on derivative instruments		(3,926,169	)		(2,683,300	)		-
		(5,605,676	)		5,220,633			-
Comprehensive Income (Loss)	$	(10,027,509	)	$	3,275,986		$	(516,272	)

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Income (Loss) Per Share

Basic net income (loss) per common share is computed based on the weighted average number of common shares outstanding during each period. Diluted net income (loss) per common share is computed based on the weighted average number of common shares outstanding plus other dilutive securities, such as stock options, warrants, and redeemable convertible preferred stock. The following securities were not included in the computation of diluted net income (loss) per share as their effect would have been anti-dilutive:

	2007		2006		2005
Options to purchase common stock		2,175,280		766,500		1,120,640
Warrants to purchase common stock		-		-		15,560,000
Convertible preferred stock		-		-		34,950
		2,175,280		766,500		16,715,590

NOTE 3. RECENT ACCOUNTING PRONOUNCEMENTS

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

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 4. RISK MANAGEMENT ACTIVITIES

Natural Gas Derivative Instruments

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

The Company recognizes all derivative instruments as assets or liabilities in the balance sheet at fair value. The accounting treatment for changes in fair value, as specified in SFAS No. 133 “Accounting for Derivative Investments and Hedging Activities,” is dependent upon whether or not a derivative instrument is designated as a hedge. For derivatives designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in Accumulated Other Comprehensive Income on the accompanying balance sheet until the hedged item is recognized in earnings as natural gas revenue. If the hedge has an ineffective portion, that particular portion of the gain or loss would be immediately reported in earnings. The following natural gas contracts were in place as of December 31, 2007, and qualified as cash flow hedges:

Period	Type of Contract		Natural Gas Volume per Day		Price per mmbtu		Fair Value Asset (Liability)
April 2007—December 2008		Swap		5,000 mmbtu	$	9.00	$	1,881,500
April 2007—December 2008		Collar		2,000 mmbtu	$	7.55/$ 9.00		45,770
January 2008 - December 2008		Swap		2,000 mmbtu	$	8.41		320,720
January 2009—December 2009		Swap		7,000 mmbtu	$	8.72		104,899
January 2010—March 2011		Swap		7,000 mmbtu	$	8.68		(534,402	)
April 2011 – September 2011		Swap		7,000 mmbtu	$	7.62		(944,668	)
Total Estimated Fair Value							$	873,819

For the year ended December 31, 2007, the Company has recognized in Comprehensive Income (Loss) changes in fair value of $(472,335) on the contracts that have been designated as cash flow hedges on forecasted sales of natural gas. See “Comprehensive Income (Loss)” found in this note section. For the year ended December 31, 2007, and 2006, the Company recognized $3,874,480 and $2,683,300, respectively, in net gains from hedging activities included in oil and natural gas revenues.

Interest Rate Derivative Instruments

The Company’s use of debt directly exposes it to interest rate risk. The Company’s policy is to manage interest rate risk through the use of a combination of fixed and floating rate debt. Interest rate swaps may be used to adjust interest rate exposure when appropriate. These derivatives are used as hedges and are not for speculative purposes. These derivatives involve the exchange of amounts based on variable interest rates and amounts based on a fixed interest rate over the life of the agreement without an exchange of the notional amount upon which payments are based. The interest rate differential to be received or paid on the swaps is recognized over the lives of the swaps as an adjustment to interest expense.

In August 2007, the Company entered into a 3-year interest rate swap agreement in the notional amount of $50 million with BNP to hedge its exposure to the floating interest rate on the $50 million second lien term loan. The swap converted the debt’s floating three month LIBOR base to 4.86% fixed base. This swap on $50 million will yield an effective interest rate of 11.86% for the period from August 23, 2007 through August 23, 2010 on the second lien term loan.

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

For the year ended December 31, 2007, the Company has recognized in Comprehensive Income (Loss) changes in fair value of $(1,207,172) on the interest rate swap. See “Comprehensive Income (Loss)” found in this note section. For the year ended December 31, 2007, the Company recognized $51,689 in interest savings related to the hedge activity which is recorded as an adjustment to interest expense. Fair value liability of the interest rate swap agreement at December 31, 2007, amounted to $1,258,861.

Financial Instruments

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

NOTE 5. ACQUISITIONS AND DISPOSITIONS

2007 – Rex Energy Exercised Option to Acquire Interest in Oil and Natural Gas Leases

On September 7, 2007, Rex Energy Corporation exercised an option to acquire a 30% working interest in various undeveloped oil and natural gas leases located in the New Albany shale for approximately $1.1 million. The interest in oil and gas leases covers approximately 70,324 (21,097 net) acres in Lawrence, Jackson, Washington and Orange Counties, Indiana.

2007 – GFS and Federated Oil and Gas Properties

On August 31, 2007, the Company entered into two Purchase Letter Agreements to buy GFS Energy, Inc. and Federated Oil & Gas Properties, Inc. non-operated working interests and overriding royalty interests in various developed oil and natural gas properties located in the Antrim shale for approximately $3.0 million. The properties included 93 (33 net) wells, producing approximately 500 mcfe per day, and approximately 4,700 (1,706 net) acres. This transaction had an effective date of September 1, 2007.

2007 – Knox County, Indiana

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

2007 – Mining Claims

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

2007 – Kansas Project

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

2007 – Other Investments

From time to time, the Company has acquired and disposed of legacy Cadence stock investments and non-core working interests. For the year ended December 31, 2007, the Company recognized minor stock investments valued at approximately $290,000 and disposed of non-core working interests and stock investments of approximately $490,000.

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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

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

The total purchase price for the Hudson Properties and HPPC was approximately $27.6 million. North also acquired an additional 2.5% membership interest in HPPC, effective January 1, 2006, which increased the membership interest to 93.60%.

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

2006 – Wabash Project

On February 2, 2006, Aurora closed on two Purchase and Sale Agreements with respect to certain New Albany Shale acreage located in Indiana, commonly called the Wabash project. Aurora acquired 64,000 acres of oil and natural gas leases from Wabash Energy Partners, L.P. for a purchase price of $11.84 million. The Company was required to deposit into escrow for the seller $3.2 million

Aurora then sold half its interest in a combined 95,000-acre lease position in the Wabash project to New Albany-Indiana, L.L.C. (“New Albany”), an affiliate of Rex Energy Operating Corporation, for a sale price of $10.5 million. Pursuant to the terms of this sales agreement, $3.5 million was placed in escrow by New Albany on behalf of the Company as a deposit until the closing in February 2006.

2006 – DeSoto Parish, Louisiana

On July 20, 2006, the Company entered into a Purchase and Sale Agreement with respect to the DeSoto Parish, Louisiana, properties to sell certain assets to BEUSA Energy, Inc. for a purchase price of $4.75 million. BEUSA Energy, Inc. is the current operator and joint interest owner in these properties. The properties included: (1) fourteen gross wells with working interest ranging from 22.5% to 45%; (2) 4,480 (1,657 net) acres; and (3) various pipelines and facilities. The effective date of the sale was July 1, 2006.

2006 – Crossroads Project, Henry, Ohio

Effective August 15, 2006, the Company agreed to assign all of its working interests in the Crossroads Project located in Henry County, Ohio, to an unrelated party. The 7.06% working interest included 15,519 (1,096 net) leasehold acres, 13 (0.92 net) wells, and pipeline assets. Aurora agreed to pay $251,225 for disposition costs but will receive future pipeline revenue over the life of the project.

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

2006 – Bach

On October 6, 2006, the Company closed on the purchase of all assets of Bach Enterprises, Inc., certain assets owned by Bach Energy, LLC, and a limited liability company known as Kingsley Development LLC (together “Bach”). Bach is primarily an oil and natural gas service company. The Company has been working exclusively with Bach as a service business in Michigan for several years. Services they have provided include building compressors, CO2 removal, pipelining, and facility construction. The purchase price included common stock and cash. The common stock issued was subject to a 1-year lock-up period. In addition, the Company entered into 5-year employment agreements with two principals of Bach who agreed not to compete during their employment and for a period of 1 year following termination of their employment.

NOTE 6. MERGER WITH AURORA ENERGY, LTD.

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

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

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

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

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

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

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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

	2005
	Historical			Pro Forma
Oil and natural gas revenues	$	6,743,444		$	8,821,869
Production expenses		(2,093,840	)		(2,846,316	)
Net operating revenues		4,649,604			5,975,553

Net loss	$	(516,272	)	$	(4,293,053	)

Net loss per common share - basic and diluted	$	(0.01	)	$	(0.07	)

Weighted average number of common shares outstanding – basic and diluted		40,622,000			58,108,000

NOTE 7. DEBT

Short-Term Bank Borrowings

The Company had a $5.0 million revolving line of credit agreement with Northwestern Bank for general corporate purposes through October 15, 2007. The Company elected not to request an extension of this revolving line of credit beyond the expiration date of October 15, 2007. The interest rate under the revolving line of credit was Wall Street prime (7.50% at October 31, 2007, and 8.25% at December 31, 2006) with interest payable monthly in arrears. Principal was payable at the expiration of the revolving line of credit agreement. Interest expense on the revolving line of credit for the years ended December 31, 2007, 2006, and 2005, was $32,873, $283,163, and $37,326, respectively.

Northwestern Bank continues to provide letters of credit for the Company’s drilling program (as described in Note 11 “Commitments and Contingencies”). These letters of credit may be extended or may be replaced upon their expiration dates by letters of credit under the Company’s senior secured credit facility.

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

Effective December 12, 2007, Bach obtained an increase in its borrowing capacity under the revolving line of credit from $0.5 million to $1.0 million with Northwestern Bank. This revolving line of credit agreement is for general company purposes and is secured by all of Bach’s personal property owned or hereafter acquired and is non-recourse to the Company. The interest rate under the revolving line of credit is Wall Street prime (7.25% at December 31, 2007, and 8.25% at December 31, 2006) with interest payable monthly in arrears. Principal is payable at the expiration of the revolving line of credit agreement. The expiration date is October 1, 2008. Interest expense for the years ended December 31, 2007, and 2006, was $3,082 and $2,166, respectively.

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Mortgage and Notes Payable - Bach

Bach’s outstanding debt was as follows with interest expense for the periods indicated:

								Principal Amount		Interest Expense
Description of Loan	Date of Loan		Maturity Date		Interest Rate			Outstanding		2007		2006
Mortgage payable on building		10/06/06		10/15/09		6.00	%	$	369,408	$	20,657	$	5,352
Notes payable:
Vehicles		10/06/06		10/01/10		7.50	%		68,231		6,006		1,618
Equipment		10/06/06		09/01/07		5.50	%		-		253		198
Vehicles		12/18/06		12/20/09		7.25	%		48,452		4,158		-
Vehicles		04/23/07		04/25/11		7.00	%		80,490		4,213		-
Vehicles		09/13/07		09/15/10		6.95	%		22,305		424		-
Total notes payable								$	219,478	$	15,054	$	1,816

Mortgage Payable

On October 4, 2005, the Company entered into a mortgage loan from Northwestern Bank in the amount of $2,925,000 for the purchase of an office condominium and associated interior improvements. The security for this mortgage is the office condominium real estate. Effective February 14, 2008, the Company refinanced the existing loan by extending its maturity date through February 1, 2011. The payment schedule is principal and interest in 36 monthly payments of $21,969 with one principal and interest payment of $2,692,849 on February 1, 2011. The interest rate is 5.95% per year. As of December 31, 2007, the principal amount outstanding was $2,712,788. Interest expense for the years ended December 31, 2007, 2006, and 2005, was $174,972, $192,814, and $15,732, respectively.

Note Payable – Directors and Officers Insurance

On November 13, 2006, the Company entered into a financing agreement with AICCO, Inc. to finance the insurance premium related to director and officer liability insurance coverage in the amount of $184,230. A monthly payment of $15,807 was required beginning November 30, 2006, through August 1, 2007. The interest rate was 7.01% per year. Interest expense for the year ended December 31, 2007, was $2,546.

Second Lien Term Loan

On August 20, 2007, the Company entered into a second lien term loan agreement with BNP Paribas (“BNP”), as the arranger and administrative agent, and several other lenders forming a syndicate. The initial term loan is $50 million for a 5-year term (expires 8/20/12) which may increase up to $70 million under certain conditions over the life of the loan facility. The proceeds of the loan were used to repay the outstanding balance under the Company’s mezzanine financing with Trust Company of the West (“TCW”) and for general corporate purposes. Interest under the loan is payable at rates based on the London Interbank Offered Rate (“LIBOR”) plus 700 basis points with a step-down of 25 basis points once the Company’s ratio of total indebtedness to earnings before interest, taxes, depreciation, depletion, amortization, and other non-cash charges is lower than or equal to a ratio of 4.0 to 1.0 on a trailing four quarters basis. The Company has the ability to prepay the loan during the first year at a price equal to 103% of par, during the second year at a price equal to 102% of par, and thereafter at a price equal to 100% of par.

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

For the year ended December 31, 2007, interest and fees incurred for the loan was $2,244,539. The Company has also incurred deferred financing fees of approximately $1.3 million with regard to the loan. The deferred financing fees are being amortized on a straight-line basis over the remaining terms of the loan obligation. Amortization expense for the loan is estimated to be $264,000 per year through 2011. Amortization expense was $96,724 for the year ended December 31, 2007. In addition, the Company incurs annual agency fees which are recorded to interest expense.

Mezzanine Financing

Effective August 20, 2007, the Company’s subsidiary Aurora Antrim North, L.L.C. (“North”) terminated its Amended Note Purchase Agreement with TCW which provided $50 million in mezzanine financing. As of the effective date, North had outstanding borrowing of $40 million. The interest rate was fixed at 11.5% per year, compounded quarterly, and payable in arrears. TCW had limited the borrowing base and the agreement contained a commitment expiration date of August 12, 2007. Under the termination provisions, the Company was required to pay certain fees and prepayment charges associated with early termination. The following represents the expenditures paid to TCW: (i) $40 million payment of principal; (ii) $0.7 million payment of interest expense from June 27, 2007, through August 20, 2007; (iii) $0.36 million payment of interest make-whole provision from August 21, 2007, through September 27, 2007; (iv) $1.25 million payment of prepayment premium; and (v) $0.2 million payment for a make-whole provision on principal greater than $30 million.

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

For the years ended December 31, 2007, 2006, and 2005, interest and fees incurred for the mezzanine credit facility was $2,989,305, $4,714,861, and $2,171,389, respectively. In addition, the Company completed a write-off $1.6 million of unamortized debt issuance cost associated with the early extinguishment of the mezzanine financing.

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Senior Secured Credit Facility

On January 31, 2006, the Company entered into a $100 million senior secured credit facility with BNP and other lenders for drilling, development, and acquisitions, as well as other general corporate purposes. In connection with the second lien term loan discussed above, the Company also agreed to the amendment and restatement of the senior secured credit facility, pursuant to which the borrowing base under the senior secured credit facility was increased from the current authorized borrowing base of $50 million to $70 million effective August 20, 2007. The amount of the borrowing base is based primarily upon the estimated value of the Company’s oil and natural gas reserves. The borrowing base amount is redetermined by the lenders semi-annually on or about April 1 and October 1 of each year or at other times required by the lenders or at the Company’s request. The required semi-annual reserve report may result in an increase or decrease in credit availability. The security for this facility is substantially all of the Company’s oil and natural gas properties; guarantees from all material subsidiaries; and a pledge of 100% of the stock or member interest of all material subsidiaries.

This facility provides for borrowings tied to BNP’s prime rate (or, if higher, the federal funds effective rate plus 0.5%) or LIBOR-based rate plus 1.25% to 2.0% depending on the borrowing base utilization, as selected by the Company. The borrowing base utilization is the percentage of the borrowing base that is drawn under the senior secured credit facility from time to time. As the borrowing base utilization increases, the LIBOR-based interest rates increase under this facility. As of December 31, 2007, interest on the borrowings had a weighted average interest rate of 6.93%. For the years ended December 31, 2007, and 2006, interest and fees incurred for the senior secured credit facility were $2,723,170 and $2,323,732, respectively. All outstanding principal and accrued and unpaid interest under the senior secured facility is due and payable on January 31, 2010. The maturity date of the outstanding loan may be accelerated by the lenders upon occurrence of an event of default under the senior secured credit facility.

The Company has incurred deferred financing fees of $703,811 with regard to the senior secured credit facility. The deferred financing fees are being amortized on a straight-line basis over the remaining terms of the debt obligation. Amortization expense for the senior secured credit facility is estimated to be $202,000 per year through 2009. Amortization expense was $163,526 and $100,722 for the years ended December 31, 2007, and 2006, respectively. In addition, the Company incurs various annual fees associated with unused commitment and agency fees which are recorded to interest expense.

Scheduled principal maturities of long-term debt for each of the years succeeding December 31, 2007, are summarized as follows (in thousands):

Year	Amount
2008	$	189
2009		550
2010		56,171
2011		2,392
2012		50,000
Total	$	109,302

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 8. SHAREHOLDERS’ EQUITY

Redeemable Convertible Preferred Stock

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

Common Stock

2007

From February 2007 through December 2007, 210,000 common stock options were exercised by various Company employees under the existing stock option plans at exercise prices ranging from $0.375 to $1.25 per share. The Company received $92,500 in conjunction with these exercises.

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

From February through December 2007, 143,332 common stock options were exercised by various Company directors under the existing stock option plans at exercise prices ranging from $0.375 to $1.42 per share. The Company received $106,000 in conjunction with these exercises.

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

2006

From late December 2005 through early February 2006, the Company reduced the exercise price of certain outstanding options and warrants in order to encourage the early exercise of these securities. Each holder who took advantage of the reduced exercise price was required to execute a 6-month lock-up agreement with respect to the shares issued in the exercise. As a result of the options and warrants exercised pursuant to this reduced exercise price arrangement and pursuant to other exercises of outstanding options, an additional 20,573,422 shares were issued during the year ended December 31, 2006, representing 15,823,457 shares issued for cash proceeds of $18,301,949, and 4,749,965 shares issued pursuant to cashless exercises of the applicable and other warrants or options. Substantially, all of the options and warrants exercised under the reduced exercise price option were noncompensatory in nature and were accounted for as equity transaction.

In December 2006, three officers of the Company rescinded option exercises for 600,000 shares each. The option exercise price of $249,000 was returned to each of these officers and in exchange each officer surrendered 600,000 shares of common stock.

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

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

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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

The Company closed on the public offering of 16 million shares on November 7, 2006, and received net proceeds of approximately $44.4 million, which were utilized to repay amounts outstanding under the senior secured credit facility. The 30-day over-allotment option granted to the underwriters for the purchase of 3.6 million additional shares was exercised and closed on November 13, 2006, and the Company received net proceeds of approximately $10.2 million.

2005

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

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

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

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

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

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

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

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

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Common Stock Warrants

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

	2007			2006			2005
	Number of Shares Underlying Warrants			Number of Shares Underlying Warrants			Number of Shares Underlying Warrants
Outstanding at the beginning of the period		2,079,500			19,697,500			-
Granted		-			-			2,402,000
Assumed upon merger:
2 for 1 exchange of Aurora warrants		-			-			2,402,000
Cadence warrants		-			-			17,498,500
Exercised under early exercise program		-			(13,182,625	)		-
Exercised		(78,158	)		(3,589,871	)		(2,596,677	)
Forfeitures and other adjustments		(49,342	)		(845,504	)		(8,323	)
Outstanding at the end of the period		1,952,000			2,079,500			19,697,500

As of December 31, 2007, these common stock warrants had an average remaining contractual life of 1.09 years and weighted average exercise price per share of $1.74.

NOTE 9. INCOME TAXES

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

For the Years Ended December 31,	2007			2006			2005

Current taxes	$	-		$	-		$	-
Deferred taxes		(7,875	)		1,862			175
Less: change in valuation allowance		7,875			(1,862	)		(175	)

Net income tax expense (benefit)	$	-		$	-		$	-

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

For the Years Ended December 31,	2007			2006			2005

Tax at federal statutory income tax rate	$	(1,504	)	$	(661	)	$	(176	)
Adjustment of estimated income tax provision of prior years ^(a)		(6,371	)		2,523			-
Change in valuation allowance		7,875			(1,862	)		176

Net income tax expense (benefit)	$	-		$	-		$	-

^(a) 2006 adjustment of estimated income tax provision of prior year is due primarily to intangible costs that were expensed in 2005 calculation but capitalized and amortized in actual 2005 tax return. 2007 adjustment of estimated income tax provision of prior year is due primarily to a 2006 revision to the method of tax accounting treatment for stock options which lead to a significant change in the net operating loss carryover.

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

The components of the deferred tax assets and liabilities as of December 31 are as follows (in thousands):

	2007			2006			2005
Deferred tax assets:
Net operating loss carryover	$	28,926		$	11,661		$	12,324
Stock options		1,612			928			-
Section 1231 carryover		109			-			147
Capital loss carryover		-			33			66,000
Less valuation allowance		(8,405	)		(530	)		(2,392	)
Deferred tax assets, net		22,242			12,092			10,146

Deferred tax liabilities:
Excess assigned acquisition value		(4,165	)		(4,339	)		(4,339	)
Intangible drilling costs and other		(18,077	)		(7,753	)		(5,807	)
Deferred tax liabilities, net		(22,242	)		(12,092	)		(10,146	)

Net deferred tax assets (liabilities)	$	-		$	-		$	-

The Company has net operating loss carryforwards available to offset future federal taxable income of approximately $85.1 million, which expire from 2010 through 2027. Included in this amount is a pre-merger net operating loss carryforward incurred by Cadence of approximately $16.9 million. The valuation allowance increased (decreased) by approximately $7.9 million, ($1.9 million), and ($0.2 million) as of December 31, 2007, 2006, and 2005, respectively. Due to the net operating loss carryforwards, no income tax expense was recorded in 2007, 2006, and 2005.

NOTE 10. COMMON STOCK OPTIONS

Stock Option Plans

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

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

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

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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

Activity related to the stock option plans referenced above was as follows for the years ended December 31, 2007, 2006 and 2005:

For the Years Ended December 31,	2007			2006			2005
Options outstanding at beginning of period		3,432,496			1,804,994			943,994
Options granted		185,000			2,727,500			146,000
Assumed upon merger:
2 for 1 exchange of Aurora options		-			-			490,000
Cadence options		-			-			400,000
Options exercised		(353,332	)		(592,732	)		(195,000	)
Options forfeited and other adjustments		(390,500	)		(507,266	)		20,000
Options outstanding at end of period		2,873,664			3,432,496			1,804,994

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

	2007			2006			2005
Risk-free interest rate		4.67	%		4.1	%		4	%
Expected years until exercise		3.25-6.0			2.5-6.0			10
Expected stock volatility		71.41	%		41	%		41	%
Dividend yield		0	%		0	%		0	%

All Stock Options

In addition, Cadence awarded compensatory options and warrants totaling 30,280 on an individualized basis that was considered outside the awards issued under its 2004 Equity Incentive Plan. Aurora also issued options and warrants totaling 1,400,000 on an individualized basis that was considered outside the awards issued under its 1997 Stock Option Plan and Equity Compensation Plan for Non-Employee Directors.

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Activity with respect to all stock options is presented below for the years ended December 31, 2007, 2006 and 2005:

	2007					2006					2005
	Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price

Options outstanding at the beginning of period		4,862,776		$	2.23		6,448,468		$	0.72		2,700,664		$	0.99
Options granted		185,000			3.35		2,727,500			3.89		156,000			3.32
Assumed upon merger:
2 for 1 exchange of Aurora options		-					-			-		2,856,664			-
Cadence options		-					-			-		1,124,349			1.79
Options exercised		(353,332	)		0.56		(3,800,926	)		0.67		(357,500	)		1.20
Forfeitures and other adjustments		(390,500	)		4.10		(512,266	)		3.65		(31,709	)		0.43
Options outstanding at end of period		4,303,944		$	2.25		4,862,776		$	2.23		6,448,468		$	0.72

Exercisable at end of period		2,940,609		$	1.56		2,775,609		$	1.01

Weighted average fair value of options granted during the period	$	1.20				$	3.85

The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option. The intrinsic value of the options outstanding at December 31, 2007, was approximately $1.9 million and the intrinsic value of the options exercisable at December 31, 2007, was approximately $1.9 million. The intrinsic value of the options exercised during the year ended December 31, 2007, was approximately $350,000.

The weighted average remaining life by exercise price as of December 31, 2007, is summarized below:

Range of Exercise Prices	Outstanding Shares		Weighted Average Life		Exercisable Shares		Weighted Average Life

$0.38 - $0.63		1,896,664		1.5		1,896,664		1.5
$1.75 - $2.55		405,280		5.9		332,280		6.0
$2.90 - $3.55		268,000		8.3		135,000		7.8
$3.62		1,140,000		3.0		300,000		2.9
$4.45 - $4.70		494,000		7.7		176,665		7.3
$5.50		100,000		3.2		100,000		3.2
$0.38 - $5.50		4,303,944		3.5		2,940,609		2.5

NOTE 11. COMMITMENTS AND CONTINGENCIES

Environmental Risk

Due to the nature of the oil and natural gas business, the Company is exposed to possible environmental risks. The Company manages its exposure to environmental liabilities for both properties it owns as well as properties to be acquired. The Company has historically not experienced any significant environmental liability and is not aware of any potential material environmental issues or claims at December 31, 2007.

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Letters of Credit

For each salt water disposal well drilled in the State of Michigan, the Company is required to issue a letter of credit to the Michigan Supervisor of Wells. The Supervisor of Wells may draw on the letter of credit if the Company fails to comply with the regulatory requirements relating to the locating, drilling, completing, producing, reworking, plugging, filling of pits, and clean up of the well site. The letter of credit or a substitute financial instrument is required to be in place until the salt water disposal well is plugged and abandoned. For drilling natural gas wells, the Company is required to issue a blanket letter of credit to the Michigan Supervisor of Wells. This blanket letter of credit allows the Company to drill an unlimited number of natural gas wells. The majority of existing letters of credit have been issued by Northwestern Bank of Traverse City, Michigan, and are secured only by a Reimbursement and Indemnification Commitment issued by the Company, together with a right of setoff against all of the Company’s deposit accounts with Northwestern Bank. At December 31, 2007, letters of credit in the amount of $1.2 million were outstanding with the majority issued to the Michigan Supervisor of Wells.

Employment Agreement

Ronald E. Huff resigned as President, Chief Financial Officer and Director of AOG effective January 21, 2008. The Company had a 2-year Employment Agreement with Mr. Huff, providing for an annual salary of $200,000 per year and an award of a stock bonus in the amount of 500,000 shares of the Company’s common stock on January 1, 2009, so long as he remained employed by the Company through June 18, 2008, which requires the Company to record approximately $2.1 million in stock-based compensation expense over the contract period. Mr. Huff’s employment agreement will be honored by the Company through its June 18, 2008 termination date. At December 31, 2007, the stock bonus amount of 500,000 shares was unvested. However, this agreement has been modified to accelerate the award of Mr. Huff’s stock bonus in the amount of 500,000 shares of common stock from January 1, 2009, to June 18, 2008.

Equipment Sale - Leaseback Agreement

Effective June 21, 2007, the Company entered into an agreement with Fifth Third Bank to sell and leaseback three natural gas compressors, which were accounted for as an operating lease. The net carrying value of the natural gas compressors sold was $1.2 million. Because the net carrying value of the natural gas compressors was equal to the sales price, there was no gain or loss recognized on the sale. The lease agreement has a base lease term of 84 months with a monthly rental fee of $13,610 beginning July 1, 2007. For the year ended December 31, 2007, total rental expense incurred by the Company under this lease was $83,475, of which $8,713 was capitalized in oil and natural gas properties.

Effective December 19, 2007, the Company entered into an agreement with Fifth Third Bank to sell and leaseback eleven natural gas compressors for $2.7 million. Under the agreement, the Company is leasing back the property over a base lease term of 60 months with a monthly rental fee of $37,110 beginning January 1, 2008. The Company is accounting for the leaseback as an operating lease. The gain of $0.7 million realized in this transaction has been deferred and will be amortized to income in proportion to rent charged over the term of the lease. At December 31, 2007, the deferred gain of $0.7 million is shown on the Company’s Balance Sheet as “Other long-term liabilities” for the long-term portion of $0.6 million and as “Accounts payable and accrued liabilities” for the short-term portion of $0.1 million. For the year ended December 31, 2007, no rental expense was incurred by the Company under this lease.

The minimum lease payments required by both leases are as follows:

2008	$	608,638
2009		608,639
2010		608,638
2011		608,639
2012		608,638
Thereafter		244,982
	$	3,288,174

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Fry Well Loss

The Company participated with Savoy Energy, L.P. (“Savoy”) in an exploratory well known as the Fry 1-13 located in Mecosta County, Michigan. In late December 2006, the well experienced a blow-out event which incurred approximately $5.6 million associated with controlling the well and other related costs. The Company had a 13.33% cost interest (10% working interest) in this well to casing point and paid approximately $762,000 to cover its portion of the loss to Savoy. The Company’s insurance covered approximately 34% or $266,666 of the well control costs.

NOTE 12. RELATED PARTY TRANSACTIONS

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

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

Effective May 30, 2007, the board of directors named John C. Hunter as Vice President of Exploration and Production. He has worked for AOG since 2005 as Senior Petroleum Engineer. Prior to that, Mr. Hunter was instrumental in certain projects associated with the Company’s New Albany shale play. Over a series of agreements with the Company, Mr. Hunter (controlling member of Venator Energy, LLC) has acquired 1.25% working interest in certain leases. The leases cover approximately 132,600 acres (1,658 net) in certain counties located in Indiana. The 1.25% carried working interest shall be effective until development costs exceed $30 million. Thereafter, participation may continue as a standard 1.25% working interest owner. The Company is entitled to recovery of 100% of development costs (plus interest at a rate of 6.75% per annum compounded annually) from 85% of the net operating revenue generated from oil and gas production developed directly or indirectly in the area of mutual interest covered by the agreement. As of December 31, 2007, there is no production associated with this working interest and development costs were approximately $12.4 million.

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

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

NOTE 13. RETIREMENT BENEFITS

401(k) Plan

Effective May 1, 2006, the Company established a qualified retirement plan referred to as the Aurora 401(k) Plan (the “Plan”). The Plan is available to all employees who have completed at least 1,000 hours of service over their first 12 consecutive months of employment and are at least 21 years of age. Effective July 1, 2006, the Company waived the age and service requirements for any employee employed by the Company on or before July 1, 2006. The Company may provide: (1) discretionary matching of employee contributions; (2) discretionary profit-sharing contributions; and (3) qualified nonelective contributions to the Plan. Company-provided contributions are subject to certain vesting schedules. For the years ended December 31, 2007, and 2006, the Company contributed $66,211 and $42,350, respectively, as a discretionary matching contribution.

Retention Bonus

On September 19, 2007, the Company announced that it had retained Johnson Rice & Company, L.L.C. to assist the Board of Directors with investigating strategic alternatives for the Company. These alternatives, among other things, may include revisions to the Company’s strategic plan, asset divestitures, operating partnerships, identifying additional capital sources, or a sale, merger, or other business combination of the Company. The Board of Directors of the Company has approved a retention bonus arrangement to encourage certain key officers and employees to remain with the Company through the completion of the Company’s review of potential strategic alternatives. The Board of Directors recognizes that certain key officers and employees will have increased responsibilities and duties during the evaluation of strategic alternatives and will contribute significantly to the process. The aggregate retention bonus consists of four payments over an 8-month period beginning in late October 2007 through late April 2008. The key officers and employees must remain continuously employed with the Company as well as remain in good standing on the scheduled payment dates. As of December 31, 2007, the Company had recorded $237,500 for estimated retention bonuses in 2007.

2007 Incentive Bonus Plan

The Company had adopted an incentive bonus plan for the year 2007. The incentive bonus plan was available to all full-time employees, excluding officers and employees of subsidiaries. The bonus would be up to 10% of eligible employees’ compensation during the year 2007 if certain objectives are met. Those objectives were not met and no bonus expense was incurred.

NOTE 14. FOURTH QUARTER ADJUSTMENTS—2006

During the fourth quarter of 2006, the Company modified its approach to estimating capitalized interest. The Company’s original approach to capitalization of interest cost was to relate the specific exploration and development activities in progress that were allowed under the mezzanine credit facility to specific mezzanine credit facility borrowings. If there were no such borrowings in a month that matched the drilling activities, then no interest was capitalized. On January 31, 2006, the Company entered into a new senior secured revolving credit facility for drilling, development, and acquisitions, which was not limited to certain exploration and development activities. In this connection, the mezzanine credit facility was subordinated to the new senior credit facility, and no further borrowings occurred under the mezzanine facility. The Company reviewed its approach to capitalized interest and began treating all oil and gas properties that were not being depreciated, depleted, or amortized, as well as any exploration and development activities that were in progress of being developed as qualifying assets under SFAS No. 34. The Company identified all its long-term debt borrowings to be included in the weighted average rate calculation for capitalized interest. This change resulted in additional $3.2 million of capitalized interest for the entire fiscal year of 2006 which was recorded in the fourth quarter; of this amount, $1.9 million related to prior quarters.

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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

NOTE 15. SELECTED QUARTERLY DATA (Unaudited)

	Quarter Ended
	March 31			June 30			September 30			December 31
2007
Operating revenues (a)	$	6,248,362		$	6,820,177		$	7,205,388		$	7,632,879
Operating income (b)		1,531,336			2,231,935			2,876,491			2,671,790
Net (loss) income		(740,319	)		229,477			(3,254,294	)		(656,697	)
Basic net earnings per share		(0.01	)		0.00			(0.03	)		(0.01	)
Diluted net earnings per share		(0.01	)		0.00			(0.03	)		(0.01	)

2006
Operating revenues (a)		5,528,632			5,654,887			5,313,261			5,710,115
Operating income (b)		2,023,772			2,361,513			1,613,107			1,476,417
Net (loss) income		(939,183	)		(1,185,188	)		(2,086,234	)		2,091,433
Basic net earnings per share		(0.01	)		(0.01	)		(0.03	)		0.02
Diluted net earnings per share		(0.01	)		(0.01	)		(0.03	)		0.02

(a)

Includes (1) oil and natural gas sales, (2) pipeline transportation and processing, and (3) field services and sales.

(b)

Includes (1) production taxes, (2) production and processing operating expenses, (3) field services expenses, and (4) general and administrative expenses.

NOTE 16. SUBSEQUENT EVENTS

Letter of Intent

Effective January 22, 2008, the Board of Directors named John E. McDevitt as President, Chief Operating Officer and Director. The Board of Directors also named Gilbert A. Smith as Vice President of Business Development effective as of February 1, 2008. The Company has signed a non-binding Letter of Intent to acquire Acadian Energy, LLC. Mr. McDevitt (through a controlled entity) and Mr. Smith are the sole members of Acadian Energy, LLC (60% and 40% respectively). The proposed acquisition is valued at approximately $12.5 million and will include over 10,000 acres of New Albany Shale properties, 4 development wells, and approximately 7 bcf in proved reserves .

Other Investment Transfer

Effective March 31, 2007, the Company withdrew from active participation in the GeoPetra Partners, LLC investment. The Company has a full ownership interest in all projects in which it elected to participate and in properties and interest acquired in the investment prior to the effective date of the withdrawal. The carrying value of $528,136 is expected to be converted from "Other Investments" on the Balance Sheet to working interests in oil and natural gas properties for applicable projects in the first quarter of 2008.

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL

GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES

(Unaudited)

Supplemental Reserve Information . The information set forth below on our proved oil and natural gas reserves is presented in accordance with regulations prescribed by the Securities and Exchange Commission. The Company emphasizes that reserve estimates are inherently imprecise. Our reserve estimates were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change and such changes could be material and occur in the near term as future information becomes available.

The Company retained the service of an independent petroleum consultant (Data & Consulting Services, Division of Schlumberger Technology Corporation) to estimate its proved natural gas reserves at December 31, 2007, 2006, and 2005. Included in the tables set forth below are proved oil and natural gas reserves located in Michigan that were acquired as a separate property acquisition early in 2006 and proved oil and natural gas reserves acquired in conjunction with the reverse merger with Cadence Resources Corporation effective October 31, 2005. These proved reserves acquired in the reverse merger were estimated by Netherland, Sewell & Associates, Inc. and Ralph E. Davis Associates, Inc.

The following table sets forth a summary of changes in estimated reserves for 2007, 2006 and 2005:

Estimates of Proved Reserves	Oil (mbbl)			Natural Gas (mmcf)			Total (mmcfe)

Proved reserves as of December 31, 2004		-			34,949			34,949
Revisions of previous estimates		6			5,382			5,394
Purchases of minerals in place		103			1,572			2,190
Extensions and discoveries		-			22,107			22,107
Production		(10	)		(688	)		(748	)
Proved reserves as of December 31, 2005		99			63,322			63,916

Revisions of previous estimates		(40	)		4,880			5,120
Purchases of minerals in place		-			22,843			22,843
Extensions and discoveries		45			65,095			65,365
Production ⁽¹⁾		(23	)		(2,511	)		2,649
Sales of minerals in place		-			(665	)		(665	)
Proved reserves as of December 31, 2006		81			152,964			153,450

Revisions of previous estimates		20			(34,651	)		(34,531	)
Purchases of minerals in place		-			2,943			2,943
Extensions and discoveries		131			47,256			48,042
Production ⁽¹⁾		(28	)		(3,034	)		(3,202	)
Sales of minerals in place		(16	)		(11	)		(107	)
Proved reserves as of December 31, 2007		188			165,467			166,595

Proved developed reserves:
December 31, 2005		70			45,205			45,625
December 31, 2006		54			82,580			82,904
December 31, 2007		74			100,887			101,331

(1) Production for both 2007 and 2006 does not reflect 5 mcfe and 142 mcfe, respectively, of production the Company received in association with certain non-operated wells excluded in the year end reserve report.

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL

GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES

(Unaudited—continued)

During 2007, the Company recorded downward revisions to certain Antrim properties of 34.5 bcfe to the December 31, 2006, estimates of our reserves. This was due primarily to the 2007 lower realized production levels from certain project areas. The production curves used in the reserve report were adjusted to reflect lower future production to be consistent with the 2007 actual experience. This decrease was net of the upward adjustments caused by higher natural gas prices at December 31, 2007. Increase in pricing extends the economic lives of the properties which subsequently increases the reserves.

The Company recorded an increase in extensions and discoveries of 48 bcfe which was due to positive results from our 2007 drilling activity. Positive drilling results in the New Albany Shale added nearly 24 bcfe, while positive drilling results in the Antrim added 24 bcfe. Increases in the number of identifiable offsets also moved certain probable reserves to proved reserves. The Company also acquired 2.9 bcfe of proved reserves through the purchase of certain Antrim working interests for $3 million and sold 0.11 bcfe of proved reserves for approximately $1 million.

During 2006, the Company experienced significant changes in reserves due to extensions and discoveries associated with drilling activities conducted by both the Company and by third parties. Approximately 99.6% of the 65.4 bcfe of reserves attributable to extensions and discoveries are associated with the following:

The drilling of 16 gross (0.9 net) New Albany shale wells in Daviess and Greene Counties, Indiana, resulted in two field discoveries and reserves of 2.3 bcfe associated with 40 gross (2.4 net) wells. Approximately 67% of the reserves are undeveloped and are expected to be developed in 2007 and 2008.

The drilling of 196 gross (90.1 net) Antrim shale wells in Alcona, Alpena, Antrim, Charlevoix, Cheboygan, Montmorency, and Otsego Counties, Michigan, resulted in reserve extensions of 62.8 bcfe associated with 257 gross (138.1 net) wells. Approximately 59% of the reserve extensions are undeveloped and are expected to be developed in 2007 and 2008. The Company also acquired approximately 23 bcfe of proved reserves through purchases of natural gas properties for approximately $24.0 million and sold 0.7 bcfe of proved reserves for approximately $4.75 million.

During 2006, the Company recorded upward revisions of 5.1 bcfe to the December 31, 2005, estimates of our reserves. This was due primarily to the increase in the lives of the wells from 40 years to 50 years. Our reserve report for 2005 recognized a maximum well life of 40 years for Antrim shale wells. Schlumberger Data & Consulting Services, the preparer of the Company’s reserve reports, extended the maximum well life for the Antrim shale by an additional 10 years in the 2006 reserve report, and they also recognized a 50-year maximum life for the New Albany shale for several reasons. First, a number of Antrim shale properties operated by third parties have exhibited extended lives that suggest that a 50-year life is a reasonable expectation. Second, in most cases, our properties are projected to still be economic to produce after 50 years of production. Third, the casing in our wells is expected to maintain its integrity for 50+ years. Finally, we noted that at least one of the leading Antrim shale and New Albany shale producing companies projects their Antrim shale reserves and New Albany shale reserves using a 50-year maximum well life. The New Albany shale properties were included for the first time in our 2006 reserve report. The New Albany shale reservoir is comparable to the Antrim shale in its age, depth, pay thickness, gas content, gas origin, and production characteristics, so it is our belief that the maximum well life will be comparable. This increase was net of the downward adjustments caused by lower natural gas prices at December 31, 2006. A decrease in pricing reduces the economic lives of the properties which subsequently reduces the reserves.

During 2005, the Company recorded upward revisions of 5.4 bcfe to the December 31, 2004, estimates of our reserves. This upward revision was primarily due to positive initial production rates from one particular project area which outperformed prior year expectations which resulted in an upward adjustment to the projected production profile. This new profile became the analog for the entire project area increasing the reserves accordingly.

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL

GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES

(Unaudited—continued)

Also in 2005, the Company recorded an increase in extensions and discoveries of 22 bcfe which was due to positive results from our 2005 drilling and leasing activity. Certain positive drilling results coupled with increased drilling opportunities from leasing activity resulted in an increase in the number of identifiable offsets which moved certain probable reserves to proved reserves. The Company also acquired approximately 1.7 bcfe of proved reserves of oil and natural gas properties through our reverse merger.

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

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

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

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

The following table sets forth the our future net cash flows relating to proved oil and natural gas reserves based on the standardize measure prescribed in SFAS 69:

Year Ended December 31,	2007			2006			2005

Future gross revenues (1)	$	1,204,891,690		$	884,186,810		$	632,058,720
Future production costs (2)		(556,123,590	)		(378,345,360	)		(182,710,406	)
Future development costs (2)		(42,298,790	)		(37,324,420	)		(15,073,590	)
Future income tax expense (3)		(102,354,760	)		(83,566,133	)		(101,521,160	)
Future net cash flows after income taxes		504,114,550		$	384,950,897		$	332,753,564
Discount at 10% per annum		(328,571,410	)		(254,489,076	)		(179,885,324	)
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	$	175,543,140		$	130,461,821		$	152,868,240

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

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

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

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL

GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES

(Unaudited—continued)

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

As of December 31,	2007		2006		2005

Natural gas (per mmbtu)	$	7.18	$	5.84	$	9.89
Oil (per barrel)	$	90.18	$	57.81	$	56.41

Changes in Standardized Measure of Discounted Future Cash Flows

The following table sets forth the principal sources of change in the standardized measure of discounted future net cash flows:

Year Ended December 31,	2007			2006			2005

Beginning balance	$	130,461,821		$	152,868,240		$	32,159,710

Revisions to reserves proved in prior years:
Net change in prices and production costs ⁽¹⁾		28,130,498			(113,774,170	)		85,425,515
Net changes in future development costs		(5,261,045	)		(802,360	)		6,299,524
Net changes due to revisions in quantity estimates ⁽²⁾		(42,260,444	)		3,484,229			33,335,739
Net change in accretion of discount ⁽³⁾		15,878,281			19,950,751			(66,761,600	)
Other ⁽⁴⁾		4,469,458			(15,976,529	)		38,137,602
Total revisions to reserves provided in prior years		956,747			(107,118,080	)		96,436,780

New discoveries and extensions, net of future development and production costs		65,772,000			62,343,872			76,487,826
Purchases of minerals in place		4,371,832			23,605,950			11,834,500
Sales of oil and gas properties		(1,023,701	)		(4,756,826	)		-
Sales of oil and natural gas produced, net of production costs		(16,839,303	)		(14,436,361	)		(4,696,416	)
Previously estimated development costs incurred		5,772,092			-			-
Net change in income taxes		(13,928,348	)		17,955,026			(59,354,160	)

Net change in standardized measure of discounted cash flows		45,081,319			(22,406,419	)		120,708,530

Ending balance	$	175,543,140		$	130,461,821		$	152,868,240

⁽¹⁾ “Net changes in prices and production costs” – Our reserves consist primarily of natural gas. A significant change in natural gas price between reporting periods resulted in differences between 2005, 2006 and 2007. These price fluctuations were offset by changes in production costs. A summary of the changes is as follows:

	Price		Change in Price			Production Cost		Change in Production Cost
2007	$	7.18	$	1.34		$	3.34	$	0.87
2006	$	5.84	$	(4.05	)	$	2.47	$	(0.39	)
2005	$	9.89	$	3.69		$	2.86	$	(0.74	)
2004	$	6.20				$	2.12

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL

GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES

(Unaudited—continued)

⁽²⁾ “Revisions in quantity estimates” – The quantity estimates varied significantly between 2005, 2006 and 2007. The large reduction reflected in 2007 resulted when year end prices were applied to the downward adjustments of 34 bcfe to the 12/31/06 reserves for certain Antrim properties, then discounted back to present value. Certain fluctuations occurred in 2006 versus 2005 due to the classification of additional wells being added to the proved undeveloped category from the 12/31/05 report versus the 12/31/06 report. The additional wells were treated as “revisions” in the 2005 report but as new discoveries or extensions in the 2006 report which impacts the comparability between the 2 years. In addition, an upward revision was made in 2005. This was due to positive initial production rates from one particular project area which outperformed prior year expectations resulting in an upward adjustment to the projected production profile.

⁽³⁾ “Accretion to the discount” – In 2005, this line item was computed as the change in the overall discount between the 2004 report and the 2005 report. In 2006 and 2007, it was computed using the more simplified and industry-recognized method as a computation of the 10% of the pre-tax present value of the prior year reserve report.

⁽⁴⁾ “Other” – This line item reflects reconciling amounts which is made available to capture those timing and other differences, including modifications to the methodology applied from 2005, 2006, and 2007.

Capitalized Costs Related to Oil and Natural Gas Producing Activities

The following table sets forth the capitalized costs relating to the Company’s oil and natural gas producing activities:

As of December 31,	2007			2006			2005

Proved properties	$	167,282,245		$	128,381,121		$	39,643,003
Unproved properties		56,937,683			43,718,594			37,279,889
Total oil and natural gas properties		224,219,928			172,099,715			76,922,892
Less accumulated depreciation, depletion, and amortization		(14,401,584	)		(10,628,438	)		(7,962,138	)
Oil and natural gas properties—net	$	209,818,344		$	161,471,277		$	68,960,754

Costs Incurred in Oil and Natural Gas Producing Activities

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

AURORA OIL & GAS CORPORATION AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL

GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES

(Unaudited—continued)

The following table sets forth capitalized costs incurred related to the Company’s oil and natural gas activities:

Years Ended December 31,	2007			2006			2005

Property acquisition costs
Proved	$	3,005,609		$	24,011,335		$	22,763,734
Unproved		16,012,328			27,718,336			19,607,099
Exploration		11,687,015			8,360,779			781,586
Development		24,504,278			46,575,829			29,707,367
Total costs incurred ⁽¹⁾		55,209,230			106,666,279			72,859,786
Sales of oil and natural gas properties		(3,089,017	)		(11,489,456	)		(11,504,428	)
Total	$	52,120,213		$	95,176,823		$	61,355,358

⁽¹⁾ Total costs incurred includes (a) capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $1.3 million, $1.3 million, and $0 million for years ended December 31, 2007, 2006, and 2005, respectively, and (b) capitalized interest on unproven properties of $4.5 million, $3.9 million, and $1.1 million for years ended December 31, 2007, 2006, and 2005, respectively. Certain non-cash transactions are included as follows: (a) 2007 and 2006 asset retirement obligation and capitalized stock compensation of $0.12 million and $1.3 million and $0.17 million and $0.45 million, respectively, (b) net transfer of $0.31 million from 2005 deposits to 2006 oil and natural gas properties, and (c) the 2005 fair market value of properties received from Cadence in the merger valued at $22.4 million.

Results of Operations

The Company’s results of operations related to oil and natural gas activities are set forth below. The following table includes revenues and expenses associated directly with our oil and natural gas producing activities. It does not include any interest costs, general and administrative costs or provision for income taxes due to the net operating loss carryforward, and therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil and natural gas operations.

For Year Ended December 31,	2007			2006			2005

Oil and natural gas sales	$	26,723,818		$	21,591,811		$	6,743,444
Production taxes		(1,123,070	)		(877,319	)		(506,635	)
Production and lease operating costs		(8,761,445	)		(5,966,341	)		(1,587,205	)
Depletion and amortization		(3,769,104	)		(2,681,290	)		(767,511	)
Results of producing activities	$	13,070,199		$	12,066,861		$	3,882,093

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

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

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

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

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

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management has responsibility for establishing and maintaining adequate internal control over our financial reporting. Management utilized the Committee of Sponsoring Organizations of the Treadway Commissions Internal Control-Integrated Framework (“COSO framework”) in conducting the required assessment of effectiveness of our internal control over financial reporting.

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

Our Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) of the Securities Exchange Act of 1934, as amended) as of December 31, 2007, and have concluded that these disclosure controls and procedures are effective at the reasonable assurance level. Our CEO and CFO believe that the consolidated financial statements included in this report on Form 10-K fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented in conformity with generally accepted accounting principles.

Our management, including our CEO and CFO, do not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met with respect to financial statement preparation and presentation. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or because the degree of compliance with the policies or procedures deteriorates.

Changes in Internal Controls over Financial Reporting

There have been no changes in our internal controls over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Management’s report on internal control over financial reporting and the attestation report of our independent registered public accounting firm are included in Item 8 of this report.

ITEM 9B. OTHER INFORMATION

Not applicable.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Pursuant to instruction G(3) of Form 10-K, the information required by this Item will be set forth in our definitive proxy statement which will be filed not later than 120 days after the end of our fiscal year.

ITEM 11. EXECUTIVE COMPENSATION

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13. CERTAIN RELATIONSHIPS, RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial Statements

	The following financial statements are filed as a part of this report:

	Management’s Report on Internal Control Over Financial Reporting
	Reports of Independent Registered Public Accounting Firms
	Consolidated Financial Statements
	Consolidated Balance Sheets as of December 31, 2007, and 2006
	Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006, and 2005
	Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2007

(a)(2) Exhibit Index:

	3.1(1)	Restated Articles of Incorporation of Aurora Oil & Gas Corporation.
	3.2	By-Laws of Aurora Oil & Gas Corporation. (filed as an Exhibit 3.2 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)
	10.1	Securities Purchase Agreement between Cadence Resources Corporation and the investors signatory thereto, dated January 31, 2005 (filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on February 2, 2005, and incorporated herein by reference.)
	10.2(2)	Asset Purchase Agreement with Nor Am Energy, L.L.C., Provins Family, L.L.C. and O.I.L. Energy Corp. dated January 10, 2006.
	10.3	First Amended and Restated Note Purchase Agreement between Aurora Antrim North, L.L.C. et al. and TCW Asset Management Company, dated December 8, 2005 (filed as an Exhibit to our report on Form 10-KSB for the fiscal year ended September 30, 2005 filed with the SEC on December 29, 2005 and incorporated herein by reference.)
	10.4(2)	First Amendment to First Amended and Restated Note Purchase Agreement between Aurora Antrim North, L.L.C., et al., and TCW Asset Management Company, dated January 31, 2006.
	10.5	Amended and Restated Credit Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent and the Lenders Party hereto. (filed as an Exhibit 10.7 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)
	10.6(2)	Confirmation from BNP Paribas to Aurora Antrim North, L.L.C., dated February 22, 2006 relating to gas sale commitment.
	10.7	2006 Stock Incentive Plan. (filed as Exhibit 99.1 to our Form S-8 Registration Statement filed with the SEC on May 15, 2006 and incorporated herein by reference.)
	10.8(1)	Employment Agreement with Ronald E. Huff dated June 19, 2006.
	10.9(1)	Letter Agreement with Bach Enterprises dated July 10, 2006. (A redacted copy is filed as an exhibit to Amendment No. 4 to our Form 10`-QSB/A filed on January 30, 2008.)
	10.10(1)	First Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated July 14, 2006.
	10.11(3)	LLC Membership Interest Purchase Agreement dated October 6, 2006 relating to Kingsley Development Company, L.L.C.
	10.12(3)	Asset Purchase Agreement with Bach Enterprises, Inc., et al., dated October 6, 2006.
	10.13(3)	Form of indemnification letter agreement between Aurora Oil & Gas Corporation and Rubicon Master Fund.
	10.14	Second Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated December 21, 2006. (filed as an Exhibit 10.24 to our report on Form 10-KSB for the fiscal year ended December 31, 2006, filed with the SEC on March 15, 2007 and incorporated herein by reference.)
	10.15	Third Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated June 20, 2007. (filed as an Exhibit 10.25 to our Form 10-Q for the period ended June 30, 2007, filed with the SEC on August 9, 2007 and incorporated herein by reference.)
	10.16	Intercreditor Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent and the Lenders Party hereto. (Replaced Exhibit 10.8 Intercreditor and Subordination Agreement among, BNP Paribas, et al., TCW Asset Management Company, and Aurora Antrim North, L.L.C., dated January 31, 2006.) (filed as an Exhibit 10.26 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)
	10.17	Second Lien Term Loan Agreement dated August 20, 2007, among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as Administrative Agent and the Lenders Party hereto. (filed as an Exhibit 10.27 to our Form 8-K dated August 16, 2007, filed with the SEC on August 22, 2007 and incorporated herein by reference.)
*	10.18	Promissory Note from Aurora Oil & Gas Corporation to Northwestern Bank dated February 14, 2008.
*	14.1	Code of Conduct and Ethics (updated 2/1/08)
	16.1	Letter concerning change of certifying accountant from Rachlin Cohen & Holtz, LLP (included in Exhibit 23.1)
*	21.1	List of Subsidiaries.

*	23.1	Consent of Rachlin Cohen & Holtz LLP.
*	23.2	Consent of Weaver & Tidwell LLP.
*	23.3	Consent of Ralph E. Davis Associates, Inc.
*	23.4	Consent of Schlumberger Technology Corporation.
*	23.5	Consent of Netherland, Sewell & Associates, Inc.
*	31.1	Rule 13a-14(a) Certification of Principal Executive Officer.
*	31.2	Rule 13a-14(a) Certification of Principal Financial and Accounting Officer.
*	32.1	Section 1350 Certification of Principal Executive Officer.
*	32.2	Section 1350 Certification of Principal Financial and Accounting Officer.

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

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

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

* Filed with this report.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	AURORA OIL & GAS CORPORATION

Date: March 7, 2008	By:	/s/ William W. Deneau
		Name:	William W. Deneau
		Title:	Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

SIGNATURE	OFFICE	DATE

/s/ William W. Deneau	Chairman, Chief Executive Officer, and	March 7, 2008
William W. Deneau	Director (Principal Executive Officer)

/s/ Barbara E. Lawson	Chief Financial Officer	March 7, 2008
Barbara E. Lawson	(Principal Financial Officer and
	Principal Accounting Officer)

/s/ John E. McDevitt	President, Chief Operating Officer, and	March 7, 2008
John E. McDevitt	Director

/s/ Richard M. Deneau	Director	March 7, 2008
Richard M. Deneau

/s/ Gary J. Myles	Director	March 7, 2008
Gary J. Myles

/s/ Wayne G. Schaeffer	Director	March 7, 2008
Wayne G. Schaeffer

/s/ Kevin D. Stulp	Director	March 7, 2008
Kevin D. Stulp

/s/ Earl V. Young	Director	March 7, 2008
Earl V. Young

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