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, 2008




OR




 ̈
            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 registeredCommon
      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   ̈      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   ̈      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   ̈




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.   ̈




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




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


Yes   ̈      No  x




The
aggregate market value of common stock held by non-affiliates of the Registrant
as of June 30, 2008 was $35,576,214.  The number of outstanding shares
of the Registrant’s common stock as of March 3, 2009, was
103,282,788.








AURORA
OIL & GAS CORPORATION


2008
ANNUAL REPORT ON FORM 10-K


TABLE
OF CONTENTS




PART
      IItem
      1.
                    Business
                    
                    1Item
      1A.
                    Risk
      Factors
                    
                    15Item
      1B.
                    Unresolved
      Staff Comments
                    
                    26Item
      2.
                    Properties
                    
                    26Item
      3.
                    Legal
      Proceedings
                    
                    27Item
      4.
                    Submission
      of Matters to a Vote of Security Holders
                    
                    27PART
      IIItem
      5.
                    Market
      for the Registrant’s Common Stock, Related Shareholder Matters and Issuer
      Purchases of Equity Securities
                    
                    28Item
      6.
                    Selected
      Financial Data
                    
                    31Item
      7.
                    Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations
                    
                    33Item
      7A.
                    Quantitative
      and Qualitative Disclosures About Market Risk
                    
                    51Item
      8.
                    Financial
      Statements and Supplementary Data
                    
                    53Item
      9.
                    Changes
      in and Disagreements with Accountants on Accounting and Financial
      Disclosure
                    
                    109Item
      9A.
                    Controls
      and Procedures
                    
                    109Item
      9B.
                    Other
      Information
                    
                    111PART
      IIIItem
      10.
                    Directors,
      Executive Officers, and Corporate Governance
                    
                    112Item
      11.
                    Executive
      Compensation
                    
                    115Item
      12.
                    Security
      Ownership of Certain Beneficial Owners and Management and Related
      Stockholder Matters
                    
                    122Item
      13.
                    Certain
      Relationships, Related Transactions, and Director
    Independence
                    
                    124Item
      14.
                    Principal
      Accounting Fees and Services
                    
                    127PART
      IVItem
      15.
                    Exhibits
      and Financial Statement Schedules
                    
                    128Index
      to Exhibits
                    
                    128Signatures
                    
                    130Exhibits


i


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:





·
            changes
      in general economic, market, industry, or business
    conditions;


·
            the
      volatibility of natural gas and oil prices caused in part by the
      volatility of domestic and international demand for oil and natural
      gas;


·
            impacts
      the current national and international financial crisis may have on our
      business and financial condition;


·
            our
      ability to execute certain business strategies and debt restructuring
      initiatives;


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


·
            the
      anticipated impact on production of our well enhancement program, Antrim
      remediation program, or other corrective actions that we may take in an
      attempt to improve production;


·
            uncertainties
      inherent in estimating quantities of natural gas and oil reserves and
      projecting future rates of production and the timing of development
      expenditures;


·
            leasehold
      terms expiring before production can be
  established;


·
            declines
      in the values of our natural gas and oil properties resulting in ceiling
      test write-downs;


·
            fluctuations
      in the values of certain of our assets and
  liabilities;


·
            actions
      taken with respect to non-performance by third parties, including
      suppliers, contractors, operators, processors, customers, and
      counterparties;


·
            drilling
      and operating risks;


·
            drilling
      and operating activities that do not result in commercially productive
      reserves;


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


·
            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.


ii





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 an
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 natural gas exploration and development opportunities and changed our name
to Cadence Resources Corporation (“Cadence”). We acquired Aurora Energy, Ltd.
("Aurora") on October 31, 2005 through the merger of our wholly-owned subsidiary
with and into Aurora. The acquisition of Aurora was accounted for as a reverse
merger, with Aurora being the acquiring party for accounting purposes. The
Aurora executive management team also assumed management control at the time the
merger closed, and we moved our corporate offices to Traverse City, Michigan.
Effective May 11, 2006, Cadence amended its articles of incorporation to change
the parent name to Aurora Oil & Gas Corporation (“AOG”).





During
2008, due to the current global economic crisis coupled with significant losses
in production, significant deficiencies in working capital, loss of revenue due
to the termination of our natural gas derivatives, and increases in interest
rates on our debt obligations, we have been unable to gain access to the credit
markets.  As a result, our drilling activities have substantially
decreased and we have had to adjust our short-term strategy, placing less
emphasis on drilling and more emphasis on cash conservation and pursuing farmout
relationships in order to develop our undeveloped reserves.  We
continue discussions with existing lenders to restructure our debt and are
currently undergoing an Antrim remediation program to address our decline in
production.





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.


1


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,
2008:





Total Acreage
                  
                  
                  Percentage DevelopedPlay/Trend
                  
                  Gross
                  
                  
                  Net
                  
                  
                  Gross
                  
                  
                  NetMichigan
      Antrim
                  
                  
                  286,390
                  
                  
                  
                  134,003
                  
                  
                  
                  23
                  %
                  
                  
                  30
                  %New
      Albany
                  
                  
                  787,595
                  
                  
                  
                  449,183
                  
                  
                  
                  2
                  %
                  
                  
                  1
                  %Other
                  
                  
                  90,475
                  
                  
                  
                  68,203
                  
                  
                  
                  2
                  %
                  
                  
                  1
                  %Total
                  
                  
                  1,164,460
                  
                  
                  
                  651,389
                  
                  
                  
                  7
                  %
                  
                  
                  7
                  %





As of
December 31, 2008, our proved reserves decreased by approximately 68.6 bcfe from
December 31, 2007, to approximately 98.0 bcfe.  Of the 98.0 bcfe, 73%
was in our Antrim shale properties and 73% was proved developed.  The
New Albany shale provided a modest increase in proved reserves during the year,
adding a net 1.0 bcfe, which is a 4% increase over the 25.0 bcfe reported on
December 31, 2007.  The Antrim shale proved reserves were reduced by a
net 69.3 bcfe due to the following developments:





·
            Reserves
      were reduced by 3.0 bcfe due to production during the
  year.


·
            A
      reduction in natural gas prices (from an average of $7.18 per mcf on
      December 31, 2007, to an average of $6.07 per mcf on December 31, 2008)
      has caused a reduction in the volume of natural gas that can be
      economically produced.  We attribute approximately 7.9 bcfe of
      the reduction in Antrim shale proved reserves to be attributable to lower
      natural gas prices.


·
            As
      a result of changes in regulatory criteria, the Michigan Department of
      Environmental Quality (“DEQ”) forced us to plug 5 wells and shut in 13
      wells during 2008 due to water quality issues, resulting in a setback in
      our efforts to dewater the Antrim shale in the Arrowhead
      project.  Furthermore, the DEQ blocked our efforts to drill
      additional wells needed for dewatering.  With no means to
      effectively dewater the project area, performance of the existing wells
      resulted in net reserve reduction of 7.1 bcfe on the three producing units
      in the project.


·
            Due
      to the DEQ issues cited above, the absence of available capital needed to
      install infrastructure for existing wells and drill additional wells, and
      lack of performance of wells in the Arrowhead project, the proved reserves
      associated with the Blue Lakes Unit, Tomahawk 26 Unit, Tomahawk 27 Unit
      and Tomahawk 35 Unit were eliminated, resulting in a reduction of 12.8
      bcfe.


·
            Our
      Antrim shale proved reserves have historically been determined by our
      third party reserve engineers using type curves derived from a combination
      of reservoir simulation and production performance from nearby more mature
      Antrim shale units operated by others.  At the end of 2007, the
      type curves were modified to conform to our historical production history
      to date, but we had an insufficient amount of production on our working
      interest units to significantly alter the type curves.  Now that
      we have sufficient data to develop decline curves for our wells, our
      engineers have based their projections of future production volumes on
      actual historical data from our own wells instead of representative data
      from other wells in the Antrim play.  Not only did this affect
      the proved developed producing reserves, but the type curves for proved
      undeveloped reserves were modified accordingly.  This resulted
      in type curves projecting lower reserves, and certain future drilling
      locations with proved undeveloped reserves were eliminated due to
      unacceptable economics. We estimate that approximately 41.3 bcfe of the
      reduction in Antrim shale proved reserves is attributable to this
      change.


·
            We
      added 2.8 bcfe in extensions to proved reserves due to drilling activities
      in various areas.


2


Unconventional
shale plays tend to be characterized by high drilling success rates. For the
12-month period ending December 31, 2008, we incurred $10.5 million to
drill and participate in 26 (6 net) wells, with an 88% drilling success
rate.  Of the total 26 (6 net) wells, 14 (3 net) wells were drilled in
the Antrim, with a 100% drilling success rate.  The remaining 12 (3
net) wells were drilled in other plays with a 75% drilling success
rate.  Our drilling activities were significantly reduced during 2008
due to our financial constraints and inability to refinance or restructure our
debt obligations.  We also incurred $2.2 million on property and
leasehold acquisitions.  Average net daily production decreased from
8,787 mcfe per day in 2007 to 8,316 mcfe per day in 2008. Lower than expected
production resulted from damage to our South Knox facility caused by fire and
flooding, pumping deficiencies, and continued dewatering problems with the
Antrim play.  During the first and second quarter we also experienced
delays from Warner Plant outages and heavy snowfall causing delays in response
to freezing complications associated with compressors, booster stations, and
water lines.





During
2008, we implemented a well enhancement program on our operated Antrim shale
properties to address our decline in production.  We completed well
enhancement activities on 74 wells and experienced an approximate one to two
days stoppage in production per well to complete the well enhancement
activities.  We also shut down the downhole pumps on various wells that
were producing large volumes of water with insignificant volumes of gas. 
Since we discontinued the pumping operations on these wells, we have observed a
detrimental impact on the gas production levels in the remaining producing
wells.  We believe that maximizing water production from all operated
Antrim shale wells, regardless of their individual economic impact, is necessary
to maximize gas production from the projects as a whole.  Therefore, we
have initiated a renewed well enhancement program in February 2009 that
emphasizes measures that will increase water production.  The program will
be implemented in three phases throughout 2009 with the first phase
incorporating the Hudson 19, Hudson 34, Hudson SW and Hudson West Units. 
As part of this process, we are planning to install water meters at each well
location to track water production.  Additional time will be required
before measurable progress in production can be recognized.  The table
below highlights our portfolio of producing wells as of December 31,
2008.





Play /Trend
                  
                  Gross Wells
                    Producing
                  
                  
                  Net Wells
                    Producing
                  
                  
                  Gross Wells
                    Waiting
                    Hook-Up
                  
                  
                  Net Wells
                    Waiting
                    Hook-Up
                  
                  
                  Gross Wells
                    Undergoing
                    Resource
                    Assessment
                  
                  
                  Net Wells
                    Undergoing
                    Resource
                    AssessmentMichigan
      Antrim
                  
                  
                  567.00
                  
                  
                  
                  261.89
                  
                  
                  
                  24.00
                  
                  
                  
                  4.80
                  
                  
                  
                  10.00
                  
                  
                  
                  2.84New
      Albany
                  
                  
                  25.00
                  
                  
                  
                  1.25
                  
                  
                  
                  6.00
                  
                  
                  
                  6.00
                  
                  
                  
                  -
                  
                  
                  
                  -Other
                  
                  
                  36.00
                  
                  
                  
                  18.35
                  
                  
                  
                  1.00
                  
                  
                  
                  -
                  
                  
                  
                  10.00
                  
                  
                  
                  4.00Total
                  
                  
                  628.00
                  
                  
                  
                  281.49
                  
                  
                  
                  31.00
                  
                  
                  
                  10.80
                  
                  
                  
                  20.00
                  
                  
                  
                  6.84





Effective
September 15, 2008, we closed the sale to Presidium Energy, LC (“Presidium”) of
all our membership interest in a wholly owned subsidiary, AOK Energy, LLC
(“AOK”).  We participated in a joint venture project known as the “Oak
Tree Project” through AOK which held all of our Woodford shale
properties.  Presidium is wholly owned and operated by John V. Miller,
who served as our Vice President from November 1, 2005 until he resigned on
February 29, 2008.  Total sales price was $15 million, of which we
received $3 million in cash and received a note receivable in the amount of $12
million.  In connection with the sale, we also received a 3%
overriding royalty interest in certain oil and gas leases located within the Oak
Tree Project.





On
October 1, 2008, we received a notice of early termination from BNP Paribas
(“BNP”) with respect to our natural gas and interest rate swap derivatives (the
“Early Termination Notice”) in accordance the 1992 International Swap Dealers
Association, Inc. (“ISDA”) master agreement dated August 20, 2007 between the
Company and BNP.  For the year ended December 2008, the effect of the
termination of our natural gas derivatives resulted in a loss of oil and gas
revenue in the approximate amount of $1.2 million.  Based on a sales
price of $4.50 per mcf, we estimate lost revenues from our terminated natural
gas contracts to be $10.8 million, $10.7 million, and $8.0 million for the years
ending December 31, 2009, 2010, and 2011, respectively.  As a result
of the natural gas derivative contracts terminations, we are presently exposed
to the fluctuation of natural gas prices.


3


On
October 29, 2008, we entered into a farmout arrangement with Atlas Energy
Resources, LLC (“Atlas”) to farm out our 64.43% interest in undeveloped acreage
in the Wabash project.  The Wabash project is a 121,702 gross acre New
Albany shale project located in the Indiana counties of Clay, Greene, Owen, and
Sullivan.  Under the terms of the farmout arrangement, Atlas must (1)
drill at least 20 horizontal wells on an annual basis, (2) pay a well site fee,
(3) accept responsibility for any lease obligations, including payments for
lease extensions, (4) provide us with an overriding royalty interest in
production, and (5) allow us to participate as a working interest owner, if
requested, in a 25% working interest in any leases pooled into a drilling
unit.  As of the filing of this Form 10-K, no drilling activities have
commenced under the farmout arrangement and we declined an option to participate
in 2 anticipated wells.





If Atlas
fails to drill the minimum number of wells per year, the farmout agreement will
automatically terminate for each lease not earned or subject to
assignment.  If Atlas fails to comply with any other provision or
requirement, Atlas will have 30 days to correct the
non-compliance.  At the expiration of the 30 days if the
non-compliance has not been corrected, the farmout agreement may be terminated
at our option, and we would have the right to exercise all rights and remedies
under the agreement.





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 the Antrim shale and New Albany shale. Both
plays are at varying stages of their respective development life cycle. We
believe the New Albany shale represents emerging plays, as development activity
has only been initiated within the last several years. As we and others 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 development activities.  We
continue discussions with existing lenders to restructure our
debt.  We are also seeking alternative financing
arrangements.  Due to the recent events within the banking industry
and decline in operations, we are having difficulty restructuring our debt and
securing alternative financing arrangements.  Fostering stable
financing for our producing properties and providing flexibility for pursuing
our growth development strategy is dependent on restructuring our debt or
securing alternative financing arrangements.





Generate growth
through drilling and farmout arrangement.We expect to generate long-term
reserve and production growth through farmout arrangements and drilling
activities. We believe the experience and expertise of our management and
technical teams enables us to identify and evaluate farmout arrangements and
develop natural gas projects.





Optimize our
asset portfolio.   With extensive leasehold positions in
two 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. Due to challenges in the
capital markets, our focus has shifted from drilling and operating natural gas
and oil wells, to working in partnership with others to develop our
assets.  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.


4


OPERATING
AREAS





Antrim
shale





Our
Antrim shale properties are primarily located in northern Michigan and represent
the majority of our production and proved reserves.  Prior to 2008, we
had focused on development drilling in the Antrim shale, creating a stable base
of production and proved reserves.  At December 31, 2008, we owned
working interests in 652 (318 net) Antrim wells which included 48 (45 net)
non-producing wells.  In 2008, we drilled or participated in 14 gross
(3 net) Antrim wells and completed 14 gross wells for a success rate of
100%.  In 2007, we drilled 56 gross (35 net) Antrim wells and
completed 54 gross wells for a success rate of 96%.  We currently have
134,003 net acres leased, with approximately 39,956 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 is 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 10%
annually.





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, 2008, we owned working interests in 56
(19 net) New Albany shale wells which included 25 (11 net) non-producing
wells.  In 2008, we did not drill or participate in any New Albany
wells due to our financial constraints and inability to access
capital.  In 2007, we drilled or participated in 27 gross (11 net) New
Albany shale wells and completed 27 gross wells for a success rate of
100%.  We currently have 449,183 net acres leased, with approximately
5,148 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 is 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 10% annually.


5





While the
New Albany shale is our primary target, our acreage also includes a variety of
producible oil and natural gas formations, including coalbed methane formations
and those formations overlying Silurian-age reefs. Our New Albany shale drilling
efforts will also provide useful information about these other producible
formations for future evaluation strategies.  We believe this will
provide further insight into our ability to predict the commerciality of the
resource.





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
produced at low wellhead pressure from a wellbore equipped with five and
one-half inch or seven inch diameter production casing and through a polypipe
flowline that has a minimum diameter of four inches.





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.


6


Oil
and natural gas reserves





The following table presents
information as of December 31, 2008, 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 44% of our proved reserves are classified as either proved
developed non-producing or proved undeveloped.





As of December 31, 2008Oil and Natural Gas Reserves
                    
                    Oil
                      (mbbls)
                    
                    
                    Gas
                      (mmcf)
                    
                    
                    Total
                      (mmcfe)
                    
                    
                    PV-10(c)
                      (In thousands)
                    
                    
                    Standardized
                      Measure
                      (In thousands)Proved
      developed producing
                    
                    
                    73
                    
                    
                    
                    54,830
                    
                    
                    
                    55,268
                    
                    
                    $
                    42,653
                    
                    
                    
                    42,636Proved
      developed non-producing
                    
                    
                    23
                    
                    
                    
                    16,209
                    
                    
                    
                    16,347
                    
                    
                    
                    14,350
                    
                    
                    
                    14,344Proved
      undeveloped
                    
                    
                    19
                    
                    
                    
                    26,321
                    
                    
                    
                    26,435
                    
                    
                    
                    11,595
                    
                    
                    
                    11,591Total
      proved (a)
      (b)
                    
                    
                    115
                    
                    
                    
                    97,360
                    
                    
                    
                    98,050
                    
                    
                    $
                    68,598
                    
                    
                    
                    68,571Oil and Natural Gas Reserves by
                      Play/Trend
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    Total
                      (mmcfe)
                    
                    
                    Percent of
                      Proved
                      Reserves
                    
                    
                    PV-10(c)
                      (In thousands)Michigan
      Antrim
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    71,448
                    
                    
                    
                    73
                    %
                    
                    $
                    48,650New
      Albany
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    26,002
                    
                    
                    
                    26
                    %
                    
                    
                    18,691Other
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    600
                    
                    
                    
                    1
                    %
                    
                    
                    1,257Total
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    98,050
                    
                    
                    
                    100
                    %
                    
                    $
                    68,598Change in reserve quantity
      information
                      for the year ended December 31,
      2008
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    Oil
                      (mbbls)
                    
                    
                    Gas
                      mmcf
                    
                    
                    Total
                      (mmcfe)Proved
      reserves as of December 31, 2007
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    188
                    
                    
                    
                    165,467
                    
                    
                    
                    166,595Revisions
      of previous estimates
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    (74
                    )
                    
                    
                    (67,843
                    )
                    
                    
                    (68,287
                    )Purchases
      of minerals in place
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -Extensions
      and discoveries
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    26
                    
                    
                    
                    2,630
                    
                    
                    
                    2,786Production
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    (25
                    )
                    
                    
                    (2,894
                    )
                    
                    
                    (3,044
                    )Sales
      of minerals in place
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    -
                    
                    
                    
                    -
                    
                    
                    
                    -Proved
      reserves as of December 31, 2008
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    115
                    
                    
                    
                    97,360
                    
                    
                    
                    98,050





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





(b)
            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.





7


(c)
            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, 2008. The estimated future production is priced at December 31, 2008,
      without escalation, using an average of $41.30 per bbl and an average of
      $6.07 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 31,2008
                
                
                2007
                
                
                2006Standardized
      measure of discounted future net cash flows
                
                $
                68,570,766
                
                
                $
                175,543,140
                
                
                $
                130,461,821Add:
      Present value of future income tax discounted at 10%
                
                
                27,724
                
                
                
                14,392,640
                
                
                
                28,320,989PV-10
                
                $
                68,598,490
                
                
                $
                189,935,780
                
                
                $
                158,782,810





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, 2008, 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(c)Play/Trend
                
                Gross
                
                
                Net
                
                
                Gross
                
                
                Net
                
                
                Gross
                
                
                NetMichigan
      Antrim
                
                
                65,973
                
                
                
                39,956
                
                
                
                220,417
                
                
                
                94,047
                
                
                
                286,390
                
                
                
                134,003New
      Albany
                
                
                767,935
                
                
                
                5,148
                
                
                
                19,660
                
                
                
                444,035
                
                
                
                787,595
                
                
                
                449,183Other
                
                
                1,410
                
                
                
                941
                
                
                
                89,065
                
                
                
                67,262
                
                
                
                90,475
                
                
                
                68,203Total
                
                
                835,318
                
                
                
                46,045
                
                
                
                329,142
                
                
                
                605,344
                
                
                
                1,164,460
                
                
                
                651,389





(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.





(c)
            While
      we are focused on developing the shale, our acreage covers a variety of
      different formations in addition to the shale that have the possibility of
      being developed and marketed.


8


Production
and price information





The following table summarizes sales
volumes, sales prices, and production cost information for the periods indicated
($ in thousands):





Year Ended December 312008
                  
                  
                  2007
                  
                  
                  2006ProductionOil
      (bbls)
                  
                  
                  25,321
                  
                  
                  
                  27,907
                  
                  
                  
                  22,588Natural
      gas (mcf)
                  
                  
                  2,892,186
                  
                  
                  
                  3,039,714
                  
                  
                  
                  2,517,897Natural
      gas equivalent (mcfe)
                  
                  
                  3,044,112
                  
                  
                  
                  3,207,155
                  
                  
                  
                  2,653,427Oil
      and natural gas salesNatural
      gas sales
                  
                  $
                  26,208
                  
                  
                  $
                  20,911
                  
                  
                  $
                  17,510Natural
      gas derivatives-realized (losses) gains
                  
                  
                  (3,537
                  )
                  
                  
                  3,874
                  
                  
                  
                  2,683Oil
      sales
                  
                  
                  2,531
                  
                  
                  
                  1,939
                  
                  
                  
                  1,399Total
                  
                  $
                  25,202
                  
                  
                  $
                  26,724
                  
                  
                  $
                  21,592Average
      sales price (excluding all gains (losses) from
derivatives)Natural
      gas ($ per mcf)
                  
                  $
                  9.06
                  
                  
                  $
                  6.88
                  
                  
                  $
                  6.95Oil
      ($ per bbl)
                  
                  
                  99.96
                  
                  
                  
                  69.49
                  
                  
                  
                  61.96Natural
      gas equivalent ($ per mcfe)
                  
                  
                  9.44
                  
                  
                  
                  7.12
                  
                  
                  
                  7.13Average
      sales price (including all gains (losses) from
derivatives)Natural
      gas ($ per mcf)
                  
                  $
                  7.84
                  
                  
                  $
                  8.15
                  
                  
                  $
                  8.02Oil
      ($ per bbl)
                  
                  
                  99.96
                  
                  
                  
                  69.49
                  
                  
                  
                  61.96Natural
      gas equivalent ($ per mcfe)
                  
                  
                  8.28
                  
                  
                  
                  8.33
                  
                  
                  
                  8.14Average
      production expenses ($ per mcfe)Production
      taxes
                  
                  $
                  0.44
                  
                  
                  $
                  0.35
                  
                  
                  $
                  0.33Post-production
      expenses
                  
                  
                  0.93
                  
                  
                  
                  0.59
                  
                  
                  
                  0.55Leasing
      operating expenses
                  
                  
                  2.36
                  
                  
                  
                  2.14
                  
                  
                  
                  1.82Total
                  
                  $
                  3.73
                  
                  
                  $
                  3.08
                  
                  
                  $
                  2.70





Productive
wells





The following table sets forth as of
December 31, 2008, 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
                
                
                OilPlay/Trend
                
                Gross Wells
                
                
                Net Wells
                
                
                Gross Wells
                
                
                Net WellsMichigan
      Antrim
                
                
                591.00
                
                
                
                266.69
                
                
                
                -
                
                
                
                -New
      Albany
                
                
                31.00
                
                
                
                7.25
                
                
                
                -
                
                
                
                -Other
                
                
                1.00
                
                
                
                0.10
                
                
                
                36.00
                
                
                
                18.35Total
                
                
                623.00
                
                
                
                274.04
                
                
                
                36.00
                
                
                
                18.35


9





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 WellsType of Well
                                  
                                  Productive(b)
                                  
                                  
                                  Dry(c)
                                  
                                  
                                  Total
                                  
                                  
                                  Productive(b)
                                  
                                  
                                  Dry(c)
                                  
                                  
                                  TotalYear
      Ended 12/31/08(e)Exploratory(a)Michigan
      Antrim
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -New
      Albany
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -Other
                                  
                                  
                                  7
                                  
                                  
                                  
                                  2
                                  
                                  
                                  
                                  9
                                  
                                  
                                  
                                  1.07
                                  
                                  
                                  
                                  0.53
                                  
                                  
                                  
                                  1.60Total
                                  
                                  
                                  7
                                  
                                  
                                  
                                  2
                                  
                                  
                                  
                                  9
                                  
                                  
                                  
                                  1.07
                                  
                                  
                                  
                                  0.53
                                  
                                  
                                  
                                  1.60Development(a)Michigan
      Antrim
                                  
                                  
                                  14
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  14
                                  
                                  
                                  
                                  2.80
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  2.80New
      Albany
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  -Other
                                  
                                  
                                  2
                                  
                                  
                                  
                                  1
                                  
                                  
                                  
                                  3
                                  
                                  
                                  
                                  1.23
                                  
                                  
                                  
                                  0.50
                                  
                                  
                                  
                                  1.73Total
                                  
                                  
                                  16
                                  
                                  
                                  
                                  1
                                  
                                  
                                  
                                  17
                                  
                                  
                                  
                                  4.03
                                  
                                  
                                  
                                  0.50
                                  
                                  
                                  
                                  4.53Year
      Ended 12/31/07(d)Exploratory(a)Michigan
      Antrim
                                  
                                  
                                  1
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  1
                                  
                                  
                                  
                                  0.22
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  0.22New
      Albany
                                  
                                  
                                  15
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  15
                                  
                                  
                                  
                                  10.57
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  10.57Other
                                  
                                  
                                  7
                                  
                                  
                                  
                                  6
                                  
                                  
                                  
                                  13
                                  
                                  
                                  
                                  5.51
                                  
                                  
                                  
                                  5.00
                                  
                                  
                                  
                                  10.51Total
                                  
                                  
                                  23
                                  
                                  
                                  
                                  6
                                  
                                  
                                  
                                  29
                                  
                                  
                                  
                                  16.30
                                  
                                  
                                  
                                  5.00
                                  
                                  
                                  
                                  21.30Development(a)Michigan
      Antrim
                                  
                                  
                                  50
                                  
                                  
                                  
                                  2
                                  
                                  
                                  
                                  52
                                  
                                  
                                  
                                  29.43
                                  
                                  
                                  
                                  2.00
                                  
                                  
                                  
                                  31.43New
      Albany
                                  
                                  
                                  12
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  12
                                  
                                  
                                  
                                  0.60
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  0.60Other
                                  
                                  
                                  8
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  8
                                  
                                  
                                  
                                  5.80
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  5.80Total
                                  
                                  
                                  70
                                  
                                  
                                  
                                  2
                                  
                                  
                                  
                                  72
                                  
                                  
                                  
                                  35.83
                                  
                                  
                                  
                                  2.00
                                  
                                  
                                  
                                  37.83Year Ended 12/31/06Exploratory(a)Michigan
      Antrim
                                  
                                  
                                  2
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  2
                                  
                                  
                                  
                                  2.00
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  2.00New
      Albany
                                  
                                  
                                  13
                                  
                                  
                                  
                                  1
                                  
                                  
                                  
                                  14
                                  
                                  
                                  
                                  6.39
                                  
                                  
                                  
                                  0.50
                                  
                                  
                                  
                                  6.89Other
                                  
                                  
                                  1
                                  
                                  
                                  
                                  3
                                  
                                  
                                  
                                  4
                                  
                                  
                                  
                                  0.38
                                  
                                  
                                  
                                  1.25
                                  
                                  
                                  
                                  1.63Total
                                  
                                  
                                  16
                                  
                                  
                                  
                                  4
                                  
                                  
                                  
                                  20
                                  
                                  
                                  
                                  8.77
                                  
                                  
                                  
                                  1.75
                                  
                                  
                                  
                                  10.52Development(a)Michigan
      Antrim
                                  
                                  
                                  162
                                  
                                  
                                  
                                  9
                                  
                                  
                                  
                                  171
                                  
                                  
                                  
                                  91.53
                                  
                                  
                                  
                                  4.93
                                  
                                  
                                  
                                  96.46New
      Albany
                                  
                                  
                                  12
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  12
                                  
                                  
                                  
                                  0.60
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  0.60Other
                                  
                                  
                                  6
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  6
                                  
                                  
                                  
                                  3.95
                                  
                                  
                                  
                                  -
                                  
                                  
                                  
                                  3.95Total
                                  
                                  
                                  180
                                  
                                  
                                  
                                  9
                                  
                                  
                                  
                                  189
                                  
                                  
                                  
                                  96.08
                                  
                                  
                                  
                                  4.93
                                  
                                  
                                  
                                  101.01





(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.


10


(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 which are included in the December 31, 2008
  totals.





(e)
            At
      December 31, 2008, we had 5 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 utilize a gas
marketing firm for the sale of production. Effective June 1, 2007, we 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. Since the expiration of the firm sales contract on
December 31, 2008, the Company has been negotiating 4,500 mmbtu per day on a
month by month basis.  We are currently in discussions about the
possibility of entering into a long term contract.  Our average daily
production for operated Antrim was 5,259 mmbtu per day for 2008. 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.





On
October 1, 2008, we received a notice of early termination from BNP with respect
to our then existing natural gas and interest rate swap derivatives (the “Early
Termination Notice”) in accordance the 1992 International Swap Dealers
Association, Inc. (“ISDA”) master agreement dated August 20, 2007 between the
Company and BNP.  The Early Termination notice amounted to
approximately $1.6 million for the interest rate swap derivative and $0.6
million for the natural gas derivatives.  The total settlement amount
due in the approximate amount of $2.2 million has been classified as a liability
included with the senior secured credit facility.  For the year ended
December 31, 2008, the effect of the termination of our natural gas derivatives
resulted in a loss of oil and gas revenue in the approximate amount of $1.2
million.  If natural gas continues selling at current prices, our oil
and gas revenue will be impacted negatively due to the inability to benefit from
gains resulting from hedged production.  Based on a sales price of
$4.50 per mcf, we estimate lost revenues from our terminated natural gas
contracts to be $10.8 million, $10.7 million, and $8.0 million for the years
ending December 31, 2009, 2010, and 2011, respectively.  As a result
of the natural gas derivative contracts and interest rate contract terminations,
we are presently exposed to the fluctuation of natural gas prices and
fluctuation of interest rates.


11




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 storybuilding, plus common
areas and 15 covered parking spaces. We moved our corporate offices into this
space on December 5, 2005.




Employees




As of December 31, 2008, we had 61
full-time employees and 2 part-time employees.  Of our 61 full-time
employees 29 are employed by Bach Services & Manufacturing Co. LLC, a
subsidiary engaged in oil and gas field services. We are not a party to any
collective bargaining agreements. We believe that our relations with our
employees are good.




Competition
and markets




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




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


12




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 subjectto 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 ofdoing 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.


13




A permit from the EPA and the Michigan
Department of Environmental Quality (‘DEQ”) 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. We
are currently in discussions with the DEQ regarding water quality issues from
certain wells in Arrowhead, Blue Chip, and Gaylord Fishing Club
projects.  In 2007, the DEQ instituted a water sampling and monitoring
requirement for wells north of a line of demarcation that includes most of our
Antrim projects.  The drilling permits for new wells in this area now
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 agreed to plug five of the six wells requested and
collected a new round of water samples from each requested well for additional
analysis.




In September 2008, we received a notice
of violation from the DEQ requesting a proposal from management to plug 25 wells
in the Arrowhead and Blue Chip projects.  Five of the wells listed on
this notice had been agreed to during the January 31, 2008 meeting and were
plugged during 2008.  In December 2008, we met again with the DEQ to
discuss the remaining wells.  We agreed to shut-in three additional
wells, bringing total shut-in wells to 13, and continue to provide water samples
for the remaining wells for further analysis.  We are expecting to
meet again with the DEQ in March 2009 to discuss the results.  There
is no assurance that we will not be required to plug the remaining wells in the
Arrowhead project.  If we are required to plug the remaining wells,
operations are not expected to be materially impacted as most of these wells are
uneconomic.  We anticipate plugging costs of approximately $12,000 per
well if we are required to plug the remaining wells.




To date, compliance with environmental
laws and regulations has not required the expenditure of any material amount of
money. Since environmental laws and regulations are periodically amended, we are
unable to predict the ultimate cost of compliance. To our knowledge, other than
the potential water quality issue described above, 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.


14




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





We
are currently in default with our lenders.




We are currently in default under our
senior secured credit facility and second lien term loan.  We are
currently operating under a forbearance agreement with the senior secured credit
facility which expires on April 30, 2009.  We received notice of
default under the second lien term loan in October 2008.  Under the
terms of the second lien term loan no enforcement action can be taken against us
for at least 180 days beginning November 24, 2008.  While we have
previously entered into a series of forbearance agreements and voluntary
standstill periods there can be no assurance once the current forbearance period
ends under the senior secured credit facility and the 180 days expires under the
second lien term loan that the lenders will not enforce their rights and
remedies under the agreements and demand partial or full payment.




We are currently in discussions with
our current lenders to restructure our debt obligations and continue to seek
alternative financing arrangements.  There can be no assurance we will
be successful in restructuring our debt or finding alternative financing
arrangements.  If we are unsuccessful restructuring our current debt
obligations or securing alternative financing arrangements, our liquidity would
be affected in a material manner and we may elect to file for bankruptcy
protection.




Our
independent registered public accounting firm’s report on our 2008 consolidated
financial statements contains an explanatory paragraph expressing substantial
doubt about our ability to continue as a going concern.




As a
result of our recurring losses from operations, loss of production, significant
deficiencies in working capital, increases in interest rates, termination of our
natural gas and interest rate derivatives, and limited capital resources, our
independent registered public accounting firm’s report on our consolidated
financial statements as of December 31, 2008 and the years ended December 31,
2008 and 2007 includes an explanatory paragraph expressing substantial doubt
about our ability to continue as a going concern.


15


We
have a history of losses.




We
reported a net loss for the years ended December 31, 2008, 2007 and
2006.  There can be no assurance that we will be able to achieve and
maintain profitability.




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, 2008, natural gas prices quoted for the near month NYMEX contract
have ranged from a low of $4.67 per mmbtu to a high of $13.61 per mmbtu. The
prices for natural gas are subject to a variety of factors beyond our control,
including:





•
            the
      level of consumer product demand;


•
            weather
      conditions and fluctuating and seasonal
demand;


•
            domestic
      and foreign governmental relations, regulations, and
    taxation;


•
            the
      price and availability of alternative
fuels;


•
            political
      conditions in oil and natural gas producing
  regions;


•
            the
      domestic and foreign supply of oil and natural gas including U.S.
      inventories of natural gas and oil
reserves;


•
            speculative
      trading and other market
uncertainty;


•
            technological
      advances affecting energy
consumption;


•
            impact
      of energy conservation efforts;


•
            the
      cost, proximity and capacity of natural gas pipelines and other
      transportation facilities; and


•
            overall
      domestic and global economic
conditions.





Failure
to hedge our production may result in losses.





On October 1, 2008, we received a
notice of early termination for all our natural gas derivatives due to our
default on the senior secured credit facility and second lien term
loan.  Currently, we do not have the ability to hedge our production
due to our bank defaults and the lack of borrowing base capacity to meet margin
calls.  By failing to hedge our production, we are more adversely
affected by declines in natural gas prices than our competitors who are
currently engaged in hedging arrangements.  For example, for the year
ended December 31, 2008, the effect of the termination of our natural gas
derivatives resulted in a loss of oil and gas revenue in the approximate amount
of $1.2 million.  If natural gas continues selling at current prices,
our oil and gas revenue will be impacted negatively due to the inability to
benefit from gains resulting from hedged production.  Based on a sales
price of $4.50 per mcf, we estimate lost revenues from our terminated natural
gas contracts to be $10.8 million, $10.7 million, and $8.0 million for the years
ending December 31, 2009, 2010, and 2011, respectively.





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, joint venture relationships, and/or
acquire properties containing proved reserves.  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 and joint venture 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.  Thus, our
future natural gas reserves and production and, therefore, our cash flow and
income are highly dependent on our success in efficiently developing and
exploiting our current reserves and economically finding or acquiring additional
recoverable reserves. Our ability to find and acquire additional recoverable
reserves to replace current and future production at acceptable costs depends on
our generating sufficient cash flow from operations and other sources of
capital, including our joint venture partnerships, all of which are subject to
the risks discussed elsewhere in this section.


16


Some
of our undeveloped leasehold acreage is subject to leases that may expire in the
near future.





Leases covering approximately 148,429
of our 651,389 net acres, or 23%, are scheduled to expire on or before December
31, 2009.  An additional 72% of our net acres are scheduled to expire
in the years 2010 and 2011.  If we are unable or choose not to renew
these leases or any leases scheduled for expiration beyond December 31, 2009 we
will lose the right to develop the acreage that is covered by an expired lease
which would impair our ability to expand our reserves and
production.





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.





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, 2008, 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 find joint venture or farmout partners 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 whether we
will be able to find suitable joint venture or farmout partners, whether our
numerous potential drilling locations will ever be drilled, or whether natural
gas will ever be produced from these or any other potential drilling locations,
which could materially affect our business.





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, 2008, we
operated 31% of our gross wells and 63% of our net wells. We anticipate that in
the future the percentage of gross wells that we operate may
decline.  As a result of these varying levels of management control,
for those properties that we do not operate, we have no control
over:





•
              the
      number and location of wells to be
drilled;


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


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


•
            the
      timing and amounts of production;


•
            the
      approval of other participants in drilling
  wells;


•
            development
      and operating costs;


•
            capital
      calls on working interest
owners; and


•
            pipeline
      nominations.


17


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, 2008, we had acquired
approximately 1,164,460 (651,389 net) acres with 98,050 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, 2008, approximately 56% are classified as proved developed
producing, 17% are classified as proved developed non-producing, and 27% are
classified as proved undeveloped.





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





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




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




•
            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 we are currently unable
      to access significant capital for these expenditures;
  and


18




•
            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:





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





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





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





•
            The
      reserve report for our Michigan Antrim 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;





•
            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;





•
            We
      may be unable to expend the capital resources required to achieve and
      maintain production within the time frame assumed in the calculation of
      revenues; and





•
            Unanticipated
      regulatory problems not contemplated in the calculation of reserves may
      defer or impair production.


19


Drilling for and producing natural
gas are high-risk activities with many uncertainties.





Our
drilling activities are subject to many risks, including the risk that we will
not discover commercially productive reservoirs. Drilling for natural gas can be
uneconomic, not only from dry holes, but also from productive wells that do not
produce sufficient revenues to be commercially viable. In addition, our drilling
and producing operations may be curtailed, delayed or canceled as a result of
other factors, including:





•
            the
      high cost, shortages or delivery delays of equipment and
      services;





•
            unexpected
      operational events and drilling
conditions;





•
            adverse
      weather conditions, including
flooding;





•
            facility
      or equipment malfunctions;





•
            title
      problems;





•
            pipeline
      ruptures or spills;





•
            compliance
      with environmental and other governmental
  requirements;





•
            unusual
      or unexpected geological
formations;





•
            formations
      with abnormal pressures;





•
            injury
      or loss of life;





•
            environmental
      accidents such as gas leaks, ruptures or discharges of toxic gases, brine
      or well fluids into the environment or , including groundwater
      contamination;





•
            fires,
      blowouts, craterings and explosions;
and





•
            uncontrollable
      flows of natural gas or well
fluids.




Any one
or more of the factors discussed above could reduce or delay our receipt of
production revenues, thereby reducing our earnings.  In addition, any
of these events can cause substantial losses, including personal injury or loss
of life, damage to or destruction of property, natural resources and equipment,
pollution, environmental contamination, loss of wells and regulatory
penalties.





Although
we will maintain insurance against various losses and liabilities arising from
our operations, insurance against all operational risks is not available to us.
Additionally, we may elect not to obtain insurance if we believe that the cost
of available insurance is excessive relative to the perceived risks presented.
Losses could, therefore, occur for uninsurable or uninsured risks or in amounts
in excess of existing insurance coverage. The occurrence of an event that is not
fully covered by insurance could reduce our results of operations.





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, natural disasters such as fire and flooding, 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 and maintaining 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.


20


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 us to discontinue
operations in certain areas, and has required us to plug certain wells as a
result of the outcome of water quality tests.  We have no control over
this type of regulatory delay or loss of producing wells.





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. 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, on occasion 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.





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.





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.


21


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.





Our
electricity sources may be unreliable, resulting in interference with
production.





We have experienced a problem with
periodic electricity outages, particularly in the area of our Antrim
wells.  Because our pumps are powered by electricity, such outages can
reduce our production until each of the affected pumps is
restarted.





Equipment
failures may reduce our production.





We have experienced significant
production down time due to failed equipment in our wells and production
facilities.  There is no assurance that our well enhancement program
will remediate this problem, or that we will be able to retain the services of
experts who can improve the maintenance and repair of our wells sufficiently to
reduce down time.





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.


22


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
(10% working 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.





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.  As of
December 31, 2008, we recorded a ceiling write-down of $78.5
million.  The write-down of oil and gas properties is not reversible
at a later date.  Additional write-downs in future years may be
required if the ceiling is exceeded again.





We
face risks rising from potential material weaknesses in our internal control
environment.




Our management, including our Chief
Executive Officer and Chief Financial Officer, do not expect that our disclosure
controls or our internal audit controls can prevent all possible error or
fraud.  A control system, no matter how well conceived and operated,
can provide only reasonable, not absolute assurances 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 assurances that any design will
succeed in achieving its stated goals under all potential future condition;,
over time, controls may be 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.


23


At December 31, 2008, a material
weakness was identified in our reserve reporting process as further described in
management’s report on internal control over financial reporting included in
Item 8 of this report.  While management believes we will be able to
successfully remediate this material weakness, our remedial actions may prove to
be ineffective or inadequate and expose us to further risk of misstatements in
our financial statements.  In such circumstances, investors and other
users of our financial statements may lose confidence in the reliability of our
financial information and we could fail to comply with certain representations,
warranties and covenants in our debt and other financing-related agreements or
be obligated to incur additional costs to improve our internal
controls.




Because
we handle natural gas and oil, we may incur significant costs and liabilities in
the future resulting from a failure to comply with new or existing environmental
regulations or an accidental release of hazardous substances into the
environment.





The
operations of our wells and other facilities are subject to stringent and
complex federal, state and local environmental laws and regulations. These
include, for example:




•
            the
      federal Clean Air Act and comparable state laws and regulations that
      impose obligations related to air
emissions;





•
            the
      federal Clean Water Act and comparable state laws and regulations that
      impose obligations related to discharges of pollutants into regulated
      bodies of water;





•
            Resource
      Conservation and Recovery Act (“RCRA”) and comparable state laws that
      impose requirements for the handling and disposal of waste, including
      produced waters, from our facilities;
and





•
            Comprehensive
      Environmental Response, Compensation, and Liability Act (“CERCLA”)
      and comparable state laws that regulate the cleanup of hazardous
      substances that may have been released at properties currently or
      previously owned or operated by us or at locations to which we have sent
      waste for disposal.





Failure
to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial requirements, and
the issuance of orders enjoining future operations. Certain environmental
statutes, including the RCRA, CERCLA, and analogous state laws and regulations,
impose strict, joint and several liability for costs required to clean up and
restore sites where hazardous substances have been disposed of or otherwise
released. Moreover, it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other waste products into the
environment.





There is
an inherent risk that we may incur environmental costs and liabilities due to
the nature of our business and the substances we handle. For example, an
accidental release from one of our wells could subject us to substantial
liabilities arising from environmental cleanup and restoration costs, claims
made by neighboring landowners and other third parties for personal injury and
property damage, and fines or penalties for related violations of environmental
laws or regulations. Moreover, the possibility exists that stricter laws,
regulations or enforcement policies may be enacted or adopted and could
significantly increase our compliance costs and the cost of any remediation that
may become necessary. We may not be able to recover remediation costs under our
insurance policies.


24


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.  As described above, we have recently been
required to plug wells as a result of water quality issues.





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 ended December
31, 2008, our stock traded as high as $4.59 per share and as low as $0.07 per
share. The market price of our common stock may fluctuate significantly in
response to a number of factors some of which are within our control such as non
compliance with debt covenants and other lender requirements and lack of access
to credit markets.  Other factors are beyond our control,
including:





•      changes
in natural gas prices;


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


•      quarterly
variations in operating results;


•      changes
in financial estimates by securities analysts;


•      changes
in market valuations of other similar companies;


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


25




•      additions
or departures of key personnel;


•      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.





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, 2008, we had 103,282,788
shares of common stock outstanding and no shares of preferred stock
outstanding.





At December 31, 2008, we had warrants
and options outstanding that were exercisable for 4,533,944 shares of our common
stock. We have an additional 2,257,500 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.





The issuance of a large number of
shares of our common stock in connection with future acquisitions, equity
financing, debt restructuring or otherwise, could cause the market price of our
common stock to decline significantly. As of December 31, 2008, we had
approximately 103.3 million shares of common stock issued and outstanding,
including approximately 5.0 million shares of our common stock held or
controlled by our executive officers and directors. Of those 5.0 million
shares, 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.




We
could be delisted, resulting in a less robust trading market for our
shares.
 
 Because
of our recent financial difficulties and low trading price, we are at risk of
being delisted by the NYSE Alternext US LLC (formerly known as the American
Stock Exchange).  If this occurs, our shares may be traded over the
counter, which is likely to result in lower visibility for our stock and lower
trading volumes.


ITEM
      1B.
            UNRESOLVED
      STAFF COMMENTS





None.





ITEM
      2.
            PROPERTIES





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


26


ITEM
      3.
            LEGAL
      PROCEEDINGS





Refer to
Note 12 beginning on page 91 of the Form 10-K.





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, 2008.




27


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 NYSE Alternext US LLC (formerly known as the American Stock
Exchange) ("AMEX").  The following chart shows the range of high and
low sales prices for our common stock for each fiscal quarter in the two most
recent fiscal years.





Quarter Ended
              
              High
                Sales Price
              
              
              Low
                Sales PriceMarch 31,
      2007
              
              $
              3.30
              
              
              $
              2.06June
      30, 2007
              
              $
              2.77
              
              
              $
              1.30September
      30, 2007
              
              $
              2.35
              
              
              $
              1.37December
      31, 2007
              
              $
              1.75
              
              
              $
              1.16March
      31, 2008
              
              $
              1.57
              
              
              $
              0.53June
      30, 2008
              
              $
              0.92
              
              
              $
              0.39September
      30, 2008
              
              $
              0.51
              
              
              $
              0.12December
      31, 2008
              
              $
              0.20
              
              
              $
              0.07





On March
3, 2009, the last reported sale price of our common stock on AMEX was $0.07 and
there were 103,282,788 shares of our common stock outstanding and approximately
498 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.





28


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
trading on the AMEX on December 29, 2006, and ending on the close of trading on
the AMEX on December 31, 2008.  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





During October 2005, the Company
(formerly Cadence) acquired Aurora through the wholly-owned subsidiary with and
into Aurora.  As a result of the merger, Aurora became a wholly-owned
subsidiary.





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.


29


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, 2008, we
had awarded restricted stock and options to purchase restricted stock in a total
amount of 5,742,500 shares, leaving 2,257,500 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, 2008 regarding the shares of our common stock (i)
issuable upon exercise of options or warrants granted as compensation for
services; and (ii) available for grant under existing plans (No of Securities in
thousands).





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
                    
                    
                    4,178
                    
                    
                    $
                    2.11
                    
                    
                    
                    2,258Equity
      compensation plans and awards not approved by security
    holders
                    
                    
                    56
                    (a)
                    
                    $
                    1.25
                    
                    
                    
                    -0-Total/combined
                    
                    
                    4,234
                    
                    
                    $
                    2.10
                    
                    
                    
                    2,258




(a)
            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.




UNREGISTERED
EQUITY SALES/PURCHASES





None.


30


ITEM
6.     SELECTED HISTORICAL FINANCIAL DATA




The
following table sets forth our December 31, 2008, 2007, 2006, 2005, and 2004
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, 2008, 2007, 2006, 2005,
and 2004 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.





2008
                  
                  
                  2007
                  
                  
                  2006
                  
                  
                  2005(a)
                  
                  
                  2004(a)Statement
      of Operations DataReve
      nues:Oil
      and natural gas sales
                  
                  $
                  25,201,777
                  
                  
                  $
                  26,723,818
                  
                  
                  $
                  21,591,811
                  
                  
                  $
                  6,743,444
                  
                  
                  $
                  960,011Pipeline
      transportation and marketing
                  
                  
                  710,250
                  
                  
                  
                  578,020
                  
                  
                  
                  489,473
                  
                  
                  
                  -
                  
                  
                  
                  -Field
      service and sales
                  
                  
                  3,051,419
                  
                  
                  
                  390,401
                  
                  
                  
                  125,611
                  
                  
                  
                  -
                  
                  
                  
                  -Interest
      and other
                  
                  
                  877,488
                  
                  
                  
                  549,149
                  
                  
                  
                  220,592
                  
                  
                  
                  666,850
                  
                  
                  
                  1,240,513Total
      revenues
                  
                  
                  29,840,934
                  
                  
                  
                  28,241,388
                  
                  
                  
                  22,427,487
                  
                  
                  
                  7,410,294
                  
                  
                  
                  2,200,524Expenses:Production
      taxes
                  
                  
                  1,338,397
                  
                  
                  
                  1,123,070
                  
                  
                  
                  877,319
                  
                  
                  
                  506,635
                  
                  
                  
                  72,001Production
      and lease operating expense
                  
                  
                  9,995,981
                  
                  
                  
                  8,424,096
                  
                  
                  
                  5,966,341
                  
                  
                  
                  1,587,205
                  
                  
                  
                  542,337Pipeline
      and processing operating expense
                  
                  
                  593,059
                  
                  
                  
                  482,647
                  
                  
                  
                  265,795
                  
                  
                  
                  -
                  
                  
                  
                  -Field
      services expense
                  
                  
                  2,439,939
                  
                  
                  
                  321,753
                  
                  
                  
                  90,913
                  
                  
                  
                  -
                  
                  
                  
                  -General
      and administrative expense
                  
                  
                  9,075,903
                  
                  
                  
                  8,029,122
                  
                  
                  
                  7,531,718
                  
                  
                  
                  3,435,507
                  
                  
                  
                  2,057,333Oil
      and natural gas depletionand
      amortization
                  
                  
                  5,380,106
                  
                  
                  
                  3,769,104
                  
                  
                  
                  2,681,290
                  
                  
                  
                  767,511
                  
                  
                  
                  203,249Other
      assets depreciation and amortization
                  
                  
                  1,193,993
                  
                  
                  
                  2,396,026
                  
                  
                  
                  2,083,191
                  
                  
                  
                  308,647
                  
                  
                  
                  -Interest
      expense
                  
                  
                  9,201,343
                  
                  
                  
                  4,582,021
                  
                  
                  
                  4,573,785
                  
                  
                  
                  1,307,370
                  
                  
                  
                  392,402Ceiling-write
      down of oiland
      gas properties
                  
                  
                  78,457,801
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Goodwill
      impairment
                  
                  
                  19,373,264
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Loss
      on debt extinguishment
                  
                  
                  -
                  
                  
                  
                  3,448,520
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Taxes,
      other
                  
                  
                  77,671
                  
                  
                  
                  19,021
                  
                  
                  
                  250,884
                  
                  
                  
                  29,651
                  
                  
                  
                  75,000Total
      expenses
                  
                  
                  137,127,457
                  
                  
                  
                  32,595,380
                  
                  
                  
                  24,321,236
                  
                  
                  
                  7,942,526
                  
                  
                  
                  3,342,322Loss
      before minority interest
                  
                  
                  (107,286,523
                  )
                  
                  
                  (4,353,992
                  )
                  
                  
                  (1,893,749
                  )
                  
                  
                  (532,232
                  )
                  
                  
                  (1,141,798
                  )Minority
      interest in income of subsidiaries
                  
                  
                  (78,139
                  )
                  
                  
                  (67,841
                  )
                  
                  
                  (50,898
                  )
                  
                  
                  15,960
                  
                  
                  
                  38,087Net
      loss
                  
                  
                  (107,364,662
                  )
                  
                  
                  (4,421,833
                  )
                  
                  
                  (1,944,647
                  )
                  
                  
                  (516,272
                  )
                  
                  
                  (1,103,711
                  )Less
      dividends on preferred stock
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  (30,268
                  )Loss
      attributable to common shareholders
                  
                  $
                  (107,364,662
                  )
                  
                  $
                  (4,421,833
                  )
                  
                  $
                  (1,944,647
                  )
                  
                  $
                  (516,272
                  )
                  
                  $
                  (1,133,979
                  )Net
      loss per common share – basicand
      diluted
                  
                  $
                  (1.04
                  )
                  
                  $
                  (0.04
                  )
                  
                  $
                  (0.02
                  )
                  
                  $
                  (0.01
                  )
                  
                  $
                  (0.05
                  )Weighted
      average common shares  outstanding – basic and
      diluted
                  
                  
                  103,062,697
                  
                  
                  
                  101,633,162
                  
                  
                  
                  82,288,243
                  
                  
                  
                  40,622,000
                  
                  
                  
                  23,636,000Cash
      Flow DataCash
      provided by operating activities
                  
                  $
                  4,098,818
                  
                  
                  $
                  10,079,049
                  
                  
                  $
                  5,467,910
                  
                  
                  $
                  (2,404,739
                  )
                  
                  $
                  218,441Cash
      used by investing activities
                  
                  
                  (10,701,427
                  )
                  
                  
                  (61,100,489
                  )
                  
                  
                  (89,606,098
                  )
                  
                  
                  (39,869,326
                  )
                  
                  
                  (8,716,784
                  )Cash
      provided by financing activities
                  
                  
                  14,182,069
                  
                  
                  
                  51,711,722
                  
                  
                  
                  73,892,946
                  
                  
                  
                  49,075,121
                  
                  
                  
                  12,632,173





(a)
            We
      acquired Aurora Energy, Ltd. (“Aurora”) on October 31, 2005 through the
      merger of our wholly-owned subsidiary with and into Aurora.  The
      acquisition of Aurora was accounted for as a reverse merger, with Aurora
      being the acquiring party for accounting purposes.  As a result
      of the reverse merger, the historical financial statements presented for
      periods prior to the acquisition date are the financial statements of
      Aurora.  The operations of the former Cadence Resources
      Corporation (now known as Aurora Oil & Gas Corporation) businesses
      have been included in the financial statements from the date of
      acquisition.


31





As
      of December 31,2008
                
                
                2007
                
                
                2006
                
                
                2005
                
                
                2004Balance
      Sheet DataCash
      and cash equivalents
                
                $
                10,005,138
                
                
                $
                2,425,678
                
                
                $
                1,735,396
                
                
                $
                11,980,638
                
                
                $
                5,179,582Other
      current assets
                
                
                5,411,250
                
                
                
                8,901,774
                
                
                
                11,306,797
                
                
                
                7,274,869
                
                
                
                2,636,114Oil
      and natural gas properties, net(using
      full cost accounting)
                
                
                116,426,381
                
                
                
                205,260,103
                
                
                
                161,471,277
                
                
                
                68,960,754
                
                
                
                14,967,457Other
      property and equipment, net
                
                
                14,451,523
                
                
                
                14,923,840
                
                
                
                10,465,897
                
                
                
                3,610,138
                
                
                
                -Other
      assets
                
                
                13,906,789
                
                
                
                23,160,273
                
                
                
                27,407,825
                
                
                
                24,995,746
                
                
                
                662,676Total assets
                
                $
                160,201,081
                
                
                $
                254,671,668
                
                
                $
                212,387,192
                
                
                $
                116,822,145
                
                
                $
                23,445,829Current
      liabilities
                
                $
                127,312,547
                
                
                $
                8,580,990
                
                
                $
                18,040,082
                
                
                $
                17,279,518
                
                
                $
                6,085,330Long-term
      debt, net of currentmaturities
                
                
                5,265,459
                
                
                
                113,835,028
                
                
                
                54,538,138
                
                
                
                42,794,862
                
                
                
                11,090,369Minority
      interest in net assets of subsidiaries
                
                
                467,937
                
                
                
                112,661
                
                
                
                77,873
                
                
                
                61,913
                
                
                
                23,826Shareholders’
      equity
                
                
                27,155,138
                
                
                
                132,142,989
                
                
                
                139,731,099
                
                
                
                56,685,852
                
                
                
                6,246,304Total liabilities and
      shareholders’ equity
                
                $
                160,201,081
                
                
                $
                254,671,668
                
                
                $
                212,387,192
                
                
                $
                116,822,145
                
                
                $
                23,445,829





32


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 an
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 (“Cadence”). We acquired Aurora Energy, Ltd.
("Aurora") on October 31, 2005 through the merger of our wholly-owned subsidiary
with and into Aurora. The acquisition of Aurora was accounted for as a reverse
merger, with Aurora being the acquiring party for accounting purposes. The
Aurora executive management team also assumed management control at the time the
merger closed, and we moved our corporate offices to Traverse City, Michigan.
Effective May 11, 2006, Cadence amended its articles of incorporation to change
the parent name to Aurora Oil & Gas Corporation (“AOG”).




Operational
Highlights





As of
December 31, 2008, our leasehold acres were 1,164,460 (651,389 net) which
represent a 9% decrease over our December 31, 2007 net acres. This decrease
primarily resulted from the sale of our Oak Tree Project acreage of 37,325
(33,219 net) acres in September 2008 which accounted for all our acreage within
the Woodford shale play located in Oklahoma.  Our remaining leasehold
acres are included in the following plays: 286,390 (134,003 net) leasehold acres
in the Antrim shale play, 787,595 (449,183 net) acres in the New Albany shale
play, and 90,475 (68,203 net) acres in the Other play areas.




With
regard to our drilling activities, we drilled or participated in 26 (6 net)
wells for the year ended December 31, 2008, with an 88% success
rate.  As of December 31, 2008, we had 628 (281 net) producing wells,
31 (11 net) wells awaiting hook-up, 20 (7 net) wells undergoing resource
assessment and 54 (37 net) wells temporarily abandoned.




We began
2008 with estimated proved reserves of 166.6 bcfe and at December 31, 2008 had
98.0 bcfe, a decrease of 68.6 bcfe, or 41%. The New Albany shale provided a
modest increase in proved reserves during the year, adding a net 1.0 bcfe, which
is a 4% increase over the 25 bcfe reported on December 31, 2007.  The
Antrim shale proved reserves were reduced by a net 69.3 bcfe due to the
following recent developments:


33


·
              Reserves
      were reduced by 3.0 bcfe due to production during the
  year.


·
            A
      reduction in natural gas prices (from an average of $7.18 per mcf on
      December 31, 2007, to an average of $6.07 per mcf on December 31, 2008)
      has caused a reduction in the volume of natural gas that can be
      economically produced.  We attribute approximately 7.9 bcfe of
      the reduction in Antrim shale proved reserves to be attributable to lower
      natural gas prices.


·
            As
      a result of changes in regulatory criteria, the Michigan Department of
      Environmental Quality (“DEQ”) forced us to plug 5 wells and shut in 13
      wells during 2008 due to water quality issues, resulting in a setback in
      our efforts to dewater the Antrim shale in the Arrowhead
      project.  Furthermore, the DEQ blocked our efforts to drill
      additional wells needed for dewatering.  With no means to
      effectively dewater the project area, performance of the existing wells
      resulted in net reserve reduction of 7.1 bcfe on the three producing units
      in the project.


·
            Due
      to the DEQ issues cited above, the absence of available capital needed to
      install infrastructure for existing wells and drill additional wells, and
      lack of performance of wells in the Arrowhead project, the proved reserves
      associated with the Blue Lakes Unit, Tomahawk 26 Unit, Tomahawk 27 Unit
      and Tomahawk 35 Unit were eliminated, resulting in a reduction of 12.8
      bcfe.


·
            Our
      Antrim shale proved reserves have historically been determined by our
      third party reserve engineers using type curves derived from a combination
      of reservoir simulation and production performance from nearby more mature
      Antrim shale units operated by others.  At the end of 2007, the
      type curves were modified to conform to our historical production history
      to date, but we had an insufficient amount of production on our working
      interest units to significantly alter the type curves.  Now that
      we have sufficient data to develop decline curves for our wells, our
      engineers have based their projections of future production volumes on
      actual historical data from our own wells instead of representative data
      from other wells in the Antrim play.  Not only did this affect
      the proved developed producing reserves, but the type curves for proved
      undeveloped reserves were modified accordingly.  This resulted
      in type curves projecting lower reserves, and certain future drilling
      locations with proved undeveloped reserves were eliminated due to
      unacceptable economics. We estimate that approximately 41.3 bcfe of the
      reduction in Antrim shale proved reserves is attributable to this
      change.


·
            We
      added 2.8 bcfe in extensions to proved reserves due to drilling activities
      in various areas.





Oil and
natural gas production for 2008 was 3,044,112 mcfe, or a 5% decrease over the
3,207,155 mcfe produced in 2007.  During 2008, production continued to
be hampered by wells undergoing resource assessment and dewatering in the Antrim
along with damages caused by a fire in our South Knox project.  During
2008, we implemented a well enhancement program on our operated Antrim shale
properties to address our decline in production.  We completed well
enhancement activities on 74 wells and experienced an approximate one to two
days stoppage in production per well to complete the well enhancement
activities.  We also shut down the downhole pumps on various wells that
were producing large volumes of water with insignificant volumes of gas. 
Since we discontinued the pumping operations on these wells, we have observed a
detrimental impact on the gas production levels in the remaining producing
wells.  We believe that maximizing water production from all operated
Antrim shale wells, regardless of their individual economic impact, is necessary
to maximize gas production from the projects as a whole.  Therefore, we
have initiated a renewed well enhancement program in February 2009 that
emphasizes measures that will increase water production.  The program will
be implemented in three phases throughout 2009 with the first phase
incorporating the Hudson 19, Hudson 34, Hudson SW and Hudson West Units. 
As part of this process, we are planning to install water meters at each well
location to track water production.  Additional time will be required
before measurable progress in production can be recognized.  Our
average daily production for 2008 was 8,317 mcfe per day compared to 8,787 mcfe
per day in 2007.  Daily production for operated properties was 5,259
mcfe and 6,397 mcfe for 2008 and 2007, respectively.  Daily production
for non-operated properties was 3,058 and 2,390 mcfe for 2008 and 2007,
respectively.





Effective
September 15, 2008, we closed on the sale to Presidium Energy, LC (“Presidium”)
of all our membership interest in a wholly owned subsidiary, AOK Energy, LLC
(“AOK”).  We participated in a joint venture project known as the “Oak
Tree Project” through AOK.  Presidium is wholly owned and operated by
John V. Miller, who served as our Vice President from November 1, 2005 until he
resigned on February 29, 2008.  Total sales price was $15 million, of
which we received $3 million in cash and entered into a note receivable in the
amount of $12 million.  Under the terms of the note receivable,
Presidium is required to make monthly interest only payments calculated at
9.0%.  The entire outstanding principal balance along with all accrued
interest is due September 10, 2010.  In connection with the sale, we
also received a 3% overriding royalty interest in certain oil and gas leases
located in various counties in Oklahoma.


34





On October 29, 2008, we entered into a
farmout arrangement with Atlas Energy Resource, LLC (“Atlas”) to farm out our
64.43% interest in undeveloped acreage in the Wabash project.  The
Wabash project is a 121,702 gross acre New Albany shale project located in the
Indiana counties of Clay, Greene, Owen, and Sullivan.  Under the terms
of the farmout arrangement Atlas must (1) drill at least 20 horizontal wells on
an annual basis, (2) pay a well site fee, (3) accept responsibility for any
lease obligations, including payments for lease extensions, (4) provide us with
an overriding royalty interest on production, and (5) allow us to participate as
a working interest owner, if requested, in a 25% working interest in any leases
pooled into a drilling unit.  As of the filing of this Form 10-K, no
drilling activities have commenced under the farmout arrangement.





Other
Developments





On October 3, 2008, we received a
notice of default from BNP with respect to the senior secured credit facility
(the “Notice of Default).  The Notice of Default states that an event
of default occurred under (1) Section 10.01(a) of the senior secured credit
facility due to our failure to pay the first of three principal borrowing base
deficiency payments in the approximate amount of $6.6 million, (2) Section
10.01(g) of the senior secured credit facility due to the swap termination
amount in connection with the Early Termination Notice exceeding $500,000, (3)
Section 10.01(f) of the senior secured credit facility due to our failure to pay
the settlement amount of approximately $2.2 million ($0.6 million for natural
gas derivatives and $1.6 million for interest rate derivative) by the due date
of October 2, 2008, in connection with the Early Termination Notice, and (4)
Sections 8.14, 8.18, and 9.01 of the senior secured credit facility and second
lien term loan (cross default) due to our failure to comply with certain
financial and non-financial covenants.




The Notice of Default informed us, as
of October 1, 2008, that the interest rate under the senior secured credit
facility shall bear interest at the default rate of prime plus 3.0%, thereby
increasing our current interest rate under the senior secured credit facility by
2% to approximately 8.0% (which has since declined to the current rate
of  6.25% at March 4, 2009).




On October 6, 2008, we received a
notice of default from Laminar with respect to the second lien term loan (“the
“Term Loan Notice of Default”).  The Term Loan Notice of Default
states that an event of default occurred under (1) Section 10.01(g) of the
second lien term loan due to the swap termination amount in connection with the
Early Termination Notice exceeding $500,000, (2) Section 10.01(f) of the second
lien term loan due to our failure to pay the settlement amount of approximately
$2.2 million ($0.6 million for natural gas derivatives and $1.6 million for
interest rate derivative) by the due date of October 2, 2008, in connection with
the Early Termination Notice, (3) Sections 8.14, 8.18, and 9.01 of the second
lien term loan and the senior secured  credit facility (cross default)
due to our failure to comply with certain financial and non-financial covenants,
and (4) Section 10.01(f) and (g) of the second lien term loan due to our failure
to pay the first of three principal borrowing base deficiency payments in the
approximate amount of $6.6 million under Section 10.01(a) of the senior secured
credit facility (cross default).  Laminar and the syndication under
the second lien term loan cannot take any enforcement or similar actions against
us or our property for at least 180 days beginning November 24, 2008 pursuant to
the terms of the Intercreditor Agreement, dated August 20, 2007, between the
second lien term loan syndication and the senior secured credit facility
syndication.




The Term Loan Notice of Default also
informed us, as of October 1, 2008, that the interest rate under the second lien
term loan will bear interest at the default rate thereby increasing our current
interest rate under the Term Loan by 2% to approximately 15.5%.




Consequently,
all of the above debt is classified as current liabilities as of December 31,
2008.


35


On
February 12, 2009, we entered into a forbearance agreement to the senior secured
credit facility (the “Second Forbearance Agreement”) with BNP Paribas (“BNP” or
the “Administrative Agent”) and the syndication.  In accordance with
the Second Forbearance Agreement, during the period from December 31, 2008 until
April 30, 2009 (the “Second Forbearance Period”), BNP will forbear and refrain
from (i) accelerating any loans outstanding and (ii) taking any other
enforcement action under the senior secured credit facility at law or otherwise
as a result of designated defaults or potential defaults, provided we comply
with the forbearance covenants (collectively, the “Second Forbearance
Covenants”).





A summary
of the Second Forbearance Covenants is as follows: (i) we shall retain and
employ a financial advisor, (ii) we shall deliver to the Administrative Agent an
initial detailed budget on or before February 20, 2009, and provide subsequent
monthly updates, (iii) we shall deliver to the Administrative Agent prior week
aggregated cash balances on or before the last business day of the current week,
(iv) no later than February 23, 2009, we will execute (or cause to be executed)
additional mortgages and no later than February 18, 2009, we will
execute  (or cause to be executed) other security instruments such
that, after giving effect to such additional mortgages and other security
instruments, the syndication will have liens on 100% of our oil and gas
properties, promissory notes, all significant overriding royalties, and all
significant farmout agreements prior to such date, (v) we must obtain prior
written approval of the Administrative Agent to farmout any assets or sell any
assets for more than $200,000; (vi) we shall provide the Administrative Agent
notice of any unwritten or written expressions of interest with respect to the
purchase of assets of the Company or any of its subsidiaries for an amount in
excess of $2.0 million, (vii) we and the financial advisor shall participate in
weekly conference calls with the Administrative Agent and the syndication during
which a financial officer of the Company must provide updates on restructuring,
sale prospects, and cost reduction efforts, (viii) we must deliver to the
Administrative Agent copies of any detailed audit reports, management letters,
or recommendations submitted to the board of directors, (ix) no later than
February 28, 2009, we must deliver a restructuring plan to resolve the borrowing
base deficiency, (x) we must maintain a liquidity position of at least $4.0
million during Second Forbearance Period, and (xi) no later than February 23,
2009, we must obtain the consent of the second lien term loan syndication for us
to defer until no earlier than the termination of the Second Forbearance Period,
payment of the scheduled interest payment currently payable to the second lien
term loan syndication on February 24, 2009.





Our
failure to comply with the Second Forbearance Covenants will terminate the
Second Forbearance Agreement and allow the syndication to exercise any or all of
their rights and remedies purportedly provided to them under the senior secured
credit facility.





On
February 18, 2009, we executed the mortgages, security agreement and pledge
agreement necessary to provide the senior secured credit facility lenders a
first secured lien on substantially all of our oil and gas properties not
previously pledged to them.  We have also complied with the other
Second Forbearance Covenants, except that we have not obtained the consent of
the second lien lenders to defer payment of the $1.6 million interest payment
scheduled to be paid on the second lien term loan on February 24,
2009.  We have received correspondence from BNP dated February 27,
2009 indicating that the first lien lenders agree not to declare a forbearance
termination event as a result of our failure to obtain the consent of the second
lien lenders to defer payment of the interest scheduled to be paid on February
24, 2009, as long as we do not actually make the interest payment during the
Second Forbearance Period.  The entire $1.6 million interest payment
owed to the second lien lenders has been recorded as a liability included with
the second lien term loan debt obligation.  As more fully described
above, Laminar and the second lien term loan syndication cannot take any
enforcement or similar actions against us or our property for at least 180 days
beginning November 24, 2008.


36




RESULTS
OF OPERATIONS


Operating
Statistics




The following table sets forth certain
key operating statistics for the years ended December 31, 2008, 2007, and
2006:





Year
      Ended December 31,2008
                        
                        
                        2007
                        
                        
                        2006Net
      wells drilledAntrim
                        
                        
                        3
                        
                        
                        
                        33
                        
                        
                        
                        93New
      Albany
                        
                        
                        -
                        
                        
                        
                        11
                        
                        
                        
                        7Other
                        
                        
                        2
                        
                        
                        
                        8
                        
                        
                        
                        5Dry
                        
                        
                        1
                        
                        
                        
                        7
                        
                        
                        
                        7Total
                        
                        
                        6
                        
                        
                        
                        59
                        
                        
                        
                        112Total
      producing net wellsAntrim
      – producing
                        
                        
                        262
                        
                        
                        
                        287
                        
                        
                        
                        199Antrim
      – awaiting hookup
                        
                        
                        5
                        
                        
                        
                        7
                        
                        
                        
                        51NAS
      – producing
                        
                        
                        1
                        
                        
                        
                        3
                        
                        
                        
                        1NAS
      – awaiting hookup
                        
                        
                        6
                        
                        
                        
                        5
                        
                        
                        
                        7Other
      – producing
                        
                        
                        18
                        
                        
                        
                        15
                        
                        
                        
                        14Other
      – awaiting hookup
                        
                        
                        -
                        
                        
                        
                        3
                        
                        
                        
                        1Total
                        
                        
                        292
                        
                        
                        
                        320
                        
                        
                        
                        273ProductionNatural
      gas (mcf)
                        
                        
                        2,892,186
                        
                        
                        
                        3,039,714
                        
                        
                        
                        2,517,897Crude
      oil (bbls)
                        
                        
                        25,321
                        
                        
                        
                        27,907
                        
                        
                        
                        22,588Natural
      gas equivalent (mcfe)
                        
                        
                        3,044,112
                        
                        
                        
                        3,207,155
                        
                        
                        
                        2,653,427Average
      daily productionNatural
      gas (mcf)
                        
                        
                        7,902
                        
                        
                        
                        8,328
                        
                        
                        
                        6,898Crude
      oil (bbls)
                        
                        
                        69
                        
                        
                        
                        76
                        
                        
                        
                        62Natural
      gas equivalent (mcfe)
                        
                        
                        8,317
                        
                        
                        
                        8,787
                        
                        
                        
                        7,270Average
      sales prices (excluding all gains (losses) on derivatives)Natural
      gas ($ per mcf)
                        
                        $
                        9.06
                        
                        
                        $
                        6.88
                        
                        
                        $
                        6.95Crude
      oil ($ per bbl)
                        
                        $
                        99.96
                        
                        
                        $
                        69.49
                        
                        
                        $
                        61.96Natural
      gas equivalent ($ per mcfe)
                        
                        $
                        9.44
                        
                        
                        $
                        7.12
                        
                        
                        $
                        7.13Average
      sales prices (including all gains (losses) from
    derivatives)Natural
      gas ($ per mcf)
                        
                        $
                        7.84
                        
                        
                        $
                        8.15
                        
                        
                        $
                        8.02Crude
      oil ($ per bbl)
                        
                        $
                        99.96
                        
                        
                        $
                        69.49
                        
                        
                        $
                        61.96Natural
      gas equivalent ($ per mcfe)
                        
                        $
                        8.28
                        
                        
                        $
                        8.33
                        
                        
                        $
                        8.14Production
      revenue ($ in thousands)Natural
      gas
                        
                        $
                        26,208
                        
                        
                        $
                        20,911
                        
                        
                        $
                        17,510Natural
      gas derivatives-realized (losses) gains
                        
                        
                        (3,537
                        )
                        
                        
                        3,874
                        
                        
                        
                        2,683Crude
      oil
                        
                        
                        2,531
                        
                        
                        
                        1,939
                        
                        
                        
                        1,399Total
                        
                        $
                        25,202
                        
                        
                        $
                        26,724
                        
                        
                        $
                        21,592


37





Year
      Ended December 31,2008
                  
                  
                  2007
                  
                  
                  2006Average
      expenses ($ per mcfe)Production
      taxes
                  
                  $
                  0.44
                  
                  
                  $
                  0.35
                  
                  
                  $
                  0.33Post-production
      expenses
                  
                  
                  0.93
                  
                  
                  
                  0.59
                  
                  
                  
                  0.46Leasing
      operating expenses
                  
                  
                  2.36
                  
                  
                  
                  2.03
                  
                  
                  
                  1.78General
      and administrative expense
                  
                  
                  2.90
                  
                  
                  
                  2.50
                  
                  
                  
                  2.84General
      and administrative expense excluding stock-based
    compensation
                  
                  
                  2.47
                  
                  
                  
                  1.81
                  
                  
                  
                  2.00Oil
      and natural gas depreciation, depletion and amortization
      expense
                  
                  
                  1.19
                  
                  
                  
                  1.18
                  
                  
                  
                  1.01Other
      assets depreciation and amortization
                  
                  
                  0.39
                  
                  
                  
                  0.75
                  
                  
                  
                  0.79Interest
      expense
                  
                  
                  3.02
                  
                  
                  
                  1.43
                  
                  
                  
                  1.72Taxes
                  
                  
                  0.03
                  
                  
                  
                  0.01
                  
                  
                  
                  0.09Number
      of employees including Bach employees
                  
                  
                  63
                  
                  
                  
                  68
                  
                  
                  
                  90




Year
Ended December 31, 2008, compared with Year Ended December 31, 2007





General. For the year ended
December 31, 2008, we had a net loss of $107.4 million, or $(1.04) per diluted
common share, on total revenues of $29.8 million. This compares to a net loss of
$4.4 million, or $(0.04) per diluted common share, on total revenue of $28.2
million during the year ended December 31, 2007. The $103.0 million increase in
net loss is primarily attributable to goodwill write-off in the amount of $19.4
million, ceiling write-down of oil and gas properties in the amount of $78.5
million, increase in interest expense in the amount of $4.6 million, increase in
oil and gas depletion and amortization in the amount of $1.6 million, increase
in production and lease operating expense of $1.6 million, and increase in
general and administrative expense of $1.1 million.  The increases in
expenses were offset by a decrease in other assets depreciation and amortization
of $1.2 million and loss of debt extinguishment of $3.4 million.  The
remaining revenues and expenses amount to a decrease of $0.6
million.





Oil and Natural Gas Sales.
During 2008, oil and natural gas sales were $25.2 million compared to $26.7
million in 2007.  We produced 3,044,112 mcfe at a weighted average
price of $8.28 compared to 3,207,155 mcfe at a weighted average price of
$8.33.  This decrease in oil and gas sales was primarily related to
the realization of losses from natural gas derivative contracts in the amount of
$3.5 million.  The losses realized on natural gas derivative contracts
were offset by increases in natural gas prices.  We had 281 net wells
producing as of December 31, 2008, as compared to 305 net wells producing as of
December 31, 2007.  The decrease in producing net wells is
attributable to our effort to reduce operating expenses by shutting in various
uneconomic wells.  Production from the Antrim shale play represented
approximately 86% of our oil and natural gas revenue for 2008.





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




Year
      Ended
                                December
      31, 2008
                              
                              
                              Year
      Ended
                                December
      31, 2007Play/Trend
                              
                              (mcfe)
                              
                              
                              Amount
                              
                              
                              (mcfe)
                              
                              
                              AmountAntrim
                              
                              
                              2,789,727
                              
                              
                              $
                              21,705,991
                              
                              
                              
                              2,975,715
                              
                              
                              $
                              24,346,250New
      Albany
                              
                              
                              100,678
                              
                              
                              
                              948,677
                              
                              
                              
                              57,186
                              
                              
                              
                              404,967Other
                              
                              
                              153,707
                              
                              
                              
                              2,547,109
                              
                              
                              
                              174,254
                              
                              
                              
                              1,972,601Total
                              
                              
                              3,044,112
                              
                              
                              $
                              25,201,777
                              
                              
                              
                              3,207,155
                              
                              
                              $
                              26,723,818


38


Production from the year ended December
31, 2008 compared to the year ended December 31, 2007, decreased by
5%.  Lower than expected production resulted from damage to our South
Knox facility caused by a fire and flooding, pumping deficiencies, and continued
dewatering problem within the Antrim play.  During the first and
second quarter, we also experienced delays from Warner Plant outages and heavy
snowfall causing delays in response to freezing complications associated with
compressors, booster stations, and water lines.





We have also instituted an Antrim
remediation program pursuant to which we plan to reinstate to producing status
certain uneconomic wells that we previously shut in due to significant water
production.  Since we shut in these wells, we have observed gas
production from surrounding wells simultaneously declining.  We
believe pumping water from these uneconomic wells will increase gas production
from the surrounding wells. As part of this process, we are also planning to
install water meters at each well location to track water
production.





Pipeline Transportation and
Processing.  Pipeline transportation and processing revenues
were $0.7 million in 2008 compared to $0.6 million in 2007.  This
amount represents billings to royalty and working interest owners which are not
expected to fluctuate significantly from year-to-year.





Field Service and
Sales.Field service and sales revenues were $3.1 million in
2008 compared to $0.4 million in 2007.  In 2007, the majority of
services performed by our field services subsidiary, Bach Services and
Manufacturing Co., LLC (“Bach”), were performed for us.  The increase
in 2008 was attributable to shifting Bach’s services to unrelated third
parties.





Interest and Other
Revenues.Interest and other revenues were $0.9 million in
2008 compared to $0.5 million in 2007.  The increase is primarily
related to interest received on the Presidium Energy, LC note receivable in the
amount of $0.3 million.





Production
Taxes.Production taxes were $1.3 million in 2008 compared to
$1.1 million in 2007. This increase is attributed to an increase in natural gas
prices which determined the amount of production taxes charged for Michigan
properties.  On a unit of production basis, production taxes were
$0.44 per mcfe in 2008 compared to $0.35 per mcfe in 2007.




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, which
includes marketing, transportation, processing and expenses to operate the wells
and equipment on producing leases.





Production
and lease operating expenses were $10.0 million in 2008 compared to $8.4 million
in 2007.  On a unit of production basis, production and lease
operating expenses were $3.29 per mcfe in 2008 compared to $2.62 per mcfe in
2007. The increase in 2008 was attributable to increased energy costs, pumping
costs, repair, and maintenance associated with meters, compressors, pumps,
production personnel, and compressor sale-leaseback expenses.  We also
incurred one-time charges amounting to $1.2 million or $0.41 per mcfe related to
compression repair and workover charges related to our well enhancement
program.





On a
component basis, post-production expenses were $2.8 million, or $0.93 per mcfe
in 2008 compared to $1.9 million, or 0.59 per mcfe, in 2007.  Increase
in post-production expenses were primarily related to additional sulfide
treatment and pipeline transportation charges, including one-time retroactive
charges associated with transportation adjustments to royalty
owners.  Lease operating expenses were $7.2 million, or $2.36 per
mcfe, in 2008 compared to $6.5 million, or $2.03 per mcfe in
2007.  Increases in lease operating expenses were primarily related to
one-time charges for compression repair and workover charges related to our well
enhancement program.


39


Production
and lease operating expenses for operated properties were $3.46 per mcfe in 2008
while non-operated production and lease operating expenses were $2.97 per mcfe
in 2008.  Our operated Arrowhead, Black Bear East, Hudson West, and
South Knox projects are negatively impacting our operating cost controls and
efficiency due to dewatering, and flooding and fire damages in our South Knox
project.  During 2008, we have experienced improving results from the
Blue Chip, Chandler North, and Gaylord Fishing Club projects, primarily as a
result of reducing our operating expenses by shutting in various uneconomical
wells. Production and lease operating expenses for operated properties excluding
Arrowhead, Black Bear East, Hudson West, and South Knox projects were $2.89 per
mcfe in 2008.





Pipeline and Processing Operating
Expenses. Pipeline and processing operating expenses were $0.6 million in
2008 compared to $0.5 million in 2007.  This increase was the result
of incurring additional post-production costs which we were previously absorbing
as operating expenses.





Field Service
Expenses.Field services expenses were $2.4 million in 2008
compared to $0.3 million in 2007 which are attributable to shifting services
performed by Bach to unrelated third party customers.





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 2008 increased by
$1.0 million, or 13%, from 2007. This increase was primarily the result of
additional legal and consulting services and charge offs in connection with (1)
refinancing efforts amounting to $1.3 million, (2) write-off of capitalized
costs incurred investigating strategic alternatives amounting to $0.2 million,
(3) write-off of acquisition costs associated with the Acadian letter of intent
in the amount of $0.2 million as a result of our decision not to proceed with
the acquisition, (4) write-off of impaired mineral properties, other
investments, patent and fixed assets amounting to $0.5 million, and (5) general
legal costs incurred for corporate matters in the amount of $0.2
million.  This increase was offset by a decrease in payroll and
related costs by $0.8 million to $5.4 million in 2008 due to lower employee
payroll, bonus expense, and stock-based compensation along with a reduction in
professional fees primarily related to reduced accounting, audit, engineering,
and Sarbanes Oxley fees in the amount of $0.6 million.





We follow
the full cost method of accounting under which all costs associated with
property acquisition, exploration, and development activities are
capitalized.  We capitalize certain internal costs that can be
directly identified with our acquisition, exploration, and development
activities and do not include any costs related to production, general corporate
overhead, or similar activities.  We capitalized $0.6 million of
payroll and benefit costs for 2008 compared to $1.3 million in
2007.  This decrease was primarily related to the reduction in the
number of employees associated with acquisition, exploration and development
activities along with limited drilling which has reduced our ability to
capitalize associated costs.





Oil and Natural Gas Depletion,
Depreciation and Amortization (“DD&A”).  DD&A of oil
and natural gas properties was $5.4 million and $3.8 million during 2008 and
2007, 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 $7.5 million being added to proved properties in the full cost
pool and signification reduction of underlying reserves.  As a result
of the significant reduction in reserves of approximately 62.8 bcfe, a fourth
quarter adjustment of approximately $1.7 million was recorded for
2008.  The average DD&A cost per mcfe was $1.86 and $1.18 in 2008
and 2007, respectively.





Other Assets Depreciation and
Amortization (“D&A”).  D&A of other assets was $1.2
million in 2008, compared to $2.4 million in 2007.  This decrease was
primarily the result of the complete amortization of certain intangible assets
during January 2008 associated with the Cadence merger.





Interest
Expense.  Interest expense was $9.2 million in 2008 and $4.6
million in 2007.  This increase is due to the higher utilization of
debt.  In addition, as part of the forbearance and amendment
agreements executed during June 2008, more fully described in the liquidity
section following and our defaults on the senior secured credit facility and
second lien term loan, interest rates for the senior secured credit facility and
second lien term loan increased resulting in an additional $4.5 million of
interest charges for 2008.


40


Goodwill
Impairment.  We recorded a $19.4 million goodwill impairment
loss related to the reverse acquisition of Cadence entered into in 2005 of $16.0
million and acquisition of Bach executed in 2006 of $3.4 million.  For
the acquisition of Cadence, we measured goodwill impairment using quoted market
prices adjusted for known synergies and other benefits arising from
subsidiaries.  For the Bach acquisition, we measured goodwill using
the anticipated sales price of Bach derived from internal
valuations.





Ceiling Write-down of Oil and Gas
Properties.  During 2008, we recognized a ceiling write-down of
oil and gas properties in the amount of $78.5 million as a result of the
carrying amount of oil and gas properties subject to amortization exceeding the
full cost ceiling limitations.





Taxes, Other.Other
taxes include state franchise taxes, state income taxes, and state business
taxes.  We have significant net operating loss carry forwards, thus no
federal income tax expense has been recognized.  Tax expense was $0.1
million in 2008, compared to $19,021 in 2007.  This increase is
primarily related to our estimated state of Oklahoma tax liability associated
with the sale of our Oak Tree Project.




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 $28.2 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 $5.8 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 $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, 2006Play/Trend
                            
                            (mcfe)
                            
                            
                            Amount
                            
                            
                            (mcfe)
                            
                            
                            AmountAntrim
                            
                            
                            2,975,715
                            
                            
                            $
                            24,346,250
                            
                            
                            
                            2,353,691
                            
                            
                            $
                            18,948,300New
      Albany
                            
                            
                            57,186
                            
                            
                            
                            404,967
                            
                            
                            
                            28,517
                            
                            
                            
                            190,079Other
                            
                            
                            174,254
                            
                            
                            
                            1,972,601
                            
                            
                            
                            271,219
                            
                            
                            
                            2,453,432Total
                            
                            
                            3,207,155
                            
                            
                            $
                            26,723,818
                            
                            
                            
                            2,653,427
                            
                            
                            $
                            21,591,811





Other Revenues. Other revenues
increased by $0.7 million, or 88%, to $1.5 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.


41


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 $8.4 million in 2007 compared to $6.0 million
in 2006. On a unit of production basis, production and lease operating expenses
were $2.62 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 $6.5 million, or $2.03 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 $0.5 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.





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 2007 increased by
$0.5 million, or 6%, from 2006. This increase is the result of increases in our
employee and related costs.





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.


42


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.





LIQUIDITY
AND CAPITAL RESOURCES





Our
financial statements for the year ended December 31, 2008, have been prepared on
a going concern basis which contemplates the realization of assets and the
settlement of liabilities in the normal course of business.  With the
loss of production and significant deficiencies in working capital along with an
increase in interest rates and the termination of our natural gas and interest
rate derivatives more fully described in the following paragraphs, our
operations and existing cash balances are not sufficient to support interest
requirements on existing debt balances for longer than one year.  We
are currently in default under the senior secured credit facility and second
lien term loan more fully described in the following paragraphs.  We
recognize our continued existence is dependent on (1) lenders’ willingness to
refrain from accelerating or demanding repayment on current debt obligations,
(2) restructuring of our current debt, (3) securing alternative financing
arrangements, and/or (4) asset divestitures.  We continue discussions
with existing lenders and are seeking alternative financing arrangements and
opportunities for asset divestitures.  Due to the recent events within
the banking industry we are having difficulty securing alternative financing
arrangements.  There is no assurance the lenders will not call the
debt obligation or that we will be able to restructure or refinance our current
debt or sell assets in an amount sufficient to remedy our loan
defaults.




On
October 1, 2008, we received a notice of early termination from BNP with respect
to our natural gas and interest rate swap derivatives (the “Early Termination
Notice”) in accordance with the 1992 International Swap Dealers Association,
Inc. (“ISDA”) master agreement dated August 20, 2007, between us and
BNP.  The Early Termination Notice references Sections 6(a) and 6(b)
of the ISDA master agreement which gives BNP the right to terminate following an
event of default.  The settlement amount in connection with the Early
Termination Notice amounted to approximately $1.6 million for the interest rate
swap derivative and $0.6 million for the natural gas derivatives.  The
total settlement amount due in the approximate amount of $2.2 million was
payable on or before October 2, 2008.  As of the filing of this Form
10-K we have not paid the $2.2 million liability and instead have included the
amount in our debt balance.  For the year ended December 31, 2008, the
effect of the termination of our natural gas derivatives resulted in a loss of
oil and gas revenue in the approximate amount of $1.2 million.  If
natural gas continues selling at current prices, our oil and gas revenue will be
impacted negatively due to the inability to benefit from gains resulting from
hedged production.  Based on a sales price of $4.50 per mcf, we
estimate lost revenues from our terminated natural gas contracts to be $10.8
million, $10.7 million, and $8.0 million for the years ended December 31, 2009,
2010, and 2011, respectively.  As a result of the natural gas
derivative contracts termination, we are presently exposed to the fluctuation of
natural gas prices.





Senior
Secured Credit Facility





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 current authorized borrowing base of $50
million to $70 million. The amount of the borrowing base was
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. As noted
above, on June 6, 2008, we were notified that our borrowing base was determined
to be only $50 million.  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 our stock or member interest of
all material subsidiaries.


43





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 3.0% (increased range by 1.0% from 2.0% to 3.0% as a result of the
First Forbearance and Amendment dated June 12, 2008) 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, 2008, interest on the borrowings including the Early Termination
Notice liability had a weighted average interest rate of 6.5%.  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.




On
February 12, 2009, we entered into a forbearance agreement to the senior secured
credit facility (the “Second Forbearance Agreement”) with BNP Paribas (“BNP” or
the “Administrative Agent”) and the syndication.  In accordance with
the Second Forbearance Agreement, during the period from December 31, 2008 until
April 30, 2009 (the “Second Forbearance Period”), BNP will forbear and refrain
from (i) accelerating any loans outstanding and (ii) taking any other
enforcement action under the senior secured credit facility at law or otherwise
as a result of designated defaults or potential defaults, provided we comply
with the forbearance covenants (collectively, the “Second Forbearance
Covenants”).





A summary
of the Second Forbearance Covenants is as follows: (i) we shall retain and
employ a financial advisor, (ii) we shall deliver to the Administrative Agent an
initial detailed budget on or before February 20, 2009, and provide subsequent
monthly updates, (iii) we shall deliver to the Administrative Agent prior week
aggregated cash balances on or before the last business day of the current week,
(iv) no later than February 23, 2009, we will execute (or cause to be executed)
additional mortgages and no later than February 18, 2009, we will
execute  (or cause to be executed) other security instruments such
that, after giving effect to such additional mortgages and other security
instruments, the syndication will have liens on 100% of our oil and gas
properties, promissory notes, all significant overriding royalties, and all
significant farmout agreements prior to such date, (v) we must obtain prior
written approval of the Administrative Agent to farmout any assets or sell any
assets for more than $200,000; (vi) we shall provide the Administrative Agent
notice of any unwritten or written expressions of interest with respect to the
purchase of assets of the Company or any of its subsidiaries for an amount in
excess of $2.0 million, (vii) we and the financial advisor shall participate in
weekly conference calls with the Administrative Agent and the syndication during
which a financial officer of the Company must provide updates on restructuring,
sale prospects, and cost reduction efforts, (viii) we must deliver to the
Administrative Agent copies of any detailed audit reports, management letters,
or recommendations submitted to the board of directors, (ix) no later than
February 28, 2009, we must deliver a restructuring plan to resolve the borrowing
base deficiency, (x) we must maintain a liquidity position of at least $4.0
million during Second Forbearance Period, and (xi) no later than February 23,
2009, we must obtain the consent of the second lien term loan syndication for us
to defer until no earlier than the termination of the Second Forbearance Period,
payment of the scheduled interest payment currently payable to the second lien
term loan syndication on February 24, 2009.





Our failure to comply with the Second
Forbearance Covenants will terminate the Second Forbearance Agreement and allow
the syndication to exercise any or all of their rights and remedies purportedly
provided to them under the senior secured credit facility.




We recognize that the senior secured
credit facility may become due and payable after expiration of the Second
Forbearance Period on April 30, 2009.  For this reason, the entire
outstanding debt has been classified as a current liability on the December 31,
2008 balance sheet.


44


Second
Term Lien Loan




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.  During August 2008 we were notified that Laminar Direct
Capital, LLC (“Laminar”) succeeded BNP as the arranger and administrative agent
for the second term lien loan.  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 second lien
term loan were used to payoff our 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 950 basis points (increased from 700 basis points as
a result of the forbearance agreement and amendment no. 1 to the second lien
term loan dated June 12, 2008, and by another 2% pursuant to the Term Loan
notice of Default dated October 1, 2008).




We
continue to engage in discussions with Laminar and the syndication to
restructure our second lien term loan debt. We recognize that the second term
lien loan is due and payable upon notification from Laminar after the expiration
of the 180 days beginning November 24, 2008, and therefore the entire
outstanding debt has been classified as a current liability on the December 31,
2008 balance sheet.  In addition to discussions with Laminar and the
syndication, we are also seeking alternative financing arrangements and
opportunities for asset divestitures.  There is no assurance that we
will be successful in restructuring our debt, finding alternative financing
arrangements, or selling company assets in an amount sufficient to remedy our
loan defaults.





Cash
Flows from Operating Activities





Cash
provided by operating activities decreased 59% to $4.1 million in 2008, compared
to $10.1 million in 2007.  See “Results of Operations” for discussion
of changes in revenues and expenses. Non-cash charges such as depreciation,
depletion and amortization and stock based compensation decreased by $0.5
million as a result of complete amortization of certain intangibles in January
2008, write-off of debt issuance costs and reduced compensation expense for
previously issued stock awards.  Non-cash charges of goodwill
impairment and ceiling write-down of oil and gas properties increased by $19.4
million and $78.5 million, respectively, due to the write-off of goodwill
associated with the Cadence and Bach acquisitions and the carrying amount of oil
and gas properties exceeding the full cost limitation.  Changes in
current operating assets and liabilities decreased cash flow from operations by
$1.1 million which is primarily related to a significant amount of collections
from joint venture partners during 2007 as opposed to 2008 due to our
significant reduction in drilling efforts for 2008.





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.


45


Cash
Flows used in Investing Activities





Cash
flows used in investing activities were $10.7 million in 2008, $61.1 million in
2007, and $89.6 million in 2006.  The following table describes our
significant investing transactions that we completed in the periods set forth
below:




Year
      Ended December 312008
                    
                    
                    2007
                    
                    
                    2006Acquisitions
      of leaseholdMichigan
      Antrim shale
                    
                    $
                    610,307
                    
                    
                    $
                    1,443,243
                    
                    
                    $
                    5,325,872Indiana
      Antrim shale
                    
                    
                    3,230
                    
                    
                    
                    491,127
                    
                    
                    
                    4,631New
      Albany shale(a)
                    
                    
                    1,019,064
                    
                    
                    
                    3,476,568
                    
                    
                    
                    15,567,504Woodford
      shale
                    
                    
                    456,236
                    
                    
                    
                    5,413,132
                    
                    
                    
                    2,063,181Other
                    
                    
                    91,798
                    
                    
                    
                    172,459
                    
                    
                    
                    1,233,485Drilling
      and development of oil and natural gas propertiesMichigan
      Antrim shale
                    
                    
                    1,536,002
                    
                    
                    
                    22,123,120
                    
                    
                    
                    20,449,950Indiana
      Antrim shale
                    
                    
                    12,182
                    
                    
                    
                    1,398,811
                    
                    
                    
                    500New
      Albany shale
                    
                    
                    990,960
                    
                    
                    
                    10,318,178
                    
                    
                    
                    2,808,030Other
                    
                    
                    907,301
                    
                    
                    
                    1,502,129
                    
                    
                    
                    5,918,128Infrastructure
      propertiesMichigan
      Antrim shale
                    
                    
                    112,496
                    
                    
                    
                    10,128,646
                    
                    
                    
                    10,988,527New
      Albany shale
                    
                    
                    1,832,554
                    
                    
                    
                    1,791,091
                    
                    
                    
                    1,789,816Other
                    
                    
                    -
                    
                    
                    
                    10,438
                    
                    
                    
                    350,268Capitalized
      interest and general and administrative cost on exploration, development
      and leasehold
                    
                    
                    5,078,969
                    
                    
                    
                    5,646,672
                    
                    
                    
                    5,252,900Acquisitions
      of oil and natural gas properties
                    
                    
                    -
                    
                    
                    
                    2,405,609
                    
                    
                    
                    24,011,335Acquisitions/additions
      for pipeline, property and equipment
                    
                    
                    372,847
                    
                    
                    
                    1,586,328
                    
                    
                    
                    4,647,497Other,
      net
                    
                    
                    12,206
                    
                    
                    
                    186,334
                    
                    
                    
                    855,070Redesignation
      of cash equivalents to short-terminvestments
                    
                    
                    1,114,627
                    
                    
                    
                    -
                    
                    
                    
                    -Subtotal
      of capital expenditures
                    
                    $
                    14,150,779
                    
                    
                    $
                    68,093,885
                    
                    
                    $
                    101,266,694Sale
      of oil and natural gas properties(a)
                    
                    
                    (3,263,762
                    )
                    
                    
                    (2,079,518
                    )
                    
                    
                    (11,489,456
                    )Option
      fees related to farmouts
                    
                    
                    (173,256
                    )
                    
                    
                    -
                    
                    
                    
                    -Sale
      and leaseback of gas compression equipment
                    
                    
                    -
                    
                    
                    
                    (3,844,500
                    )
                    
                    
                    -Sale
      of other investments
                    
                    
                    (12,334
                    )
                    
                    
                    (1,069,378
                    )
                    
                    
                    (171,140
                    )Subtotal
      of capital divestitures
                    
                    
                    (3,449,352
                    )
                    
                    
                    (6,993,396
                    )
                    
                    
                    (11,660,596
                    )Total
                    
                    $
                    10,701,427
                    
                    
                    $
                    61,100,489
                    
                    
                    $
                    89,606,098




(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.


46


Cash
Flows Provided by Financing Activities





Cash
flows provided by financing activities were $14.2 million in 2008 compared to
$51.7 million in 2007.  Cash flows provided in 2008 included: (1)
$13.8 million of senior secured borrowing; (2) $0.4 million of capital
contributions from minority interest members; and (3) $0.7 million of proceeds
received from exercise of common stock options and warrants.  Cash
flows used in 2008 included: (1) paydown of $0.3 million in mortgage and notes
payable obligations; (2) payment of $0.1 million in financing fees; (3)
distributions of $0.1 million to minority interest members; and (4) payment of
other in the amount of $0.2 million.





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.





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 asset retirement obligations, goodwill impairment, and fair value of
stock options.





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.


47


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.





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, 2008, we had approximately $120.0
million of net operating loss carryforwards which expire between 2010 and
2028.





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. We adopted the
provisions of FIN 48 on January 1, 2007.  No liabilities or assets
have been recognized as a result of the implementation of FIN
48.


48


RECENT
ACCOUNTING PRONOUNCEMENTS





On December 31, 2008, the SEC adopted a
final rule that amends its oil and gas reporting requirements.  The
revised rules change the way oil and gas companies report their reserves in the
financial statements.  The rules are intended to reflect changes in
the oil and gas industry since the original disclosures were adopted in
1978.  Definitions were updated to be consistent with Petroleum
Resource Management System (“PRMS”).  Other key revisions include a
change in pricing used to prepare reserve estimates, the inclusion of
non-traditional resources in reserves, the allowance for use of new technologies
in determining reserves, optional disclosure of probable and possible reserves
and significant new disclosures.  The revised rules will be effective
for our annual report on Form 10-K for the fiscal year ending December 31,
2009.  The SEC is precluding application of the new rules in quarterly
reports prior to the first annual report in which the revised disclosures are
required and early adoption is not permitted.  We are currently
evaluating the effect the new rules will have on our financial reporting and
anticipate that the following rule changes could have a significant impact on
our results of operations as follows:





·
            The
      price used in calculating reserves will change from a single-day closing
      price measured on the last day of the company’s fiscal year to a 12-month
      average price, and will affect our depletion and ceiling test
      calculations.





·
            Several
      reserve definitions have changed that could revise the types of reserves
      that will be included in our year-end reserve
  report.





·
            Some
      of our financial reporting disclosures could change as a result of the new
      rules.





In December 2008, the FASB issued FASB
Staff Position (“FSP”) FAS 140-4 and FIN 46(R)-8, “Disclosure by Public Entities
(Enterprises) About Transfers of Financial Assets and Interests in Variable
Interest Entities”.  The purpose of the FSP is to promptly improve
disclosures by public companies until the pending amendments to FASB Statement
No. 140, “Accounting for Transfers and Servicing of Financial Assets and
Extinguishment of Liabilities” (“SFAS 140”), and FIN 46R are finalized and
approved by the FASB.  The FSP amends SFAS 140 to require public
companies to provide additional disclosures about transferor’s continuing
involvement with transferred financial assets.  It also amends FIN 46R
by requiring public companies to provide additional disclosures regarding their
involvement with variable interest entities.  This FSP is effective
December 31, 2008 and has not had a material impact on the consolidated
financial statements.





In May 2008, the FASB issued SFAS No.
162 “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS
162”).  SFAS 162 identifies the sources of accounting principles and
the framework for selecting the principles used in the preparation of financial
statements of nongovernmental entities that are presented in conformity with
GAAP.  This statement shall be effective 60 days following the
Securities Exchange and Commission’s approval of the Public Company Accounting
Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in
Conformity With Generally Accepted Accounting Principles.”  Management
does not expect its adoption will have a material impact on the consolidated
financial statements.





In April
2008, the FASB issued FASB Staff Positions (“FSP”) No. FAS 142-3, “Determination
of the Useful Life of Intangible Assets.” FSP No. FAS 142-3 amends the factors
that should be considered in developing renewal or extension assumptions used to
determine the useful life of a recognized intangible asset under SFAS No. 142,
“Goodwill and Other Intangible Assets.”  The intent of the position is
to improve the consistency between the useful life of a recognized intangible
asset under SFAS No. 142 and the period of expected cash flows used to measure
the fair value of the asset under SFAS No. 141R, and other U.S. generally
accepted accounting principles.  The provisions of FSP No. FAS 142-3
are effective for fiscal years beginning after December 15,
2008.  Management does not expect the adoption of FSP No. FAS 142-3 to
have a material impact on the consolidated financial statements.





In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments
and Hedging Activities”, an amendment of FASB
Statement No. 133 (“SFAS 161”).  SFAS 161 requires enhanced
disclosures about an entity’s derivative instruments and hedging activities,
including:  (1) how and why an entity uses derivative instruments; (2)
how derivative instruments and related hedged items are accounted for under SFAS
133 and its related interpretations; and (3) how derivative instruments and
related hedged items affect an entity’s financial position, financial
performance, and cash flows.  SFAS 161 is effective for financial
statements issued for fiscal years and interim periods beginning after November
15, 2008, with earlier application encouraged.  With the termination
of the Company’s derivative instruments more fully disclosed in Note 6 “Risk
Management Activities”, management does not expect the adoption to have any
impact on the consolidated financial statements.


49


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 does not expect the adoption of SFAS 141R and
SFAS 160 to have a material impact on the consolidated financial
statements.  However, SFAS 160 will change our reporting of the
minority interests in subsidiaries.





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.  We did not elect to apply the fair value option to any of our
financial instruments.





In September 2006, the FASB issued SFAS
No. 157, “Fair Value Measurements” (“SFAS 157”), which is effective for fiscal
years beginning after November 15, 2007, and for interim periods within those
years.  This statement defines fair value, establishes a framework for
measuring fair value and expands the related disclosure
requirements.  This statement applies under other accounting
pronouncements that require or permit fair value measurements.  The
statement indicates, among other things, that a fair value measurement assumes
that the transaction to sell an asset or transfer a liability occurs in the
principal market for the asset or liability or, in the absence of a principal
market, the most advantageous market for the asset or liability.  SFAS
157 defines fair value based upon an exit price model.





Relative to SFAS 157, the FASB issued
FSP 157-1 and 157-2.  FSP 157-1 amends SFAS 157 to exclude SFAS No.
13, “Accounting for Leases” (“SFAS 13”), and its related interpretive accounting
pronouncements that address leasing transactions, while FSP 157-2 delays the
effective date of the application of SFAS 157 to fiscal years beginning after
November 14, 2008, for all nonfinancial assets and nonfinancial liabilities that
are recognized or disclosed at fair value in the financial statements on a
nonrecurring basis.  In October 2008, the FASB issued FSP No. FAS
157-3 “Determining the Fair Value of a Financial Asset When the Market for That
Asset Is Not Active” (“FSP No. FAS 157-3”), which clarifies the application of
SFAS No. 157 for financial assets in a market that is not active.  FSP
No. FAS 157-3 was effective upon issuance.





We
adopted SFAS 157 as of January 1, 2008, with the exception of the application of
the statement to nonrecurring nonfinancial assets and nonfinancial
liabilities.  Nonrecurring nonfinancial assets and nonfinancial
liabilities for which we have not applied the provisions of SFAS 157 include
those measured at fair value in goodwill impairment testing, indefinite lived
intangible assets measured at fair value for impairment testing, and asset
retirement obligations initially measured at fair value.  SFAS 157 has
not and is not expected to materially affect how we determine fair value, but
has resulted and will result in certain additional disclosures.


50


OFF
BALANCE SHEET ARRANGEMENTS




We have no special purpose entities,
financing partnerships, guarantees, or off-balance sheet arrangements other than
the $0.8 million of outstanding letters of credit discussed in Note 12
“Commitments and Contingencies” to our consolidated financial
statements.





CONTRACTUAL
OBLIGATIONS




The following summarizes our
contractual obligations as of December 31, 2008, and the effect such obligations
are expected to have on our liquidity and cash flow in future periods (in
thousands):





Total
                  
                  
                  2009
                  
                  
                  2010
                  
                  
                  2011
                  
                  
                  2012
                  
                  
                  2013
                  
                  
                  2014 and
                    thereafterSenior
      secured credit facility and second lien term loan
                  
                  $
                  123,001
                  
                  
                  $
                  123,001
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  -Interest
      on long-term debt (a)
                  
                  
                  10,356
                  
                  
                  
                  10,356
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Notes
      and mortgage payable
                  
                  
                  3,228
                  
                  
                  
                  179
                  
                  
                  
                  518
                  
                  
                  
                  2,496
                  
                  
                  
                  28
                  
                  
                  
                  7
                  
                  
                  
                  -Capital
      leases
                  
                  
                  1
                  
                  
                  
                  1
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  -Land
      and mineral leases(b)
                  
                  
                  7,398
                  
                  
                  
                  1,698
                  
                  
                  
                  2,863
                  
                  
                  
                  1,916
                  
                  
                  
                  664
                  
                  
                  
                  146
                  
                  
                  
                  111Operating
      leases
                  
                  
                  2,357
                  
                  
                  
                  550
                  
                  
                  
                  550
                  
                  
                  
                  550
                  
                  
                  
                  550
                  
                  
                  
                  105
                  
                  
                  
                  52Total
      contractual cash obligations
                  
                  $
                  146,341
                  
                  
                  $
                  135,785
                  
                  
                  $
                  3,931
                  
                  
                  $
                  4,962
                  
                  
                  $
                  1,242
                  
                  
                  $
                  258
                  
                  
                  $
                  163





(a)
            Amounts
      estimated based on current interest rates.  If our senior
      secured credit facility and second lien term loan are held until maturity,
      interest is estimated at $7.1 million, $6.9 million, and $3.5 million for
      2009, 2010, and 2011, respectively.


(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




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 previously entered into various derivative
instruments with BNP.  The purpose of the derivative instrument was 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 reduced our exposure on the hedged production volumes to decreases in
commodity prices and limited the benefit we might otherwise have received from
any increases in commodity prices on the hedged production
volumes.  Since BNP has terminated all of our natural gas derivatives,
we are presently exposed to the fluctuations of natural gas
prices.  Based on current production levels, a $0.50 increase or
decrease in natural gas prices would have the effect of causing $0.1 million
addition or reduction to our monthly oil and gas revenue.




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.  On October 1, 2008, we received a letter of termination
for our interest rate derivative instrument from BNP.  Since BNP has
terminated our interest rate derivative, we are presently exposed to the
fluctuation of interest rates.  Based on current borrowing levels, a
1.0% increase or decrease in current market rates would have the effect of
causing $0.1 million additional charge or reduction to our monthly interest
expense.


51


The
following table sets forth our principal financing obligation and the related
interest rates as of December 31, 2008:




Expected
      Maturity
                  
                  Average Interest Rate asof
                    December 31, 2008
                  
                  
                  Principal
                    OutstandingObligations
      under capital lease
                  01/10/09
                  
                  
                  8.25%
                  
                  
                  $
                  900Notes
      payable
                  09/15/10-10/03/13
                  
                  
                  5.00%
      - 6.95%
                  
                  
                  
                  188,133Mortgage
      payable
                  06/15/10
                  
                  Fixed
      at 6.00%
                  
                  
                  
                  356,435Mortgage
      payable
                  02/01/11
                  
                  Fixed
      at 5.95%
                  
                  
                  
                  2,613,735Mortgage
      payable
                  10/01/11
                  
                  Fixed
      at 5.95%
                  
                  
                  
                  69,419Second
      lien term loan
                  02/01/11
                  
                  Default
      at 15.50%(a)
                  
                  
                  
                  50,980,022Senior
      secured credit facility
                  01/31/10
                  
                  Default
      at 6.25%(a)
                  
                  
                  
                  72,021,446Total
      debt
                  
                  
                  
                  
                  
                  
                  $
                  126,230,090




(a)  Current
default rate as of March 4, 2009.


52


ITEM
8.     FINANCIAL STATEMENTS




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES





INDEX TO CONSOLIDATED
FINANCIAL STATEMENTS





PageManagement’s
      Report on Internal Control Over Financial Reporting
              54Reports
      of Independent Registered Public Accounting Firms
              55-58Consolidated
      Financial StatementsConsolidated
      Balance Sheets as of December 31, 2008 and 2007
              59-60Consolidated
      Statements of Operations for the Years Ended December 31, 2008, 2007 and
      2006
              61Consolidated
      Statements of Shareholders’ Equity for the Years Ended December 31, 2008,
      2007 and 2006
              62Consolidated
      Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and
      2006
              63-64Notes
      to Consolidated Financial Statements
              65Supplemental
      Oil and Natural Gas Information (Unaudited)
              101


53


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 not effective as of December 31,
2008.





A
material weakness is a deficiency, or a combination of deficiencies, in internal
control over financial reporting, such that there is a reasonable possibility
that a material misstatement of the Company’s annual or interim financial
statements will not be prevented or detected on a timely basis.  In
the course of auditing our year-end financial statements, our auditors
identified a material weakness that resulted from an error made by us during our
initial pricing of our reserve report.  The Company initially priced
its reserve report using the effective price at December 31, 2008, including an
adjustment of the price based on a contract that expired on December 31,
2008.  Since the contract expired on December 31, 2008, the contract
price was incorrectly used to initially price future reserves.  The
effect of this error resulted in understating impairment of the full cost pool
by approximately $20.0 million as a result of the ceiling test at December 31,
2008.  An audit adjustment was made to correct the error and is
reflected in the December 31, 2008 financial statements.  This error
had no impact on the December 31, 2007 or 2006 financial
statements.





Our
management’s assessment of the effectiveness of the Company’s internal control
over financial reporting as of December 31, 2008, 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


54


REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM




Board of
Directors and Shareholders


Aurora
Oil & Gas Corporation and Subsidiaries


Traverse
City, Michigan





We have
audited the accompanying consolidated balance sheets of Aurora Oil & Gas
Corporation and Subsidiaries (the Company) as of December 31, 2008 and 2007, and
the related consolidated statements of operations, shareholders’ equity and cash
flows for the years then ended.  Aurora Oil & Gas Corporation’s
management is responsible for these financial statements.  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. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes 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 consolidated financial position of Aurora Oil
& Gas Corporation at December 31, 2008 and 2007, and the consolidated
results of their operations and their cash flows for the years then ended, in
conformity with accounting principles generally accepted in the United States of
America.





The
accompanying consolidated financial statements have been prepared assuming that
the Company will continue as a going concern. As discussed in Note 3 to the
consolidated financial statements, the Company has experienced decreased
production and significant deficiencies in working capital, which results in
existing cash balances being insufficient to support existing debt service
requirements.  These conditions raise substantial doubt about the
Company’s ability to continue as a going concern. Management’s plans regarding
those matters are also described in Note 3. The consolidated financial
statements do not include any adjustments that might result from the outcome of
this uncertainty.





We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), Aurora Oil & Gas Corporation’s internal
control over financial reporting as of December 31, 2008, based on criteria
established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO), and our report dated March 13,
2009 expressed an adverse opinion.





WEAVER
AND TIDWELL, L.L.P.





Fort
Worth, Texas


March 13,
2009


55


REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


ON
INTERNAL CONTROL OVER FINANCIAL REPORTING




Board of
Directors and Shareholders


Aurora
Oil & Gas Corporation and Subsidiaries


Traverse
City, Michigan





We have
audited Aurora Oil & Gas Corporation’s (the Company) internal control over
financial reporting as of December 31, 2008, based on criteria established in
Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Aurora Oil & Gas Corporation’s management is
responsible 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 the
Company’s internal control over financial reporting based on our
audit.





We
conducted our audit 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 effective
internal control over financial reporting was maintained in all material
respects. 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 audit also included performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.





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.





A
material weakness is a control deficiency, or combination of deficiencies, in
internal control over financial reporting, such that there is a reasonable
possibility that a material misstatement of the Company’s annual or interim
financial statements will not be prevented or detected on a timely basis. The
following material weakness has been identified and included in management’s
assessment.  The Company’s controls in place did not identify errors
in the pricing used to prepare its reserve report.  The Company
initially priced the natural gas in its reserve report utilizing the effective
price at December 31, 2008 including adjustments for a contract that expired on
December 31, 2008.  Prices used in the reserve report should only be
adjusted for fixed and determinable escalations for the term of a
contract.  The effect of the material weakness resulted in an
additional impairment of the full cost pool of approximately $20 million as a
result of the ceiling test. This material weakness was considered in determining
the nature, timing, and extent of audit tests applied in our audit of the 2008
financial statements, and this report does not affect our report dated March 13,
2009 on those financial statements.


56


In our
opinion, because of the effect of the material weakness described above on the
achievement of the objectives of the control criteria, Aurora Oil & Gas
Corporation has not maintained effective internal control over financial
reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO).





We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets and the related
consolidated statements of operations, shareholders’ equity, and cash flows of
Aurora Oil & Gas Corporation, and our report dated March 13, 2009 expressed
an unqualified opinion.





WEAVER
AND TIDWELL, L.L.P.





Fort
Worth, Texas


March 13,
2009


57


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 statements of operations, shareholders’
equity, and cash flows of Aurora Oil & Gas Corporation and Subsidiaries for
the year ended December 31, 2006. 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
audit.





We
conducted our audit 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 audit provides a reasonable basis
for our opinion.





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





RACHLIN
LLP


(formerly
known as Rachlin Cohen & Holtz LLP)





Miami,
Florida


March 13,
2007


58





AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIESCONSOLIDATED
      BALANCE SHEETS





December 31,
                        
                        
                        December 31,2008
                        
                        
                        2007ASSETSCURRENT
      ASSETS:Cash
      and cash equivalents
                        
                        $
                        10,005,138
                        
                        
                        $
                        2,425,678Short-term
      investments
                        
                        
                        1,114,627
                        
                        
                        
                        -Accounts
      receivable:Oil
      and natural gas sales
                        
                        
                        2,100,363
                        
                        
                        
                        5,036,416Joint
      interest owners
                        
                        
                        676,299
                        
                        
                        
                        827,353Field
      service and sales
                        
                        
                        520,126
                        
                        
                        
                        24,285Prepaid
      expenses and other current assets
                        
                        
                        999,835
                        
                        
                        
                        765,730Short-term
      derivative instruments
                        
                        
                        -
                        
                        
                        
                        2,247,990Total
      current assets
                        
                        
                        15,416,388
                        
                        
                        
                        11,327,452PROPERTY
      AND EQUIPMENT:Oil
      and natural gas properties, using full cost accounting:Proved
      properties
                        
                        
                        88,380,779
                        
                        
                        
                        162,724,004Unproved
      properties
                        
                        
                        47,855,625
                        
                        
                        
                        56,937,683Less:
      accumulated depletion and amortization
                        
                        
                        (19,810,023
                        )
                        
                        
                        (14,401,584
                        )Total
      oil and natural gas properties, net
                        
                        
                        116,426,381
                        
                        
                        
                        205,260,103Other
      property and equipment:Pipelines,
      processing facilities, and compression
                        
                        
                        11,056,319
                        
                        
                        
                        11,027,577Other
      property and equipment
                        
                        
                        5,876,830
                        
                        
                        
                        5,450,452Less:
      accumulated depreciation
                        
                        
                        (2,481,626
                        )
                        
                        
                        (1,554,189
                        )Total
      other property and equipment, net
                        
                        
                        14,451,523
                        
                        
                        
                        14,923,840Total
      property and equipment, net
                        
                        
                        130,877,904
                        
                        
                        
                        220,183,943OTHER
      ASSETS:Note
      receivable
                        
                        
                        12,000,000
                        
                        
                        
                        -Goodwill
                        
                        
                        -
                        
                        
                        
                        19,373,264Intangibles
      (net of accumulated amortization of $4,642,499 and $4,497,920,
      respectively)
                        
                        
                        62,501
                        
                        
                        
                        457,080Other
      investments
                        
                        
                        -
                        
                        
                        
                        733,836Debt
      issuance costs (net of accumulated amortization of $846,397 and $360,972,
      respectively)
                        
                        
                        1,211,340
                        
                        
                        
                        1,661,603Other
                        
                        
                        632,948
                        
                        
                        
                        934,490Total
      other assets
                        
                        
                        13,906,789
                        
                        
                        
                        23,160,273TOTAL
      ASSETS
                        
                        $
                        160,201,081
                        
                        
                        $
                        254,671,668





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


59





AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIESCONSOLIDATED
      BALANCE SHEETS





December 31,
                    
                    
                    December 31,2008
                    
                    
                    2007LIABILITIES
      AND SHAREHOLDERS' EQUITYCURRENT
      LIABILITIES:Accounts
      payable and accrued liabilities
                    
                    $
                    4,082,298
                    
                    
                    $
                    6,490,981Accrued
      exploration, development, and leasehold costs
                    
                    
                    50,317
                    
                    
                    
                    1,341,917Current
      portion of obligations under capital leases
                    
                    
                    900
                    
                    
                    
                    6,288Current
      portion of note payable
                    
                    
                    53,014
                    
                    
                    
                    76,416Current
      portion of mortgage payables
                    
                    
                    124,550
                    
                    
                    
                    112,326Senior
      secured credit facility
                    
                    
                    72,021,446
                    
                    
                    
                    -Second
      lien term loan
                    
                    
                    50,980,022
                    
                    
                    
                    -Drilling
      advances
                    
                    
                    -
                    
                    
                    
                    168,356Short-term
      derivative instruments
                    
                    
                    -
                    
                    
                    
                    384,706Total
      current liabilities
                    
                    
                    127,312,547
                    
                    
                    
                    8,580,990LONG-TERM
      LIABILITIES:Obligations
      under capital leases, net of current portion
                    
                    
                    -
                    
                    
                    
                    1,496Asset
      retirement obligation
                    
                    
                    1,686,393
                    
                    
                    
                    1,494,745Notes
      payable
                    
                    
                    135,119
                    
                    
                    
                    143,062Mortgage
      payables
                    
                    
                    2,915,039
                    
                    
                    
                    2,969,870Senior
      secured credit facility
                    
                    
                    -
                    
                    
                    
                    56,000,000Second
      lien term loan
                    
                    
                    -
                    
                    
                    
                    50,000,000Long-term
      derivative instruments
                    
                    
                    -
                    
                    
                    
                    2,248,326Other
      long-term liabilities
                    
                    
                    528,908
                    
                    
                    
                    977,529Total
      long-term liabilities
                    
                    
                    5,265,459
                    
                    
                    
                    113,835,028Total
      liabilities
                    
                    
                    132,578,006
                    
                    
                    
                    122,416,018Minority
      interest in net assets of subsidiaries
                    
                    
                    467,937
                    
                    
                    
                    112,661COMMITMENTS,
      CONTINGENCIES, AND SUBSEQUENT EVENTS (Note 12 and Note 17)SHAREHOLDERS'
      EQUITY:Common
      stock, $0.01 par value; authorized 250,000,000 shares; issued and
      outstanding 103,282,788 and 101,769,456 shares,
    respectively
                    
                    
                    1,032,828
                    
                    
                    
                    1,017,695Additional
      paid-in capital
                    
                    
                    142,518,095
                    
                    
                    
                    140,541,460Accumulated
      other comprehensive loss
                    
                    
                    -
                    
                    
                    
                    (385,043
                    )Accumulated
      deficit
                    
                    
                    (116,395,785
                    )
                    
                    
                    (9,031,123
                    )Total
      shareholders' equity
                    
                    
                    27,155,138
                    
                    
                    
                    132,142,989TOTAL
      LIABILITIES AND SHAREHOLDERS' EQUITY
                    
                    $
                    160,201,081
                    
                    
                    $
                    254,671,668





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


60





AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES
              CONSOLIDATED
      STATEMENTS OF OPERATIONS





Year Ended December 31,2008
                
                
                2007
                
                
                2006REVENUES:Oil
      and natural gas sales
                
                $
                25,201,777
                
                
                $
                26,723,818
                
                
                $
                21,591,811Pipeline
      transportation and marketing
                
                
                710,250
                
                
                
                578,020
                
                
                
                489,473Field
      service and sales
                
                
                3,051,419
                
                
                
                390,401
                
                
                
                125,611Interest
      and other
                
                
                877,488
                
                
                
                549,149
                
                
                
                220,592Total
      revenues
                
                
                29,840,934
                
                
                
                28,241,388
                
                
                
                22,427,487EXPENSES:Production
      taxes
                
                
                1,338,397
                
                
                
                1,123,070
                
                
                
                877,319Production
      and lease operating expense
                
                
                9,995,981
                
                
                
                8,424,096
                
                
                
                5,966,341Pipeline
      and processing operating expense
                
                
                593,059
                
                
                
                482,647
                
                
                
                265,795Field
      services expense
                
                
                2,439,939
                
                
                
                321,753
                
                
                
                90,913General
      and administrative expense
                
                
                9,075,903
                
                
                
                8,029,122
                
                
                
                7,531,718Oil
      and natural gas depletion and amortization
                
                
                5,380,106
                
                
                
                3,769,104
                
                
                
                2,681,290Other
      assets depreciation and amortization
                
                
                1,193,993
                
                
                
                2,396,026
                
                
                
                2,083,191Interest
      expense
                
                
                9,201,343
                
                
                
                4,582,021
                
                
                
                4,573,785Ceiling
      write-down of oil and gas properties
                
                
                78,457,801
                
                
                
                -
                
                
                
                -Goodwill
      impairment
                
                
                19,373,264
                
                
                
                -
                
                
                
                -Loss
      on debt extinguishment
                
                
                -
                
                
                
                3,448,520
                
                
                
                -Taxes,
      other
                
                
                77,671
                
                
                
                19,021
                
                
                
                250,884Total
      expenses
                
                
                137,127,457
                
                
                
                32,595,380
                
                
                
                24,321,236LOSS
      BEFORE MINORITY INTEREST
                
                
                (107,286,523
                )
                
                
                (4,353,992
                )
                
                
                (1,893,749
                )MINORITY
      INTEREST IN INCOME OF SUBSIDIARIES
                
                
                (78,139
                )
                
                
                (67,841
                )
                
                
                (50,898
                )NET
      LOSS
                
                $
                (107,364,662
                )
                
                $
                (4,421,833
                )
                
                $
                (1,944,647
                )NET
      LOSS PER COMMON SHARE—BASIC and DILUTED
                
                $
                (1.04
                )
                
                $
                (0.04
                )
                
                $
                (0.02
                )WEIGHTED
      AVERAGE COMMON SHARES OUTSTANDING—BASIC and DILUTED
                
                
                103,062,697
                
                
                
                101,633,162
                
                
                
                82,288,243





Supplemental
Information




Net loss
for the years ended December 31, 2008, 2007, and 2006, included stock-based
compensation expense of $1,330,907, $2,222,200, and $2,206,801, respectively,
under Statement of Financial Accounting Standards No. 123 (revised
2004).  See Note 11 “Common Stock Options” for additional
information.





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


61





AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES
              CONSOLIDATED
      STATEMENTS OF SHAREHOLDERS’ EQUITY


Year Ended December 31,2008
                                                          
                                                          
                                                          2007
                                                          
                                                          
                                                          2006Shares
                                                          
                                                          
                                                          Amount
                                                          
                                                          
                                                          Shares
                                                          
                                                          
                                                          Amount
                                                          
                                                          
                                                          Shares
                                                          
                                                          
                                                          AmountCOMMON STOCK:Balance,
      beginning
                                                          
                                                          
                                                          101,769,456
                                                          
                                                          
                                                          $
                                                          1,017,695
                                                          
                                                          
                                                          
                                                          101,412,966
                                                          
                                                          
                                                          $
                                                          1,014,130
                                                          
                                                          
                                                          
                                                          61,536,261
                                                          
                                                          
                                                          $
                                                          615,363Cashless
      exercise of stock options and warrants
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          78,158
                                                          
                                                          
                                                          
                                                          782
                                                          
                                                          
                                                          
                                                          3,280,105
                                                          
                                                          
                                                          
                                                          32,801Conversion
      of redeemable convertible preferred stock to common stock
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          34,984
                                                          
                                                          
                                                          
                                                          349Exercise
      of stock options and warrants
                                                          
                                                          
                                                          1,163,332
                                                          
                                                          
                                                          
                                                          11,633
                                                          
                                                          
                                                          
                                                          353,332
                                                          
                                                          
                                                          
                                                          3,533
                                                          
                                                          
                                                          
                                                          15,823,457
                                                          
                                                          
                                                          
                                                          158,235Issuance
      of stock in connection with public equity offering
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          19,600,000
                                                          
                                                          
                                                          
                                                          196,000Issuance
      of stock in connection with an acquisition
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          1,378,299
                                                          
                                                          
                                                          
                                                          13,783Issuance
      of stock to officers and directors in lieu of compensation
                                                          
                                                          
                                                          350,000
                                                          
                                                          
                                                          
                                                          3,500
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          90,000
                                                          
                                                          
                                                          
                                                          900Issuance
      of stock to related parties in lieu of commission relating to exercise of
      warrants
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          1,469,860
                                                          
                                                          
                                                          
                                                          14,699Rescission
      of stock option exercises by certain officers
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          (1,800,000
                                                          )
                                                          
                                                          
                                                          (18,000
                                                          )Adjustment
      to stock ledger
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          (75,000
                                                          )
                                                          
                                                          
                                                          (750
                                                          )
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          -Balance,
      ending
                                                          
                                                          
                                                          103,282,788
                                                          
                                                          
                                                          
                                                          1,032,828
                                                          
                                                          
                                                          
                                                          101,769,456
                                                          
                                                          
                                                          
                                                          1,017,695
                                                          
                                                          
                                                          
                                                          101,412,966
                                                          
                                                          
                                                          
                                                          1,014,130ADDITIONAL
      PAID-IN CAPITAL:Balance,
      beginning
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          140,541,460
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          138,105,626
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          58,670,698Cashless
      exercise of stock awards, options, and warrants
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (90,450
                                                          )
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (782
                                                          )
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (32,801
                                                          )Conversion
      of redeemable convertible preferred stock to common stock
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          59,576Stock-based
      compensation
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          1,395,969
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          2,397,995
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          2,663,814Exercise
      of stock options and warrants
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          671,116
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          194,967
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          18,143,714Proceeds
      (cost of) equity offering
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (10,096
                                                          )
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          54,309,807Issuance
      of stock in connection with an acquisition
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          4,686,217Issuance
      of stock to officers and directors in lieu of compensation
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          348,300Issuance
      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
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          142,518,095
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          140,541,460
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          138,105,626ACCUMULATED
      OTHER COMPREHENSIVE INCOME (LOSS):Balance,
      beginning
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (385,043
                                                          )
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          5,220,633
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          -Changes
      in fair value of derivative instruments
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (5,294,190
                                                          )
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (1,679,507
                                                          )
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          7,903,933Recognition
      of loss (gain) on derivative instruments
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          5,679,233
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (3,926,169
                                                          )
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (2,683,300
                                                          )Balance,
      ending
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (385,043
                                                          )
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          5,220,633ACCUMULATED
      DEFICIT:Balance,
      beginning
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (9,031,123
                                                          )
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (4,609,290
                                                          )
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (2,660,134
                                                          )Dividends
      accrued on redeemable convertible preferred stock
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          -
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (4,509
                                                          )Net
      loss
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (107,364,662
                                                          )
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (4,421,833
                                                          )
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (1,944,647
                                                          )Balance,
      ending
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (116,395,785
                                                          )
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (9,031,123
                                                          )
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          (4,609,290
                                                          )TOTAL
      SHAREHOLDERS’ EQUITY
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          $
                                                          27,155,138
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          $
                                                          132,142,989
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          
                                                          $
                                                          139,731,099
  The
accompanying notes are an integral part of these consolidated financial
statements.


62


AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES
                                  CONSOLIDATED
      STATEMENTS OF CASH FLOWSYear
      Ended December 31,2008
                                
                                
                                2007
                                
                                
                                2006CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      loss
                                
                                $
                                (107,364,662
                                )
                                
                                $
                                (4,421,833
                                )
                                
                                $
                                (1,944,647
                                )Adjustments
      to reconcile net loss to net cash provided by operating
      activities:Depreciation,
      depletion, and amortization
                                
                                
                                6,574,099
                                
                                
                                
                                6,165,130
                                
                                
                                
                                4,764,481Ceiling
      write-down of oil and gas properties
                                
                                
                                78,457,801Goodwill
      and intangible impairments
                                
                                
                                19,623,264
                                
                                
                                
                                -
                                
                                
                                
                                -Amortization
      of debt issuance costs
                                
                                
                                548,518
                                
                                
                                
                                779,943
                                
                                
                                
                                813,715Accretion
      of asset retirement obligation
                                
                                
                                111,337
                                
                                
                                
                                76,768
                                
                                
                                
                                74,097Loss
      on debt extinguishment
                                
                                
                                -
                                
                                
                                
                                3,448,520
                                
                                
                                
                                -Recognition
      of deferred gain on sale of natural gas compression
    equipment
                                
                                
                                (132,827
                                )
                                
                                
                                -
                                
                                
                                
                                -Stock-based
      compensation
                                
                                
                                1,330,907
                                
                                
                                
                                2,222,200
                                
                                
                                
                                2,206,801Equity
      loss (gain) of other investments and other
                                
                                
                                292
                                
                                
                                
                                (317,367
                                )
                                
                                
                                291,890Interest
      paid in kind on second lien term loan
                                
                                
                                980,022
                                
                                
                                
                                -Realized
      gain (loss) on sale and disposal of other investments
                                
                                
                                216,834
                                
                                
                                
                                (434,849
                                )
                                
                                
                                -Realized
      loss on termination of interest and gas derivative
                                
                                
                                2,221,446
                                
                                
                                
                                -
                                
                                
                                
                                -Loss
      on sale and disposal of property and equipment
                                
                                
                                12,374
                                
                                
                                
                                -
                                
                                
                                
                                -Minority
      interest income of subsidiaries
                                
                                
                                78,139
                                
                                
                                
                                67,841
                                
                                
                                
                                50,898Changes
      in operating assets and liabilities:Account
      receivables
                                
                                
                                2,580,044
                                
                                
                                
                                1,607,835
                                
                                
                                
                                397,694Drilling
      advance—liabilities
                                
                                
                                (168,356
                                )
                                
                                
                                148,973
                                
                                
                                
                                19,383Notes
      receivable
                                
                                
                                -
                                
                                
                                
                                221,788
                                
                                
                                
                                20,720Prepaid
      expenses and other assets
                                
                                
                                (13,785
                                )
                                
                                
                                (1,838
                                )
                                
                                
                                (1,105,539
                                )Accounts
      payable and accrued liabilities
                                
                                
                                (956,629
                                )
                                
                                
                                515,938
                                
                                
                                
                                (121,583
                                )Net
      cash provided by operating activities
                                
                                
                                4,098,818
                                
                                
                                
                                10,079,049
                                
                                
                                
                                5,467,910CASH
      FLOWS FROM INVESTING ACTIVITIES:Exploration
      and development of oil and natural gas properties
                                
                                
                                (10,470,464
                                )
                                
                                
                                (51,955,565
                                )
                                
                                
                                (42,776,914
                                )Leasehold
      expenditures, net
                                
                                
                                (2,180,635
                                )
                                
                                
                                (11,960,049
                                )
                                
                                
                                (28,975,878
                                )Acquisition
      of oil and natural gas properties
                                
                                
                                -
                                
                                
                                
                                (2,405,609
                                )
                                
                                
                                (24,011,335
                                )Sale
      of oil and natural gas properties
                                
                                
                                3,263,762
                                
                                
                                
                                2,079,518
                                
                                
                                
                                11,489,456Option
      fees related to farmouts
                                
                                
                                173,256
                                
                                
                                
                                -
                                
                                
                                
                                -Sale
      and leaseback of gas compression equipment
                                
                                
                                -
                                
                                
                                
                                3,844,500
                                
                                
                                
                                -Acquisitions/additions
      for pipeline, property, and equipment
                                
                                
                                (372,847
                                )
                                
                                
                                (1,586,328
                                )
                                
                                
                                (4,647,497
                                )Additions
      in other investments
                                
                                
                                (12,206
                                )
                                
                                
                                (186,334
                                )
                                
                                
                                (855,070
                                )Sales
      of other investments
                                
                                
                                12,334
                                
                                
                                
                                1,069,378
                                
                                
                                
                                171,140Redesignation
      of cash equivalents to short-term investments
                                
                                
                                (1,114,627
                                )
                                
                                
                                -
                                
                                
                                
                                -Net
      cash used in investing activities
                                
                                
                                (10,701,427
                                )
                                
                                
                                (61,100,489
                                )
                                
                                
                                (89,606,098
                                )CASH
      FLOWS FROM FINANCING ACTIVITIES:Short-term
      bank borrowings
                                
                                
                                100,000
                                
                                
                                
                                16,412,822
                                
                                
                                
                                5,580,199Short-term
      bank payments
                                
                                
                                (100,000
                                )
                                
                                
                                (16,955,610
                                )
                                
                                
                                (11,355,827
                                )Advances
      on senior secured credit facility
                                
                                
                                13,800,000
                                
                                
                                
                                55,000,000
                                
                                
                                
                                60,000,000Payments
      on senior secured credit facility
                                
                                
                                -
                                
                                
                                
                                (9,000,000
                                )
                                
                                
                                (50,000,000
                                )Payments
      on mezzanine financing
                                
                                
                                -
                                
                                
                                
                                (40,000,000
                                )
                                
                                
                                -Advances
      on second lien term loan
                                
                                
                                -
                                
                                
                                
                                50,000,000
                                
                                
                                
                                -Payments
      on mortgage obligations and notes payable
                                
                                
                                (337,739
                                )
                                
                                
                                (272,471
                                )
                                
                                
                                (73,205
                                )Payments
      of financing fees on credit facilities
                                
                                
                                (85,163
                                )
                                
                                
                                (1,691,371
                                )
                                
                                
                                (2,452,786
                                )Prepayment
      penalties on debt extinguishment
                                
                                
                                -
                                
                                
                                
                                (1,866,580
                                )
                                
                                
                                -Capital
      contributions from minority interest members
                                
                                
                                363,183
                                
                                
                                
                                16,786
                                
                                
                                
                                -Distributions
      to minority interest members
                                
                                
                                (86,046
                                )
                                
                                
                                (49,839
                                )
                                
                                
                                -Proceeds
      from sales of common stock
                                
                                
                                -
                                
                                
                                
                                -
                                
                                
                                
                                54,505,807Proceeds
      from exercise of options and warrants
                                
                                
                                682,749
                                
                                
                                
                                198,500
                                
                                
                                
                                17,554,949Dividends
      paid on preferred stock
                                
                                
                                -
                                
                                
                                
                                -
                                
                                
                                
                                (20,250
                                )Other
                                
                                
                                (154,915
                                )
                                
                                
                                (80,515
                                )
                                
                                
                                154,059Net
      cash provided by financing activities
                                
                                
                                14,182,069
                                
                                
                                
                                51,711,722
                                
                                
                                
                                73,892,946Net
      increase (decrease) in cash and cash equivalents
                                
                                
                                7,579,460
                                
                                
                                
                                690,282
                                
                                
                                
                                (10,245,242
                                )Cash
      and cash equivalents, beginning of the period
                                
                                
                                2,425,678
                                
                                
                                
                                1,735,396
                                
                                
                                
                                11,980,638Cash
      and cash equivalents, end of the period
                                
                                $
                                10,005,138
                                
                                
                                $
                                2,425,678
                                
                                
                                $
                                1,735,396


63





AURORA
      OIL & GAS CORPORATION AND SUBSIDIARIES
              CONSOLIDATED
      STATEMENTS OF CASH FLOWS





Year Ended December 31,2008
                                
                                
                                2007
                                
                                
                                2006NONCASH
      FINANCING AND INVESTING ACTIVITIES:Oil
      and natural gas properties asset retirement obligation
                                
                                $
                                80,311
                                
                                
                                $
                                116,324
                                
                                
                                $
                                1,257,796Accrued
      exploration and development costs on oil and natural gas
      properties
                                
                                
                                26,202
                                
                                
                                
                                947,109
                                
                                
                                
                                11,161,730Accrued
      leasehold costs
                                
                                
                                14,115
                                
                                
                                
                                394,808
                                
                                
                                
                                426,120Field
      service acquisition through common stock issuance, including $600,000 of
      unproven leasehold
                                
                                
                                -
                                
                                
                                
                                -
                                
                                
                                
                                4,686,217Pipeline
      acquisition, transfer of investment to pipeline costs
                                
                                
                                2,209,400
                                
                                
                                
                                -
                                
                                
                                
                                1,100,973Processing
      facilities and compression, transfer from unproven
    properties
                                
                                
                                2,348,841
                                
                                
                                
                                1,244,669
                                
                                
                                
                                -Oil
      and natural gas properties capitalized stock-based
      compensation
                                
                                
                                65,062
                                
                                
                                
                                175,795
                                
                                
                                
                                457,013Oil
      and natural gas properties acquisition through other long-term
      liability
                                
                                
                                -
                                
                                
                                
                                600,000
                                
                                
                                
                                -Conversion
      of redeemable convertible preferred stock to common stock
                                
                                
                                -
                                
                                
                                
                                -
                                
                                
                                
                                59,925Conversion
      of accounts receivable to notes receivable
                                
                                
                                11,222
                                
                                
                                
                                35,469
                                
                                
                                
                                118,072Vehicle
      and equipment purchases through financing
                                
                                
                                193,787
                                
                                
                                
                                118,526
                                
                                
                                
                                -Land
      purchase through financing
                                
                                
                                70,000
                                
                                
                                
                                -
                                
                                
                                
                                -Sale
      of oil land gas properties through note receivable
                                
                                
                                12,000,000
                                
                                
                                
                                -
                                
                                
                                
                                -SUPPLEMENTAL
      INFORMATION OF INTEREST AND INCOME TAXES PAID:Interest,
      net of amount capitalized of $4,539,244, $4,508,767 and $3,896,645,
      respectively
                                
                                $
                                5,803,401
                                
                                
                                $
                                2,811,714
                                
                                
                                $
                                3,389,966Income
      taxes
                                
                                
                                21,892
                                
                                
                                
                                107,700
                                
                                
                                
                                6,629





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


64


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 an  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 focused on developing
operating interests in unconventional drilling programs in the Michigan Antrim
shale and the New Albany shale of Indiana and Kentucky. The Company’s drilling
program is dependent on access to the credit markets.  Due to the
current economic events within the banking industry and the Company currently
being in default under the senior secured credit facility and second lien term
loan more fully described in Note 8 “Debt”, the Company is having difficulty
securing the necessary credit to move forward with a development
program.  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.  Prior to the
termination of the Company’s natural gas derivatives on October 1, 2008, more
fully described in Note 6 “Risk Management Activities”, the Company periodically
entered into various derivative instruments with a major financial institution
to mitigate a portion of the exposure to adverse market changes.  The
Company is presently exposed to the fluctuation of natural gas
prices.





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.





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 asset retirement obligations, goodwill impairment, and fair value of
stock options.





Reclassifications





Certain
reclassifications have been made to consolidated financial statements for 2007
and 2006 in order to conform to the presentation used for the 2008 consolidated
financial statements.  These reclassifications had no effect on net
loss or net cash flows as previously reported.




65
 
 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
are held at four separate financial institutions and periodically exceed
federally insured limits.  As of December 31, 2008, cash in excess of
FDIC limits amounted to approximately $9.7 million.  The Company does
not anticipate any potential losses from uninsured amounts.





Short-Term
Investments





The
Company’s short-term investments are comprised of an investment in The Reserve
Primary Fund (the “Primary Fund”), a money market fund that has suspended
redemptions and is being liquidated.  In accordance with Statement of
Financial Accounting Standards (“SFAS”) No. 115, “Accounting for Certain
Investments in Debt and Equity Securities,” the Company records these
investments as trading securities at fair value.





In
mid-September, the net asset value of the Primary Fund decreased below $1 per
share as a result of the Primary Fund’s valuing at zero its holdings of debt
securities issued by Lehman Brothers Holdings, Inc., which filed for bankruptcy
on September 15, 2008.  Management has requested the redemption of the
Company’s investment in the Primary Fund.  Management expects
distributions will occur as the Primary Fund’s assets mature or are
sold.  While management expects to receive substantially all of the
Company’s current holdings in the Primary Fund, management cannot predict when
this will occur or the amount that ultimately will be
received.  Accordingly, management has reclassified the investment
from cash and cash equivalents to short-term investments as of December 31,
2008.





Accounts
Receivable





Accounts
receivable generally consist of amounts due from the sale of oil and natural
gas, field service and sales, 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. Customers and partners
are reviewed on a periodic basis throughout the year and 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, field service and 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 $4.5 million, $4.5 million, and
$3.9 million for the years ended December 31, 2008, 2007, and 2006,
respectively.


66




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


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.  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.  During the year ended December 31, 2008, the Company
recognized a ceiling write-down of oil and gas properties in the amount of $78.5
million as a result of the carrying amount of oil and gas properties subject to
amortization exceeding the full cost ceiling limitation.





The
following table sets forth financial data associated with unproved oil and
natural gas properties costs at December 31, 2008 ($ in thousands):





Balance as of
                            
                            
                            Net Costs Incurred During the Year Ended December 31,December 31, 2008
                            
                            
                            2008
                            
                            
                            2007
                            
                            
                            2006
                            
                            
                            2005 and priorAcquisition
      costs
                            
                            $
                            40,928
                            
                            
                            $
                            3,924
                            
                            
                            $
                            6,516
                            
                            
                            $
                            8,695
                            
                            
                            $
                            21,793Development
      costs
                            
                            
                            6,928
                            
                            
                            
                            (13,005
                            )(a)
                            
                            
                            5,458
                            
                            
                            
                            (1,012
                            )
                            
                            
                            15,487Total
      unproved properties
                            
                            $
                            47,856
                            
                            
                            $
                            (9,081
                            )
                            
                            $
                            11,974
                            
                            
                            $
                            7,683
                            
                            
                            $
                            37,280





(a) Reduction
is as a result of various sales more fully described in Note 7 “Acquisition and
Dispositions”.





Interest
costs capitalized on unproved properties during the years ended December 31,
2008, 2007, and 2006, totaled $4.5 million, $4.5 million, and $3.9 million,
respectively.  Capitalized interest costs of $3.2 million, $3.8
million, and $1.8 million are included in the balances above at December 31,
2008, 2007, and 2006, respectively, after transferring $1.3 million, $0.7
million, and $2.1 million from unproved to proven during the years 2008, 2007,
and 2006, respectively.





Note
Receivable





Note
receivable consists of amount due from the sale of our Oak Tree Project more
fully described in Note 13 “Related Party Transactions.”  Prior to
extending credit in the form of a note receivable the Company reviews the
customer for credit worthiness and secures collateral when
appropriate.  Interest income is recognized when
earned.


67




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)




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.





Revisions
for the year ended December 31, 2008, are not considered material and primarily
relate to changes in working interest on certain
properties.  Effective January 1, 2007, the accretion of ARO on
producing wells was adjusted for a change in 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 $0.6 million to estimated
liabilities.  In addition, revisions of estimated liabilities included
increases due to the removal of equipment salvage value totaling $0.1 million
and a decrease in the estimated well plugging costs for certain non-Antrim wells
totaling $0.1 million.  Revisions of estimated liabilities for 2006
included reductions in well working interest totaling $0.1 million and increases
in the salvage value of equipment totaling $0.1 million.





The
change in the ARO for the years ended December 31, 2008, 2007, and 2006 is as
follows ($ in thousands):





2008
                  
                  
                  2007
                  
                  
                  2006Beginning
      balance
                  
                  $
                  1,495
                  
                  
                  $
                  1,332
                  
                  
                  $
                  813Liabilities
      incurred
                  
                  
                  92
                  
                  
                  
                  708
                  
                  
                  
                  719Liabilities
      settled
                  
                  
                  (15
                  )
                  
                  
                  (62
                  )
                  
                  
                  (124
                  )Accretion
      expense
                  
                  
                  111
                  
                  
                  
                  77
                  
                  
                  
                  74Revisions
      of estimated liabilities
                  
                  
                  3
                  
                  
                  
                  (560
                  )
                  
                  
                  (150
                  )Ending
      balance
                  
                  $
                  1,686
                  
                  
                  $
                  1,495
                  
                  
                  $
                  1,332





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.  During 2008, the Company sold
and disposed of various assets resulting in a loss of $12,374.  Total
proceeds received in connection with the sale amounted to $785.  The
Company did not recognize any impairment losses for the years ended December 31,
2007 or 2006.  A summary of the other property and equipment for the
year ended December 31, 2008 and 2007 and the useful lives are as follows ($ in
thousands):


68




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


2008
                              
                              
                              2007
                              
                              
                              Useful Life
                                in YearsPipelines
                              
                              $
                              7,366
                              
                              
                              $
                              7,322
                              
                              
                              
                              15Processing
      facilities and compression
                              
                              
                              2,640
                              
                              
                              
                              2,656
                              
                              
                              
                              10Building
                              
                              
                              1,050
                              
                              
                              
                              1,050
                              
                              
                              
                              30Total
      pipelines, processing facilities and compression
                              
                              
                              11,056
                              
                              
                              
                              11,028Less:
      accumulated depreciation
                              
                              
                              (1,429
                              )
                              
                              
                              (818
                              )Pipelines,
      processing facilities, and compression, net
                              
                              $
                              9,627
                              
                              
                              $
                              10,210Land
                              
                              $
                              170
                              
                              
                              $
                              78
                              
                              
                              
                              N/ABuildings
                              
                              
                              3,565
                              
                              
                              
                              3,552
                              
                              
                              
                              40Furniture
      and fixtures
                              
                              
                              289
                              
                              
                              
                              329
                              
                              
                              
                              5-10Office
      equipment
                              
                              
                              92
                              
                              
                              
                              68
                              
                              
                              
                              5Computer
      equipment
                              
                              
                              177
                              
                              
                              
                              252
                              
                              
                              
                              5Software
                              
                              
                              240
                              
                              
                              
                              257
                              
                              
                              
                              3-5Vehicles
      and other equipment
                              
                              
                              1,344
                              
                              
                              
                              914
                              
                              
                              
                              5Total
      other property and equipment
                              
                              
                              5,877
                              
                              
                              
                              5,450Less:
      accumulated depreciation
                              
                              
                              (1,052
                              )
                              
                              
                              (736
                              )Other
      property and equipment, net
                              
                              $
                              4,825
                              
                              
                              $
                              4,714





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.  During 2008, the
Company sold certain properties in GeoPetra Partners, LLC more fully described
in Note 7 “Acquisitions and Dispositions”.  Investment in GeoPetra
Partners, LLC amounted to $0.5 million at December 31,
2007.  Investments in mineral properties and other investments
amounted to $0.2 million at December 31, 2007 and were written off to general
and administrative expense for the year ended December 31, 2008.





Intangible
Assets





Acquired
intangible assets consist of a noncompete agreement. This asset is recorded at
fair value or cost and amortized on a straight-line basis using an estimated
useful life of 7 years.  A summary of amortization expense over the
next 4 years is as follows ($ in thousands):





Year
                          
                          Amount2009
                          
                          $
                          172010
                          
                          
                          172011
                          
                          
                          172012
                          
                          
                          12$
                          63





69
 
 AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


During
2008, the Company determined a patent was impaired and recorded an expense to
general and administrative expense for the year ended December 31, 2008 in the
amount of $250,000.




Revenue
Recognition





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





Sales
and Major Customers





The
Company markets natural gas 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.  Since the expiration of the firm sales contract on December 31,
2008, the Company has been negotiating 4,500 mmbtu per day on a month by month
basis.





Management
is currently in discussions about the possibility of entering into a long-term
contract.  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, 2008, one gas marketing firm accounted for 63% of total
oil and natural gas revenues. 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.





Stock-Based
Compensation





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





70


AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


For the
years ended December 31, 2008, 2007, and 2006, the Company recorded the
following stock-based compensation ($ in thousands):




For
      the Years Ended December 31,
                  
                  2008
                  
                  
                  2007
                  
                  
                  2006General
      and administrative expenses
                  
                  $
                  1,318
                  
                  
                  $
                  2,222
                  
                  
                  $
                  2,207Production
      and lease operating expenses
                  
                  
                  12
                  
                  
                  
                  -
                  
                  
                  
                  -Pipeline
      and processing operating expenses
                  
                  
                  1
                  
                  
                  
                  -
                  
                  
                  
                  -Oil
      and natural gas properties
                  
                  
                  65
                  
                  
                  
                  176
                  
                  
                  
                  457Total
                  
                  $
                  1,396
                  
                  
                  $
                  2,398
                  
                  
                  $
                  2,664




The
following table provides the unrecognized compensation expense related to
unvested stock options as of December 31, 2008.  The expense is
expected to be recognized over the following remaining periods indicated ($ in
thousands):




Period
      to
                          be
                          Recognized
                        
                        2009
                        
                        
                        2010
                        
                        
                        2011
                        
                        Total
                          Unrecognized
                          Compensation
                          Expense1st
      Quarter
                        
                        $
                        252
                        
                        
                        $
                        99
                        
                        
                        $
                        392nd
      Quarter
                        
                        
                        193
                        
                        
                        
                        78
                        
                        
                        
                        263rd
      Quarter
                        
                        
                        106
                        
                        
                        
                        40
                        
                        
                        
                        -4th
      Quarter
                        
                        
                        102
                        
                        
                        
                        40
                        
                        
                        
                        -Total
                        
                        $
                        653
                        
                        
                        $
                        257
                        
                        
                        $
                        65
                        
                        $      975





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 2004.  The Company is currently not
under an examination by any U.S. federal, state, or local tax
authorities.





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.  No liabilities
or assets have been recognized as a result of the implementation of FIN
48.


71




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)




As of
December 31, 2008, the Company had approximately $14.2 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 or 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.  More fully
described in Note 6 “Risk Management Activities” the Company’s derivative
instruments were terminated on October 1, 2008.  The details of
comprehensive income (loss) are as follows ($ in thousands):





Years Ended December 31,
                  
                  2008
                  
                  
                  2007
                  
                  
                  2006Net
      Loss
                  
                  $
                  (107,365
                  )
                  
                  $
                  (4,422
                  )
                  
                  $
                  (1,945
                  )Other
      comprehensive income:Changes
      in fair value of natural gas derivative instruments
                  
                  
                  (5,883
                  )
                  
                  
                  (473
                  )
                  
                  
                  7,904Changes
      in fair value of interest rate derivative instruments
                  
                  
                  589
                  
                  
                  
                  (1,207
                  )
                  
                  
                  -Recognition
      of losses (gains) on derivative instruments
                  
                  
                  5,679
                  
                  
                  
                  (3,926
                  )
                  
                  
                  (2,683
                  )385
                  
                  
                  
                  (5,606
                  )
                  
                  
                  5,221Comprehensive
      Income (Loss)
                  
                  $
                  (106,980
                  )
                  
                  $
                  (10,028
                  )
                  
                  $
                  3,276





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. For the years ended December 31, 2008,
2007, and 2006, respectively, options and warrants to purchase 6,560,445,
2,175,280, and 766,500 shares of common stock were not included in the
computation of diluted net income (loss) per share as their effect would have
been anti-dilutive.





NOTE 3.  GOING CONCERN




The
Company’s financial statements for the year ended December 31, 2008, have been
prepared on a going concern basis which contemplates the realization of assets
and the settlement of liabilities in the normal course of
business.  With the loss of production and significant deficiencies in
working capital along with the increase in interest rates and termination of the
Company’s natural gas and interest rate derivatives more fully described in Note
6 “Risk Management Activities”, the Company’s operations and existing cash
balances are not sufficient to support interest requirements on existing debt
balances for longer than one year.  The Company is currently in
default under the senior secured credit facility and second lien term loan which
are more fully described in Note 8 “Debt”.  The Company’s continued
existence is dependent on (1) the lenders’ willingness to refrain from
accelerating or demanding repayment on current debt obligations, (2)
restructuring the Company’s current debt and interest payments, (3) securing
alternative financing arrangements, and/or (4) asset
divestitures.  Management continues discussions with existing lenders
and is seeking alternative financing arrangements and opportunities for asset
divestitures.  There is no assurance the lenders will not call the
debt obligation or that the Company will be able to restructure or refinance its
current debt or sell assets.


72


AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


These
uncertainties raise substantial doubt about the ability of the Company to
continue as a going concern.  The accompanying consolidated financial
statements do not include any adjustments that might result from the outcome of
these uncertainties should the Company be unable to continue as a going
concern.





NOTE
4.  IMPAIRMENT OF GOODWILL




On
January 1, 2008, the Company had goodwill of $16.0 million related to the
reverse acquisition of Cadence Resources Corporation (“Cadence”) executed in
October 2005 and $3.4 million related to the acquisition of Bach Services &
Manufacturing Co., LLC (“Bach”), a subsidiary of the Company, executed in
October 2006 and more fully described in Note 7 “Acquisitions and
Disposition”.





The
Company tests goodwill for impairment annually in accordance with Statement of
Financial Standards No. 142, “Goodwill and Other Intangible Assets” (“SFAS
142”).  SFAS 142 requires goodwill be tested at least annually using a
two-step process that begins with identifying potential
impairment.  Potential impairment is identified if the fair value of
the reporting unit to which goodwill applies is less than the recognized or book
value of the related reporting entity, including such goodwill.  Where
the book value of a reporting entity, including related goodwill, is greater
than the reporting entity’s fair value, the second step of the goodwill
impairment test is performed to measure the amount of impairment loss, if any.
Based on the Company’s continued loss in production, management has determined
using projected discounted future operating cash flows at a 10% discount rate as
a measurement of goodwill impairment for the Cadence acquisition is not
appropriate.  Accordingly, management measured goodwill impairment
using quoted market prices of common stock adjusted for known synergies and
other benefits arising from subsidiaries.  For the Bach acquisition,
the Company measured goodwill using the anticipated sales price of the company
derived from internal valuations.





As of
December 31, 2008, the Company determined that there was an impairment of
goodwill related to Cadence and Bach.  Accordingly, the Company
recorded a full impairment of goodwill for the Cadence and Bach acquisitions
which resulted in a write-down of $19.4 million and has been recorded as an
operating expense in the consolidated statements of operations for the year
ended December 31, 2008.  There were no impairments to goodwill during
the years ended December 31, 2007 and 2006.





NOTE
5.  RECENT ACCOUNTING PRONOUNCEMENTS




On
December 31, 2008, the SEC adopted a final rule that amends its oil and gas
reporting requirements.  The revised rules change the way oil and gas
companies report their reserves in the financial statements.  The
rules are intended to reflect changes in the oil and gas industry since the
original disclosures were adopted in 1978.  Definitions were updated
to be consistent with Petroleum Resource Management System
(“PRMS”).  Other key revisions include a change in pricing used to
prepare reserve estimates, the inclusion of non-traditional resources in
reserves, the allowance for use of new technologies in determining reserves,
optional disclosure of probable and possible reserves and significant new
disclosures.  The revised rules will be effective for the Company’s
annual report on Form 10-K for the fiscal year ending December 31,
2009.  The SEC is precluding application of the new rules in quarterly
reports prior to the first annual report in which the revised disclosures are
required and early adoption is not permitted.  The Company is
currently evaluating the effect the new rules will have on the Company’s
financial reporting and anticipate that the following rule changes could have a
significant impact on the Company’s results of operations as
follows:




73


AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


·
            The
      price used in calculating reserves will change from a single-day closing
      price measured on the last day of the Company’s fiscal year to a 12-month
      average price, and will affect the Company’s depletion and ceiling test
      calculations.





·
            Several
      reserve definitions have changed that could revise the types of reserves
      that will be included in our year-end reserve
  report.





·
            Some
      of the Company’s financial reporting disclosures could change as a result
      of the new rules.


In
December 2008, the FASB issued FASB Staff Position (“FSP”) FAS 140-4 and FIN
46(R)-8, “Disclosure by Public Entities (Enterprises) About Transfers of
Financial Assets and Interests in Variable Interest Entities”.  The
purpose of the FSP is to promptly improve disclosures by public companies until
the pending amendments to FASB Statement No. 140, “Accounting for Transfers and
Servicing of Financial Assets and Extinguishment of Liabilities” (“SFAS 140”),
and FIN 46R are finalized and approved by the FASB.  The FSP amends
SFAS 140 to require public companies to provide additional disclosures about
transferor’s continuing involvement with transferred financial
assets.  It also amends FIN 46R by requiring public companies to
provide additional disclosures regarding their involvement with variable
interest entities.  This FSP is effective December 31, 2008 and has
not had a material impact on the consolidated financial statements.





In May
2008, the FASB issued SFAS No. 162 “The Hierarchy of Generally Accepted
Accounting Principles” (“SFAS 162”).  SFAS 162 identifies the sources
of accounting principles and the framework for selecting the principles used in
the preparation of financial statements of nongovernmental entities that are
presented in conformity with GAAP.  This statement shall be effective
60 days following the Securities Exchange and Commission’s approval of the
Public Company Accounting Oversight Board amendments to AU Section 411, “The
Meaning of Present Fairly in Conformity With Generally Accepted Accounting
Principles.”  Management does not expect its adoption will have a
material impact on the consolidated financial statements.





In April
2008, the FASB issued FASB Staff Positions (“FSP”) No. FAS 142-3, “Determination
of the Useful Life of Intangible Assets.” FSP No. FAS 142-3 amends the factors
that should be considered in developing renewal or extension assumptions used to
determine the useful life of a recognized intangible asset under SFAS No. 142,
“Goodwill and Other Intangible Assets.”  The intent of the position is
to improve the consistency between the useful life of a recognized intangible
asset under SFAS No. 142 and the period of expected cash flows used to measure
the fair value of the asset under SFAS No. 141R, and other U.S. generally
accepted accounting principles.  The provisions of FSP No. FAS 142-3
are effective for fiscal years beginning after December 15,
2008.  Management does not expect the adoption of FSP No. FAS 142-3 to
have a material impact on the consolidated financial statements.





In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments
and Hedging Activities”, an amendment of FASB
Statement No. 133 (“SFAS 161”).  SFAS 161 requires enhanced
disclosures about an entity’s derivative instruments and hedging activities,
including:  (1) how and why an entity uses derivative instruments; (2)
how derivative instruments and related hedged items are accounted for under SFAS
133 and its related interpretations; and (3) how derivative instruments and
related hedged items affect an entity’s financial position, financial
performance, and cash flows.  SFAS 161 is effective for financial
statements issued for fiscal years and interim periods beginning after November
15, 2008, with earlier application encouraged.  With the termination
of the Company’s derivative instruments more fully disclosed in Note 6 “Risk
Management Activities”, management does not expect the adoption to have any
impact on the consolidated financial statements unless the Company engages in
hedge contracts.





74
 
 AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


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.





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.  We did not elect to apply the fair value option to any of our
financial instruments.




In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS
157”), which is effective for fiscal years beginning after November 15, 2007,
and for interim periods within those years.  This statement defines
fair value, establishes a framework for measuring fair value and expands the
related disclosure requirements.  This statement applies under other
accounting pronouncements that require or permit fair value
measurements.  The statement indicates, among other things, that a
fair value measurement assumes that the transaction to sell an asset or transfer
a liability occurs in the principal market for the asset or liability or, in the
absence of a principal market, the most advantageous market for the asset or
liability.  SFAS 157 defines fair value based upon an exit price
model.





Relative
to SFAS 157, the FASB issued FSP 157-1 and 157-2.  FSP 157-1 amends
SFAS 157 to exclude SFAS No. 13, “Accounting for Leases” (“SFAS 13”), and its
related interpretive accounting pronouncements that address leasing
transactions, while FSP 157-2 delays the effective date of the application of
SFAS 157 to fiscal years beginning after November 14, 2008, for all nonfinancial
assets and nonfinancial liabilities that are recognized or disclosed at fair
value in the financial statements on a nonrecurring basis.  In October
2008, the FASB issued FSP No. FAS 157-3 “Determining the Fair Value of a
Financial Asset When the Market for That Asset Is Not Active” (“FSP No. FAS
157-3”), which clarifies the application of SFAS No. 157 for financial assets in
a market that is not active.  FSP No. FAS 157-3 was effective upon
issuance.





We
adopted SFAS 157 as of January 1, 2008, with the exception of the application of
the statement to nonrecurring nonfinancial assets and nonfinancial
liabilities.  As of January 1, 2009, the Company adopted SFAS 157 as
it relates to nonrecurring nonfinancial assets and nonfinancial
liabilities.   Nonrecurring nonfinancial assets and nonfinancial
liabilities include those measured at fair value in goodwill impairment testing,
indefinite lived intangible assets measured at fair value for impairment
testing, and asset retirement obligations initially measured at fair
value.  SFAS 157 has not materially affected how the Company
determines fair value, but has resulted and will result in certain additional
disclosures.





NOTE
6.  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 previously entered into various
derivative instruments with a major financial institution.  The
purpose of the derivative instrument was 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 reduced the
Company’s exposure on the hedged production volumes to decreases in commodity
prices and limited the benefit the Company might otherwise have received from
any increases in commodity prices on the hedged production volumes.





75
 
 AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


On
October 1, 2008, the Company received a notice of early termination from BNP
Paribas (“BNP”) with respect to the Company’s natural gas and interest rate swap
derivatives (the “Early Termination Notice”) in accordance with the 1992
International Swap Dealers Association, Inc. (“ISDA”) master agreement dated
August 20, 2007, between the Company and BNP.  The Early Termination
Notice references Sections 6(a) and 6(b) of the ISDA master agreement which
gives BNP the right to terminate following an event of default (the Company
received a notice of default on October 3, 2008, from BNP which is more fully
described in Note 8 “Debt”).  The settlement amount in connection with
the Early Termination Notice amounted to $0.6 million for the natural gas
derivatives and was classified as a liability included with the senior secured
credit facility.  As a result of the natural gas derivative contracts
termination, the Company is presently exposed to the fluctuation of natural gas
prices.


For the
years ended December 31, 2008, 2007 and 2006, the Company has recognized in
Comprehensive Income (Loss) changes in fair value of $(5.9) million, $(0.5)
million, and $7.9 million, respectively, on the contracts that have been
designated as cash flow hedges on forecasted sales of natural
gas.  See “Comprehensive Income (Loss)” found in Note 2 “Basis of
Presentation and Summary of Significant Accounting Policies”.  For the
year ended December 31, 2008, the Company recognized $3.6 million of net losses
from hedging activities included in oil and gas revenues.  For the
years ended December 31, 2007, and 2006, the Company recognized $3.9 million and
$2.7 million, respectively in net gains from hedging activities included in oil
and natural gas revenues.





The
following table sets forth components of oil and gas sales ($ in
thousands):





Years Ended December 31,
                    
                    2008
                    
                    
                    2007
                    
                    
                    2006Oil
      and natural gas sales
                    
                    $
                    28,739
                    
                    
                    $
                    22,850
                    
                    
                    $
                    18,909Realized
      (losses) gains on natural gas derivatives
                    
                    
                    (3,537
                    )
                    
                    
                    3,874
                    
                    
                    
                    2,683Total
                    
                    $
                    25,202
                    
                    
                    $
                    26,724
                    
                    
                    $
                    21,592




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.





The
settlement amount for the interest rate swap derivative in connection with the
Early Termination Notice amounted to approximately $1.6 million and was
classified as a liability included with the senior secured credit
facility.  As a result of the interest rate derivative contract
termination, the Company is presently exposed to the fluctuation of interest
rates.


76




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)




For the
years ended December 31, 2008, and 2007, the Company has recognized in
Comprehensive Income (Loss) changes in fair value of $0.6 million and $(1.2)
million, respectively, on the interest rate swap.  See “Comprehensive
Income (Loss)” found in Note 2 “Basis of Presentation and Summary of Significant
Accounting Policies”.  For the years ended December 31, 2008, and
2007, the Company recognized $2.1 million in interest expense, which included
$1.6 million related to the Early Termination Notice more fully described in the
previous paragraph and $0.1 million in interest savings, respectively, related
to the hedge activity which is recorded as an adjustment to interest
expense.





Financial
Instruments





The
Company has financial instruments for which the fair value of the financial
instruments could be different than that recorded on a historical basis in the
accompanying balance sheets.  The Company’s financial instruments
consist of cash, short-term investments, accounts receivable, note receivable,
accounts payable, accrued expenses, and debt.  The carrying amounts of
the Company’s financial instruments approximate their fair values as of December
31, 2008, due to their short-term nature.





Concentration
of Credit Risk





Financial
instruments that subject the Company to concentrations of credit risk consist
primarily of temporary cash investments, short-term investments, trade
receivables, and note receivable.  The Company believes it has placed
its demand deposits with high credit quality financial
institutions.  As more fully described in Note 2 “Basis of
Presentation and Summary of Significant Accounting Policies,” the Company’s
short-term investments are comprised of an investment in the Primary Fund which
is a money market fund that decreased below $1 per share and is currently being
liquidated.  While management recognizes there is increased credit
risk associated with this investment, management expects to receive
substantially all of the company’s current holdings in the Primary
Fund.  Concentrations of credit risk with respect to trade receivable
are primarily focused on companies involved in the exploration and development
of oil and natural gas properties.  The concentration is somewhat
mitigated by the diversification of customers for which the Company provides
services or partners with.  As is general industry practice, the
Company typically does not require customers or joint venture partners to
provide collateral.  No significant losses from individual customers
or joint venture partners were experienced during the years ended December 31,
2008, 2007, or 2006.





During
2008 we entered into a note receivable as more fully described in Note 13
“Related Party Transactions”.  The Company believes the concentration
of credit risk associated with this note receivable is sufficiently mitigated
based on the collateral secured as part of this agreement.





NOTE
7.  ACQUISITIONS AND DISPOSITIONS





2008
New Albany Shale





North
Knox





On
December 1, 2008, the Company received proceeds of $25,794 in connection with
the sale of a 45% working interest in the North Knox project.  The
project is located in Knox County Indiana and covers approximately 129 net
acres.





Release
of Oil and Gas Leases





During
November 2008, the Company received proceeds amounting to $15,375 and $3,183 for
leases released in Spencer County and DeKalb Counties, Indiana respectively and
covers approximately 440 net acres.





77
 
 AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


New
Albany Shale Exchange





On August
12, 2008, the Company exchanged 42,988 net acres located in the Lawrence, Knox,
and Sullivan Counties, Indiana for 40,316 net acres located in Owen, Sullivan,
Clay, Green, Lawrence, Washington, Jackson, and Orange Counties,
Indiana.  As part of this transaction, the Company increased reserves
by 1,232 mcfe and increased the Company’s working interest by
15.68%.





2008
Other





Dehydration
Contactor and Regenerator Sale





On
December 18, 2008, the Company sold a dehydration contactor and regenerator to
Acadian Energy, LLC (related party more fully disclosed in Note 13 “Related
Party Transactions”) for a purchase price of $15,368.





AOK
Energy, LLC





As more
fully disclosed in Note 13 “Related Party Transactions”, effective September 12,
2008, the Company sold all its membership interest in AOK Energy, LLC to
Presidium Energy, LC for $15 million.





GeoPetra





In April
2008, the Company sold a 3.75% interest in the GeoPetra prospect for
$79,322.  The interest covers approximately 285 net acres in St.
Martin and Iberville Counties, Louisiana.





Other





During
2008, the Company received proceeds of $124,720 in connection with the sale of
all its interest in five separate prospects.  The prospects were
located in Benzie, Grand Traverse, Mecosta, Newaygo, and Oscoda Counties,
Michigan and cover approximately 6,410 net acres.





2007
Michigan Antrim Shale





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
New Albany Shale





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.


78




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)




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
Other





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.





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, 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.





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.





2006
New Albany Shale Sales





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
Other





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%.


79




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)





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.





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.





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.





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, forming Bach Services and
Manufacturing Co., LLC (“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, pipelines, and facility construction. The
purchase price included common stock and cash.  The common stock
issued was subject to a one-year lock-up period. In addition, the Company
entered into five-year employment agreements with two principals of Bach who
agreed not to compete during their employment and for a period of one year
following termination of their employment.





NOTE
8.  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.  Interest expense on the
revolving line of credit for the years ended December 31, 2007, and 2006, was
$32,873 and $0.3 million, respectively.




Northwestern
Bank continues to provide letters of credit for the Company’s drilling program
(as described in Note 12 “Commitments and Contingencies”).




80
 
 AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


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 Bach’s personal property owned or hereafter
acquired and is non-recourse to the Company.  Effective December 8,
2008, Bach extended the expiration maturity date of this revolving line of
credit to December 1, 2009.  As part of the extension agreement,
Bach’s maximum borrowings were reduced to $250,000.  The interest rate
under the revolving line of credit is Wall Street Prime with a floor of 4.0%
(effective rate of 4.0% at December 31, 2008) with interest payable in
arrears.  Principal is payable at the expiration of the
agreement.  Interest expense for the years ended December 31, 2008,
2007, and 2006, was $1,523, $3,082, and $2,166, respectively.




Mortgage
and Notes Payable – Bach




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




Description of Loan
                    
                    Date of Loan
                    
                    Maturity Date
                    
                    InterestRate
                    
                    
                    Principal
                      Amount
                      OutstandingMortgages
      payable:Land
      Mortgage
                    
                    09/19/08
                    
                    10/01/11
                    
                    
                    5.95%
                    
                    
                    $
                    69,419Building
      Mortgage
                    
                    12/18/06
                    
                    06/15/10
                    
                    
                    6.00%
                    
                    
                    
                    356,435Total
      mortgages payable
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    $
                    425,854Notes
      payable:Vehicles
                    
                    09/13/07
      - 9/12/08
                    
                    09/15/10
      - 09/15/12
                    
                    
                    6.50%
      - 6.95%
                    
                    
                    $
                    84,643Equipment
                    
                    07/03//08
      - 10/02/08
                    
                    07/03/13
      - 10/03/13
                    
                    
                    5.00%
                    
                    
                    
                    103,490Total
      notes payable
                    
                    
                    
                    
                    
                    
                    
                    
                    
                    $
                    188,133





The
obligations above are collateralized by the assets that are
financed.





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




Interest
      ExpenseDescription
      of Loan
                                              
                                              Date
      ofLoan
                                              
                                              Maturity
      Date
                                              
                                              InterestRate
                                              
                                              
                                              2008
                                              
                                              
                                              2007
                                              
                                              
                                              2006Mortgages
      payable:Land
      Mortgage
                                              
                                              09/19/08
                                              
                                              10/01/11
                                              
                                              
                                              5.95%
                                              
                                              
                                              $
                                              1,201
                                              
                                              
                                              $
                                              -
                                              
                                              
                                              $
                                              -Building
      Mortgage
                                              
                                              12/18/06
                                              
                                              10/15/09
                                              
                                              
                                              7.25%
                                              
                                              
                                              
                                              21,787
                                              
                                              
                                              
                                              20,657
                                              
                                              
                                              
                                              5,352Total
      mortgages payable
                                              
                                              
                                              
                                              
                                              
                                              
                                              
                                              
                                              
                                              $
                                              22,988
                                              
                                              
                                              $
                                              20,657
                                              
                                              
                                              $
                                              5,352Notes
      payable:Vehicles
                                              
                                              10/06/06
                                              
                                              Paid
                                              
                                              
                                              7.50%
                                              
                                              
                                              $
                                              3,630
                                              
                                              
                                              $
                                              6,006
                                              
                                              
                                              $
                                              1,618Equipment
                                              
                                              10/06/06
                                              
                                              Paid
                                              
                                              
                                              5.50%
                                              
                                              
                                              
                                              -
                                              
                                              
                                              
                                              253
                                              
                                              
                                              
                                              198Vehicles
                                              
                                              12/18/06
                                              
                                              Paid
                                              
                                              
                                              7.25%
                                              
                                              
                                              
                                              2,461
                                              
                                              
                                              
                                              4,158
                                              
                                              
                                              
                                              -Vehicles
                                              
                                              04/23/07
                                              
                                              Paid
                                              
                                              
                                              7.00%
                                              
                                              
                                              
                                              4,313
                                              
                                              
                                              
                                              4,213
                                              
                                              
                                              
                                              -Vehicles
                                              
                                              09/13/07-09/12/08
                                              
                                              09/15/10-9/15/12
                                              
                                              
                                              6.50%
      - 6.95%
                                              
                                              
                                              
                                              3,980
                                              
                                              
                                              
                                              424
                                              
                                              
                                              
                                              -Equipment
                                              
                                              09/13/07-09/12/08
                                              
                                              07/03/12-10/03/13
                                              
                                              
                                              5.00%
                                              
                                              
                                              
                                              2,366
                                              
                                              
                                              
                                              -
                                              
                                              
                                              
                                              -Total
      notes payable
                                              
                                              
                                              
                                              
                                              
                                              
                                              
                                              
                                              
                                              $
                                              16,750
                                              
                                              
                                              $
                                              15,054
                                              
                                              
                                              $
                                              1,816


81
  AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)




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 $2,364,419 on February 1, 2011. The
interest rate is 5.95% per year. As of December 31, 2008, the principal amount
outstanding was $2.6 million.  Interest expense for the years ended
December 31, 2008, 2007, and 2006, was $0.2 million, $0.1 million, and $0.1
million, 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.  This obligation was
paid in full during August 2007.   Interest expense for the year
ended December 31, 2007, was $2,546.




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 term lien loan discussed below, 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
then current authorized borrowing base of $50 million to $70 million effective
August 20, 2007.  The amount of the borrowing base was based primarily
upon the estimated value of the Company’s oil and 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.




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 3.0% (increased range by 1.0% from 2.0% to 3.0% as a result of the
forbearance agreement and amendment no. 1 to the senior secured credit facility
dated June 12, 2008, more fully described in the following paragraphs) 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, 2008, interest on the
borrowings including the Early Termination Notice liability more fully described
in Note 6 “Risk Management Activities”, had a weighted average interest rate of
6.5%.  For the years ended December 31, 2008, 2007, and 2006, interest
and fees incurred for the senior secured credit facility including the Early
Termination Notice liability were $4.0 million, $2.7 million, and $2.3 million,
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.


82




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)





The
senior secured credit facility contains, among other things, a number of
financial and non-financial covenants relating to restricted payments (as
defined), loans or advances to others, additional indebtedness, incurrence of
liens, geographic limitation 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 maturing of any indebtedness thereunder is also an event of
default under the senior secured credit facility.




On June
6, 2008, BNP notified the Company that the syndication had redetermined the
Company’s borrowing base to be $50 million.  As a result, there was a
potential borrowing base deficiency of as much as $20
million.  According to the senior secured credit facility, the Company
would be required to repay any deficiency in three equal monthly installments
within 90 days following notification, subject to, among other things, the
Company’s right to request an interim redetermination of the borrowing
base.




On June
12, 2008 (but as of June 2, 2008), the Company and certain subsidiaries, as
guarantors, entered into a forbearance agreement and amendment no. 1 to the
senior secured credit facility (the “First Forbearance and Amendment Agreement”)
with BNP and the syndication to address the Company’s failure to satisfy certain
financial and non-financial covenants for the first quarter ended March 31,
2008.  In accordance with the First Forbearance and Amendment
Agreement, BNP permanently waived any defaults or events of default resulting
from the non-compliance with any covenant failures for any date of determination
prior to and including March 31, 2008.  BNP also agreed to forbear and
refrain from (i) accelerating any loans outstanding (including any borrowing
base deficiency), (ii) exercising all rights and remedies, and (iii) taking any
enforcement action under the senior secured credit facility or otherwise as a
result of certain potential covenant defaults during the period from June 2,
2008, until August 15, 2008 (the “Standstill Period”), provided the Company
complied with certain forbearance covenants (collectively, the “Forbearance
Covenants”).  The First Forbearance Covenants were (i) the Company was
required to deliver to the syndication on or before the twentieth business day
of each month, a detailed monthly financial reporting package for the previous
month that shall include account payables aging, working capital, monthly
production reports, and lease operating statements, (ii) the Company was
required to participate in monthly conference calls with the syndication during
which a financial officer of the Company would provide the syndication with an
update on restructuring and cost reduction efforts, and (iii) no later than
August 14, 2008, the Company was required to execute (or cause to be executed)
additional mortgages such that, after giving effect to such additional
mortgages, the syndication will have liens on not less that 90% of the PV10 of
all proved oil and gas properties evaluated in the reserve report most recently
delivered prior to such date.  The First Forbearance and Amendment
Agreement also increased the additional margin spread from 2.0% to 3.0% when
electing a LIBOR-based borrowing rate.  From August 14, 2008 until the
execution of a second forbearance agreement on February 12, 2009 more fully
described in Note 17 “Subsequent Events,” the Company did not comply with a
provision of the First Forbearance Covenants which required the Company to
execute additional mortgages on not less than 90% of all the Company’s proved
oil and gas properties.




On
October 3, 2008, the Company received a notice of default from BNP with respect
to the senior secured credit facility (the “Notice of Default).  The
Notice of Default states that an event of default occurred under (1) Section
10.01(a) of the senior secured credit facility due to the Company’s failure to
pay the first of three principal borrowing base deficiency payments in the
approximate amount of $6.6 million, (2) Section 10.01(g) of the senior secured
credit facility due to the swap termination amount in connection with the Early
Termination Notice exceeding $500,000, (3) Section 10.01(f) of the senior
secured credit facility due to the Company’s failure to pay the settlement
amount of approximately $2.2 million ($0.6 million for natural gas derivatives
and $1.6 million for interest rate derivative) by the due date of October 2,
2008, in connection with the Early Termination Notice, and (4) Sections 8.14,
8.18, and 9.01 of the senior secured credit facility and second lien term loan
(cross default) due to the Company’s failure to comply with certain financial
and non-financial covenants.


83




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)


The
Notice of Default informed the Company, as of October 1, 2008, that the interest
rate under the senior secured credit facility shall bear interest at the default
rate of prime plus 3.0% thereby increasing the Company’s current interest rate
under the senior secured credit facility by 2% to approximately 8.0% (6.25% at
December 31, 2008).




The
Company continues to engage in discussions with BNP and the syndication to
restructure the Company’s debt.  Management recognizes that subject to
the terms of the February 12, 2009 Second Forbearance Agreement more fully
described in Note 17 “Subsequent Events,” the senior secured credit facility
will be due and payable upon notification from BNP, and therefore the entire
outstanding debt has been classified as a current liability on the accompanying
December 31, 2008 balance sheet.  In addition to discussions with BNP
and the syndication, management is also seeking alternative financing
arrangements and opportunities for asset divestitures.  Upon
expiration of the February 12, 2009 Second Forbearance Agreement, there is no
assurance that BNP and the syndication will not accelerate or demand repayment
of the senior secured credit facility or that management will be successful in
restructuring the Company’s debt, finding alternative financing arrangements, or
selling Company assets.




The
Company has incurred deferred financing fees of $0.7 million 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 was $0.2 million, $0.2 million, and
$0.1 million for the years ended December 31, 2008, 2007, and 2006,
respectively.  During 2008, the Company also incurred additional
financing fees in the amount of $0.3 million in connection with the Forbearance
and Amendment Agreement.  The additional financing fees were recorded
as an increase to general and administrative expense.  In addition,
the Company incurs various annual fees associated with unused commitment and
agency fees which are recorded to interest expense.




Second
Lien Term Loan




On
August, 20, 2007, the Company entered into a second lien term loan agreement
with BNP as the arranger and administrative agent, and several other lenders
forming a syndication (the “Term Loan”).  During August 2008, the
Company was notified that Laminar Direct Capital, LLC (“Laminar”) succeeded BNP
as the arranger and administrative agent for the second lien term
loan.  The initial term loan was $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 second lien
term 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 second lien term loan is
payable at rates based on the London Interbank Offered Rate (“LIBOR”) plus 950
basis points (increased from 700 basis points as a result of the forbearance
agreement and amendment no. 1 to the second lien term loan dated June 12, 2008,
more fully described in the following paragraphs) 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 second lien
term loan during the first year at a price equal to 103% of par, during the
second year at a price equal to 102% of par, and thereafter at a price equal to
100% of par.




On June
12, 2008 (but as of June 2, 2008), the Company and certain subsidiaries, as
guarantors, entered into a forbearance agreement and amendment no. 1 to the Term
Loan (the “Term Loan Forbearance and Amendment Agreement”) with BNP and the
syndication to address the Company’s failure to satisfy certain financial and
non-financial covenants for the first quarter ended March 31,
2008.  In accordance with the Term Loan Forbearance and Amendment
Agreement, BNP has permanently waived any defaults or events of default
resulting form the non-compliance with any covenant failures for any date of
determination prior to and including March 31, 2008.  BNP also agreed
to forbear and refrain from (i) accelerating any loans outstanding, (ii)
exercising all rights and remedies, and (iii) taking any enforcement action
under the Term Loan or otherwise as a result of certain potential covenant
defaults during the Standstill Period, provided the Company complies with the
Forbearance Covenants, as applicable to the Term Loan.  As of December
31, 2008, the syndication for the Term Loan has liens on less than 90% of all
the Company’s proved oil and gas properties, and the Company is therefore not in
compliance with a Forbearance Covenant.  On August 15, 2008, the Term
Loan Forbearance and Amendment Agreement expired without extension and therefore
the syndication currently has the ability to exercise any or all of its rights
and remedies under Term Loan.  The Term Loan Forbearance and Amendment
Agreement also increased the interest rate payable from LIBOR-based plus 700
basis points to LIBOR-based plus 950 basis points.  The Term Loan
Forbearance and Amendment Agreement also provided that in no event shall the
LIBOR-based rate be less than 4.0%.  In addition, the Term Loan
Forbearance and Amendment Agreement instituted a payment-in-kind (“PIK”)
arrangement which has resulted in additional liability under the Term Loan
amounting to $0.9 million for the year ended December 31, 2008.


84




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)


On
October 6, 2008, the Company received a notice of default from Laminar with
respect to the second lien term Loan (“the “Term Loan Notice of
Default”).  The Term Loan Notice of Default states that an event of
default occurred under (1) Section 10.01(g) of the second lien term loan due to
the swap termination amount in connection with the Early Termination Notice
exceeding $500,000, (2) Section 10.01(f) of the second lien term loan due to the
Company’s failure to pay the settlement amount of approximately $2.2 million
($0.6 million for natural gas derivatives and $1.6 million for interest rate
derivative) by the due date of October 2, 2008, in connection with the Early
Termination Notice, (3) Sections 8.14, 8.18, and 9.01 of the second lien term
loan and the senior secured  credit facility (cross default) due to
the Company’s failure to comply with certain financial and non-financial
covenants, and (4) Section 10.01(f) and (g) of the Term Loan due to the
Company’s failure to pay the first of three principal borrowing base deficiency
payments in the approximate amount of $6.6 million under Section 10.01(a) of the
senior secured credit facility (cross default).  Laminar and the
syndication under the second lien term loan cannot take any enforcement or
similar actions against the Company or its property for at least 180 days
beginning November 24, 2008 pursuant to the terms of the Intercreditor
Agreement, dated August 20, 2007, between the second lien term loan syndication
and the senior secured credit facility syndication.




The Term
Loan Notice of Default also informed the Company, as of October 1, 2008, that
the interest rate under the second lien term loan shall bear interest at the
default rate thereby increasing the Company’s current interest rate under the
Term Loan by 2% to approximately 15.5%.




Since the
expiration of the Standstill Period, the Company continues to engage in
discussions with Laminar and the syndication to restructure the Company’s
debt.  The Company recognizes that the term loan is due and payable
upon notification from Laminar after the expiration of the 180 days beginning
November 24, 2008, and therefore the entire outstanding balance has been
classified as a current liability on the accompanying December 31, 2008 balance
sheet.  In addition to discussions with Laminar and the syndication,
management is also seeking alternative financing arrangements and opportunities
for asset divestitures.  There is no assurance that management will be
successful in restructuring the Company’s debt, finding alternative financing
arrangements, or selling Company assets in an amount sufficient to remedy the
Company’s loan defaults.




For the
years ended December 31, 2008 and 2007, interest and fees incurred for the
second lien term loan was $6.7 million and $2.2 million,
respectively.  The Company has also incurred deferred financing fees
of $1.3 million with regard to the second lien term loan.  The
deferred financing fees are being amortized on a straight-line basis over the
remaining terms of the second lien term loan obligation.  Amortization
expense for the second lien term loan is estimated to be $0.3 million per year
through 2011.  Amortization expense was $0.3 million and $0.1 million
for the years ended December 31, 2008 and 2007, respectively.  During
2008, the Company also incurred additional financing fees in the amount of $0.3
million in connection with the Term Loan Forbearance and Amendment
Agreement.  The additional financing fees were recorded as an increase
to general and administrative expense.  In addition, the Company
incurred annual agency fees which are recorded to interest
expense.


85




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)


Scheduled
principal maturities of long-term debt for each of the years succeeding December
31, 2008, are summarized as follows ($ in thousands):




Year
                          
                          Amount2009
                          
                          $
                          123,1802010
                          
                          
                          5182011
                          
                          
                          2,4962012
                          
                          
                          282013
                          
                          
                          7Total
                          $
                          126,229





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.




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, and 2006, interest and fees incurred for the
mezzanine credit facility were $3.0 million and $4.7 million,
respectively.  Since this agreement was terminated in 2007, no
interest or fees were incurred during 2008.




NOTE
9.  SHAREHOLDERS’ EQUITY





Common
Stock




2008




In June
2008, 350,000 shares of the Company’s stock were issued in connection with a
stock grant awarded to the Company’s former Chief Financial
Officer.  The original grant was for 500,000 and the Chief Financial
Officer elected to forfeit 150,000 shares in exchange for the Company paying
taxes associated with the stock award in the amount of $90,450.





During
May 2008, the Board of Directors granted a special common stock award under the
2006 Stock Incentive Plan to each of the five non-employee directors totaling
250,000 shares, or 50,000 each, for past services rendered.  In
addition, two of the non-employee directors were granted a special common stock
award of an additional 15,000 shares each for services rendered on special
projects.  Of the 280,000 total shares granted, 100,000 were issued
during July 2008 and 180,000 were issued during August
2008.  Effective October 23, 2008, these awards were rescinded by
agreement of the Company and those directors.





In
January 2008 and April 2008, 500,000 common stock options were exercised in each
month totaling 1,000,000 shares exercised during 2008 by an outside party at an
exercise price of $0.625 per share.  The Company received $0.6 million
in connection with these exercises.


86




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)





In March
2008, 133,332 common stock options were exercised by two Company directors under
the existing stock option plans at an exercise price of $0.375 per
share.  The Company received $50,000 in connection with these
exercises.





In
January 2008, 30,000 common stock options were exercised by a Company employee
under the existing stock option plans at an exercise price of $0.375 per
share.  The Company received $11,250 in connection with this
exercise.





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.





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.


87




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)


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.





Common
Stock Warrants





The
following table provides information related to stock warrant activity for the
years ended December 31 ($ in thousands):





2008
                        
                        
                        2007
                        
                        
                        2006Number of Shares
                          Underlying
                          Warrants
                        
                        
                        Number of Shares
                          Underlying
                          Warrants
                        
                        
                        Number of Shares
                          Underlying
                          WarrantsOutstanding
      at the beginning of the period
                        
                        
                        1,952
                        
                        
                        
                        2,080
                        
                        
                        
                        19,698Granted
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        -Exercised
      under early exercise program
                        
                        
                        -
                        
                        
                        
                        -
                        
                        
                        
                        (13,183
                        )Exercised
                        
                        
                        -
                        
                        
                        
                        (78
                        )
                        
                        
                        (3,590
                        )Forfeitures
      and other adjustments
                        
                        
                        -
                        
                        
                        
                        (50
                        )
                        
                        
                        (845
                        )Outstanding
      at the end of the period
                        
                        
                        1,952
                        
                        
                        
                        1,952
                        
                        
                        
                        2,080





As of
December 31, 2008, these common stock warrants had an average remaining
contractual life of one month and weighted average exercise price per share of
$1.74.  As the lowest exercise price per share is $0.75, the Company
does not expect any of the warrants to be exercised.





NOTE
10.  INCOME TAXES





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





For the Years Ended December 31,
                    
                    2008
                    
                    
                    2007
                    
                    
                    2006Current
      taxes
                    
                    $
                    100
                    
                    
                    $
                    -
                    
                    
                    $
                    184Deferred
      taxes
                    
                    
                    (33,097
                    )
                    
                    
                    (7,875
                    )
                    
                    
                    1,862Less:
      change in valuation allowance
                    
                    
                    33,097
                    
                    
                    
                    7,875
                    
                    
                    
                    (1,862
                    )Net
      income tax expense (benefit)
                    
                    $
                    100
                    
                    
                    $
                    -
                    
                    
                    $
                    184





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,
                      
                      2008
                      
                      
                      2007
                      
                      
                      2006Tax
      at federal statutory income tax rate
                      
                      $
                      (36,504
                      )
                      
                      $
                      (1,504
                      )
                      
                      $
                      (661
                      )State
      income taxes
                      
                      
                      100
                      
                      
                      
                      -
                      
                      
                      
                      184Adjustment
      of estimated income tax provision of prior years (a)
                      
                      
                      3,407
                      
                      
                      
                      (6,371
                      )
                      
                      
                      2,523Change
      in valuation allowance
                      
                      
                      33,097
                      
                      
                      
                      7,875
                      
                      
                      
                      (1,862
                      )Net
      income tax expense (benefit)
                      
                      $
                      100
                      
                      
                      $
                      -
                      
                      
                      $
                      184


88




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)


(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. 2008 adjustment of estimated income
tax provision of prior year is due primarily to the impairment loss recognized
as an expense during 2008 related to goodwill having no tax basis and previously
treated as a permanent difference between book and tax amounts, reduced by
revisions to the tax basis of oil and gas properties which lead to changes in
the net operating loss carryover.





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





2008
                  
                  
                  2007
                  
                  
                  2006Deferred
      tax assets:Net
      operating loss carryover
                  
                  $
                  40,916
                  
                  
                  $
                  28,926
                  
                  
                  $
                  11,661Stock
      options
                  
                  
                  2,177
                  
                  
                  
                  1,612
                  
                  
                  
                  928Section
      1231 carryover
                  
                  
                  -
                  
                  
                  
                  109
                  
                  
                  
                  -Capital
      loss carryover
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  33Contribution
      carryover
                  
                  
                  8
                  
                  
                  
                  -
                  
                  
                  
                  -Less
      valuation allowance
                  
                  
                  (41,502
                  )
                  
                  
                  (8,405
                  )
                  
                  
                  (530
                  )Deferred
      tax assets, net
                  
                  
                  1,599
                  
                  
                  
                  22,242
                  
                  
                  
                  12,092Deferred
      tax liabilities:Excess
      assigned acquisition value
                  
                  
                  -
                  
                  
                  
                  (4,165
                  )
                  
                  
                  (4,339
                  )Intangible
      drilling costs and other
                  
                  
                  (1,599
                  )
                  
                  
                  (18,077
                  )
                  
                  
                  (7,753
                  )Deferred
      tax liabilities, net
                  
                  
                  (1,559
                  )
                  
                  
                  (22,242
                  )
                  
                  
                  (12,092
                  )Net
      deferred tax assets (liabilities)
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  -





The
Company has net operating loss carryforwards available to offset future federal
taxable income of approximately $120.0 million, which expire from 2010 through
2028.  During October 2005, the Company (formerly Cadence) acquired
Aurora Energy, Ltd. (“Aurora”) through the wholly-owned subsidiary with and into
Aurora.  As a result of the merger, Aurora became a wholly owned
subsidiary.  Included in this amount is a pre-merger net operating
loss carryforward incurred by Cadence of approximately $17.0
million.  The valuation allowance increased (decreased) by
approximately $5.8 million, $7.9 million, and $(1.9) million as of December 31,
2008, 2007, and 2006, respectively.  Due to the net operating loss
carryforwards, no federal income tax expense was recorded in 2008, 2007, and
2006.





NOTE
11.  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.


89




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)




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 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, however, the
plan continues to exist, and the Company may decide to use it in the
future.





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 non-employee directors of the
Company and to provide incentives for such persons to exert maximum efforts for
the success of the Company and its affiliates. The maximum term for options
granted is 10 years.





Activity
related to the stock option plans referenced above was as follows (shares in
thousands):





For the Years Ended December 31,
                      
                      2008
                      
                      
                      2007
                      
                      
                      2006Options
      outstanding at beginning of period
                      
                      
                      2,873
                      
                      
                      
                      3,432
                      
                      
                      
                      1,805Options
      granted
                      
                      
                      3,000
                      
                      
                      
                      185
                      
                      
                      
                      2,728Options
      exercised
                      
                      
                      (163
                      )
                      
                      
                      (353
                      )
                      
                      
                      (593
                      )Options
      forfeited and other adjustments
                      
                      
                      (1,533
                      )
                      
                      
                      (391
                      )
                      
                      
                      (508
                      )Options
      outstanding at end of period
                      
                      
                      4,177
                      
                      
                      
                      2,873
                      
                      
                      
                      3,432





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





2008
                        
                        
                        2007
                        
                        
                        2006Risk-free
      interest rate
                        
                        
                        3.68
                        %
                        
                        
                        4.67
                        %
                        
                        
                        4.1
                        %Expected
      years until exercise
                        
                        
                        6.0
                        
                        
                        
                        3.25-6.0
                        
                        
                        
                        2.5-6.0Expected
      stock volatility
                        
                        
                        76.38
                        %
                        
                        
                        71.41
                        %
                        
                        
                        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.  Of the 1,400,000 options and warrants issued,
431,000 shares remain outstanding as of December 31, 2008.


90


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, 2008, 2007, and 2006 (shares in thousands):





2008
                    
                    
                    2007
                    
                    
                    2006Shares
                    
                    
                    Weighted
                      Average
                      Exercise
                      Price
                    
                    
                    Shares
                    
                    
                    Weighted
                      Average
                      Exercise
                      Price
                    
                    
                    Shares
                    
                    
                    Weighted
                      Average
                      Exercise
                      PriceOptions
      outstanding at the beginning of period
                    
                    
                    4,304
                    
                    
                    $
                    2.25
                    
                    
                    
                    4,863
                    
                    
                    $
                    2.23
                    
                    
                    
                    6,448
                    
                    
                    $
                    0.72Options
      granted
                    
                    
                    3,000
                    
                    
                    
                    0.75
                    
                    
                    
                    185
                    
                    
                    
                    3.35
                    
                    
                    
                    2,728
                    
                    
                    
                    3.89Options
      exercised
                    
                    
                    (1,163
                    )
                    
                    
                    0.59
                    
                    
                    
                    (353
                    )
                    
                    
                    0.56
                    
                    
                    
                    (3,801
                    )
                    
                    
                    0.67Forfeitures
      and other adjustments
                    
                    
                    (1,533
                    )
                    
                    
                    1.37
                    
                    
                    
                    (391
                    )
                    
                    
                    4.10
                    
                    
                    
                    (512
                    )
                    
                    
                    3.65Options
      outstanding at end of period
                    
                    
                    4,608
                    
                    
                    
                    1.99
                    
                    
                    
                    4,304
                    
                    
                    $
                    2.25
                    
                    
                    
                    4,863
                    
                    
                    $
                    2.23Exercisable
      at end of period
                    
                    
                    2,582
                    
                    
                    $
                    2.62
                    
                    
                    
                    2,941
                    
                    
                    $
                    1.56
                    
                    
                    
                    2,776
                    
                    
                    $
                    1.01Weighted
      average fair value of options granted during the period
                    
                    $
                    0.52
                    
                    
                    
                    
                    
                    
                    $
                    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.  Since the exercise price of all stock options is greater than
the current market value, no intrinsic value exists for options outstanding at
December 31, 2008.





The
weighted average remaining life by exercise price as of December 31, 2008, is
summarized below (shares in thousands):





Range of
                    Exercise Prices
                  
                  Outstanding
                    Shares
                  
                  
                  Weighted Average
                    Life
                  
                  
                  Exercisable
                    Shares
                  
                  
                  Weighted Average
                    Life$0.38
      - $0.63
                  
                  
                  733
                  
                  
                  
                  2.2
                  
                  
                  
                  733
                  
                  
                  
                  2.2$0.75
                  
                  
                  1,750
                  
                  
                  
                  9.4
                  
                  
                  
                  -
                  
                  
                  
                  -$1.75
      - $2.55
                  
                  
                  385
                  
                  
                  
                  4.1
                  
                  
                  
                  363
                  
                  
                  
                  3.9$2.90
      - $3.62
                  
                  
                  1,308
                  
                  
                  
                  2.0
                  
                  
                  
                  1,151
                  
                  
                  
                  2.0$4.45
      - $4.70
                  
                  
                  432
                  
                  
                  
                  5.1
                  
                  
                  
                  335
                  
                  
                  
                  5.0$0.38
      - $4.70
                  
                  
                  4,608
                  
                  
                  
                  5.3
                  
                  
                  
                  2,582
                  
                  
                  
                  2.7





NOTE
12.  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.  Management believes that the Company is in substantial
compliance with all currently applicable environmental laws and
regulations.





In 2007,
the State of Michigan, Department of Environmental Quality (“DEQ”) instituted a
water sampling and monitoring requirement for wells north of a line of
demarcation that includes most of the Company’s Antrim projects.  The
drilling permits for new wells in this area 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, the Company may be required to shut-in the
well.  If such wells cannot be remediated so that fresh water is no
longer produced, the Company may be required to plug such
wells.


91


AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


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, management 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 the
Company plug six wells, plug or remediate an additional 15 wells, and collect
water samples from the remaining wells that had not been previously
sampled.  Management agreed to plug five of the six wells requested
and collected a new round of water samples from each requested well for
additional analysis.





In
September 2008, the Company received a notice of violation from the DEQ
requesting a proposal from management to plug 25 wells in the Arrowhead and Blue
Chip projects.  Five of the wells listed on this notice had been
agreed to during the January 31, 2008 meeting and were plugged during
2008.  In December 2008, management met again with the DEQ to discuss
the remaining wells.  Management agreed to shut-in three additional
wells bringing total shut-in wells to 13, and continue to provide water samples
for the remaining wells for further analysis.  Management is expected
to meet again with the DEQ in March 2009 to discuss the
results.  There is no assurance that the Company will not be required
to plug the remaining wells in the Arrowhead project.  If the Company
is required to plug the remaining wells, operations are not expected to be
materially impacted as most of these wells are uneconomic and plugging costs are
estimated to be $12,000 per well.





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, 2008,
letters of credit in the amount of $0.8 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 required the Company to record approximately $2.1 million in
stock-based compensation expense over the contract period.  The
Company paid Mr. Huff the compensation provided for in the employment agreement
through June 18, 2008.  This agreement was 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.  As a result of the
acceleration, $0.5 million was recorded as stock-based compensation during the
year ended December 31, 2008.


92




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)




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.  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 services of
Johnson Rice & Company, L.L.C. were concluded on March 7,
2008.  For the year ended December 31, 2008, the Company paid $0.3
million for retention bonuses.





Letter
of Intent





On
January 10, 2008, the Company signed a non-binding Letter of Intent to acquire
Acadian Energy, LLC (“Acadian”).  John E. McDevitt (former President
and Chief Operating Officer, through a controlled entity) and Gilbert A. Smith
(current President) are the only members of Acadian (60% and 40%,
respectively).  The Letter of Intent was terminated on October 1,
2008, and as a result Acadian acquisition costs initially capitalized in the
amount of $0.2 million were recorded as a general and administrative expense as
of December 31, 2008.  In addition, all amounts paid on behalf of
Acadian by the Company pursuant to the operating agreements more fully described
in Note 13 “Related Party Transactions” have been repaid to the Company with the
exception of $21,899 which has been recorded as a receivable at December 31,
2008.





Oak
Tree Joint Venture





In March
2006, the Company entered into a Joint Venture Agreement covering the
acquisition and development of oil and gas leases in an Area of Mutual Interest
(“AMI”) in Oklahoma.  The Company’s joint venture partner is the
manager of the leasing program and is designated as Operator for the
AMI.  In March 2008, the Company’s joint venture partner filed a
complaint alleging breach of contract and unjust enrichment, seeking a
declaratory judgment to terminate the Joint Venture Agreement and to rescind the
assignment of leases to the Company’s subsidiary, AOK Energy, LLC.  As
a result of the Company’s Purchase and Sale Agreement more fully described in
Note 13 “Related Party Transactions,” on September 23, 2008, the joint venture
partner dismissed all claims associated with this complaint.





General
Legal Matters





The
Company is currently involved in various disputes incidental to its business
operations.  Management, after consultation with legal counsel, is of
the opinion that the final resolution of all currently pending or threatened
litigation is not likely to have a material adverse effect on our consolidated
financial position results of operations, or cash flows.





South
Knox Loss





The
Company operates various wells located in the South Knox
project.  During August 2008, the facility located in the South Knox
project experienced a fire which incurred approximately $0.4 million in
damages.  Insurance claims have been submitted for the entire $0.4
million.  The Company has a $25,000 deductible and has received full
reimbursement of the amount of damages net of the deductible with the exception
of $18,000.  The Company anticipates receipt of the outstanding
$18,000 in 2009.





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.  Effective June 26, 2008, Fifth Third
Bank sold one of the compressors and released the Company of its obligation for
this compressor.  As a result of the sale and release, the monthly
rental fee was adjusted to $8,713.  For the year ended December 31,
2008, total rental expense incurred by the Company under this lease was $0.1
million.


93




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)





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,
2008, the long-term portion of the deferred gain is shown on the Company’s
Balance Sheet as “Other long-term liabilities” in the amount of $0.4 million and
as “Accounts payable and accrued liabilities” for the short-term portion of $0.1
million.  For the year ended December 31, 2008, total rental expense
incurred by the Company under this lease was $0.4 million.





The
minimum lease payments required by both leases are as follows ($ in
thousands):





Year
                    
                    
                    Amount2009
                    
                    
                    $
                    5502010
                    
                    
                    
                    5502011
                    
                    
                    
                    5502012
                    
                    
                    
                    5502013
                    
                    
                    
                    105Thereafter
                    
                    
                    
                    52$
                    2,357




NOTE
13.  RELATED PARTY TRANSACTIONS




Presidium Energy,
LC





AOK
Energy LLC Purchase and Sale Agreement





In March
2006, the Company entered into a joint venture agreement with certain unrelated
parties.  The joint venture covered the acquisition and development of
oil and gas leases in various counties located in Oklahoma.  The joint
venture project was known as the “Oak Tree Project.”  The Company
participated in the joint venture through a wholly owned subsidiary, AOK Energy,
LLC (“AOK”).  Effective March 28, 2008, the Company entered into an
Agreement for the Purchase and Sale of Limited Liability Company Memberships
with Presidium, which is wholly owned and operated by John V. Miller, who served
as the Company’s Vice President from November 1, 2005, until he resigned on
February 29, 2008.  Under the terms of the agreement, the Company
would sell to Presidium all of the outstanding member interests in AOK for a
purchase price that included the payment by Presidium of certain liabilities
that the operator alleged were owed by the Company to other participants in the
joint venture, a cash payment to the Company in the amount of $10,500,000, and
an assignment to the Company of a 3% overriding royalty in certain leases in the
Oak Tree Project.





Effective
July 21, 2008, the Company amended the Purchase and Sale of Limited Liability
Company Memberships with Presidium (the “First Amendment”) to extend Presidium’s
exclusive right to purchase all of the outstanding member interests in AOK until
September 15, 2008.  In exchange for the extension, Presidium made a
$2.0 million non-refundable payment to the Company.





Effective
on September 12, 2008, the Company amended the Purchase and Sale of Limited
Liability Company Memberships with Presidium (the “Second Amendment”) increasing
the purchase price to $15,000,000.  The Second Amendment also required
Presidium to pay another $1,000,000 in cash and execute a promissory note in the
amount of $12,000,000 (“Promissory Note”).  In order to induce the
Company to enter into the Second Amendment, Mr. Miller granted the Company an
option to buy up to one million membership units in Presidium for the sum of
$0.50 per unit during the period from six months to five years after
closing.  If the Promissory Note is repaid in full within the first
six months after closing, the Company’s option to purchase units in Presidium is
null and void.  The sale of the membership interest closed effective
September 15, 2008.


94




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)





Under the
terms of the Promissory Note, Presidium is required to make monthly interest
only payments calculated at the lesser of the maximum rate allowed by law or
9.0%. As security for repayment of the Promissory Note, Presidium granted a
first priority security interest in all of AOK interests and delivered mortgages
on all oil and gas leases Presidium holds or will acquire in the Oak Tree
Project.  In the event Presidium plans to drill a well in the Oak Tree
Project, a principal payment on the Promissory Note equal to the amount of $400
per net acre of leases to be included in the drilling unit must be submitted to
the Company in order for the Company to subordinate any mortgages held on leases
that fall within the drilling unit.  Presidium shall be entitled to
have outstanding mortgage subordinations for no more than five undrilled well
sites at any one time.  The entire outstanding principal balance along
with all accrued interest is due September 10, 2010.  For the year
ended December 31, 2008, the Company recorded $0.3 million of interest income
related to the Promissory Note.





Consulting
Agreement and Other





Effective
May 20, 2008, the Company entered into a consulting agreement with Presidium in
which the Company agreed to provide Presidium services in connection with
certain oil and gas leasing, exploration, development, and business
projects.  This agreement expired December 31, 2008.  For
the year ended December 31, 2008, the Company billed Presidium $0.1 million for
services rendered.





In the
normal course of business the Company engages in certain operational
transactions with Presidium.  For the year ended December 31, 2008,
the Company sold inventory to Presidium in the amount of $0.1 million and billed
Presidium for lease bonus extensions in the amount of $0.1 million.





Acadian
Energy, LLC





Operating
Agreements





Subsequent
to the Company executing a Letter of Intent with Acadian as more fully described
in Note 12 “Commitment and Contingencies”, on June 24, 2008, the Company entered
into an agreement with Acadian to provide funding to maintain and preserve the
value of Acadian’s properties located in the State of Indiana pending the
Company’s acquisition of Acadian. The Company agreed to advance approximately
$83,000 pursuant to an authority for expenditure to be used for the purpose of
bringing wells into compliance with the requirements of the State of Indiana and
if practical, into production.  The Company also agreed to pay certain
legal expenses on behalf of Acadian in connection with the proposed acquisition
of Acadian.  The agreement also stated if the Company did not acquire
Acadian or its assets by October 1, 2008, Acadian would be required to reimburse
the Company for the entire amount advanced no later than October 1,
2009.





Effective
April 1, 2008, the Company entered into an agreement with Acadian to provide oil
and gas operating services on properties located in the State of
Indiana.  This agreement expired December 31, 2008. Under the terms of
the agreement, the Company was not entitled to monetary
consideration.  Services were performed to maintain the value of the
properties prior to transfer of ownership from Acadian to the
Company.


95




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)




For the
year ended December 31, 2008, the Company incurred expenses in the amount of
$0.1 million under the operating agreements with Acadian.  Due to the
termination of the Letter of Intent agreement with Acadian more fully described
in Note 12 “Commitments and Contingencies”, amounts incurred on behalf of
Acadian in the amount of $0.1 million were reimbursed at December 31, 2008 with
the exception of $21,899 which has been recorded as a receivable at December 31,
2008.





Simple
Financial Solutions, Inc.





Consulting
Agreements





Effective
January 22, 2008, Barbara E. Lawson was named Chief Financial Officer of the
Company.  Simple Financial Solutions, Inc., which is owned and
operated by Ms. Lawson’s spouse, provides consulting services on a continuous
basis to the Company including Bach Services and Manufacturing Co., LLC, a
Company subsidiary.  For the year ended December 31, 2008, Simple
Financial Solutions, Inc. billed the Company $0.1 million for services
rendered.





Effective
May 1, 2008, the Company entered into a month-to-month agreement with Simple
Financial Solutions, Inc. to provide professional services for a subsidiary of
the Company, Hudson Pipeline & Processing CO., LLC (“HPPC”).  On a
monthly basis, Simple Financial Solutions, Inc. will be paid 2% of the gross
revenues of HPPC and 3.5% of the net income to HPPC before
compensation.  Certain revenue resulting from gas transportation will
be excluded from the calculations.  For the year ended December 31,
2008, the Company paid $0.1 million for services received from Simple Financial
Solutions, Inc. pursuant to this HPPC agreement.





Disposition of Membership
Interest





Effective
June 28, 2008, Lawson & Kidd, LLC purchased a 2.5% membership interest in
HPPC for $0.1 million.  Lawson & Kidd, LLC is solely owned by
Barbara E. Lawson who is the Company’s Chief Financial Officer and Ms. Lawson’s
spouse.  Lawson & Kidd, LLC’s interest will increase to 5% upon
HPPC receiving income equal to 125% of total costs spent on construction of the
pipelines owned and operated by HPPC.  For the year ended December 31,
2008, the Company received $0.1 million in capital call contributions from
Lawson & Kidd, LLC and paid Lawson & Kidd, LLC total distributions in
the amount of $20,002.  As more fully described in Note 17 “Subsequent
Events,” the Company repurchased the 2.5% membership interest in HPPC from
Lawson & Kidd, LLC during March 2009.





Other





Consulting
Agreements





Effective
August 15, 2008, the Company entered into a consulting agreement with Richard M.
Deneau to provide advice and services at an hourly rate of $125 (not to exceed
$1,000 per day) in connection with management’s negotiations with the Company’s
existing bankers and the creation and maintenance of new banking
relationships.  Mr. Deneau is the brother of the Company’s Chief
Executive Officer and has served as an affiliated director of the Company since
2005.  For the year ended December 31, 2008, the Company paid $45,500
for consulting services received from Mr. Deneau.




96


AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


Working
Interest in Certain Projects


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, 2008, there is no
production associated with this working interest, and development costs were
approximately $13.3 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 (which has since
merged into the Company) 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 three wells permitted for the Red Run project and one well was temporarily
abandoned.





NOTE
14.  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, 2008, 2007, and 2006, the Company contributed
$53,148, $66,211, and $42,350, respectively, as a discretionary matching
contribution.  Of the $53,148 discretionary matching contribution for
2008, $10,478 is attributable to forfeitures and $42,670 is attributable to cash
contributions by the Company.  No forfeitures occurred during 2007 or
2006.





NOTE
15.  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.


97


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 an 89 bcfe increase in
proved reserves associated with the full cost pool. This change in estimate from
proven developed reserves to proven reserves as well as an updated reserve
report resulted in a reduction of $2.7 million in oil and natural gas
depreciation, depletion and amortization.





NOTE
16.  SELECTED QUARTERLY DATA (Unaudited)





The
following table shows financial data for 2008, 2007, and 2006 ($ in thousands
except for share data):





Quarter EndedMarch 31
                          
                          
                          June 30
                          
                          
                          September 30
                          
                          
                          December 312008Operating
      revenues(a)
                          
                          $
                          6,790
                          
                          
                          $
                          7,719
                          
                          
                          $
                          9,154
                          
                          
                          $
                          5,301Operating
      income(b)
                          
                          $
                          1,458
                          
                          
                          $
                          2,120
                          
                          
                          $
                          2,293
                          
                          
                          $
                          (351
                          )Net
      (loss) income
                          
                          $
                          (1,181
                          )
                          
                          $
                          (703
                          )
                          
                          $
                          (16,695
                          )
                          
                          $
                          (88,785
                          )Basic
      net earnings per share
                          
                          
                          (0.01
                          )
                          
                          
                          (0.01
                          )
                          
                          
                          (0.16
                          )
                          
                          
                          (0.86
                          )Diluted
      net earnings per share
                          
                          
                          (0.01
                          )
                          
                          
                          (0.01
                          )
                          
                          
                          (0.16
                          )
                          
                          
                          (0.86
                          )2007Operating
      revenues(a)
                          
                          $
                          6,248
                          
                          
                          $
                          6,820
                          
                          
                          $
                          7,205
                          
                          
                          $
                          7,633Operating
      income(b)
                          
                          $
                          1,531
                          
                          
                          $
                          2,232
                          
                          
                          $
                          2,876
                          
                          
                          $
                          2,672Net
      (loss) income
                          
                          $
                          (740
                          )
                          
                          $
                          229
                          
                          
                          $
                          (3,254
                          )
                          
                          $
                          (657
                          )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
                          )2006Operating
      revenues(a)
                          
                          $
                          5,529
                          
                          
                          $
                          (5,655
                          )
                          
                          $
                          5,313
                          
                          
                          $
                          5,710Operating
      income(b)
                          
                          $
                          2,024
                          
                          
                          $
                          2,362
                          
                          
                          $
                          1,613
                          
                          
                          $
                          1,476Net
      (loss) income
                          
                          $
                          (939
                          )
                          
                          $
                          (1,185
                          )
                          
                          $
                          (2,086
                          )
                          
                          $
                          2,091Basic
      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
      oil and natural gas sales, pipeline transportation and processing, and
      field services and sales.





(b)
            Includes
      production taxes, production and processing operating expenses, field
      services expenses, and general and administrative
  expenses.


98




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Continued)





NOTE
17.  SUBSEQUENT EVENTS




On
February 12, 2009, the Company and certain subsidiaries, as guarantors, entered
into a forbearance agreement to the senior secured credit facility (the “Second
Forbearance Agreement”) with BNP Paribas (“BNP” or the “Administrative Agent”)
and the syndication.  In accordance with the Second Forbearance
Agreement, during the period from December 31, 2008 until April 30, 2009 (the
“Second Forbearance Period”), BNP will forbear and refrain from (i) accelerating
any loans outstanding and (ii) taking any other enforcement action under the
senior secured credit facility at law or otherwise as a result of designated
defaults or potential defaults, provided the Company complies with the
forbearance covenants (collectively, the “Second Forbearance
Covenants”).





A summary
of the Second Forbearance Covenants is as follows: (i) the Company shall retain
and employ a financial advisor, (ii) the Company shall deliver to the
Administrative Agent an initial detailed budget on or before February 20, 2009,
and provide subsequent monthly updates, (iii) the Company shall deliver to the
Administrative Agent prior week aggregated cash balances on or before the last
business day of the current week, (iv) no later than February 23, 2009, the
Company will execute (or cause to be executed) additional mortgages and no later
than February 18, 2009, the Company will execute  (or cause to be
executed) other security instruments such that, after giving effect to such
additional mortgages and other security instruments, the syndication will have
liens on 100% of all oil and gas properties, promissory notes, all significant
overriding royalties, and all significant farmout agreements prior to such date,
(v) the Company must obtain prior written approval of the Administrative Agent
to farmout any assets or sell any assets for more than $200,000; (vi) the
Company shall provide the Administrative Agent notice of any unwritten or
written expressions of interest with respect to the purchase of assets of the
Company or any of its subsidiaries for an amount in excess of $2.0 million,
(vii) the Company and its financial advisor shall participate in weekly
conference calls with the Administrative Agent and the syndication during which
a financial officer of the Company must provide updates on restructuring, sale
prospects, and cost reduction efforts, (viii) the Company must deliver to the
Administrative Agent copies of any detailed audit reports, management letters,
or recommendations submitted to the board of directors, (ix) no later than
February 28, 2009, the Company must deliver a restructuring plan to resolve the
borrowing base deficiency, (x) the Company must maintain a liquidity position of
at least $4.0 million during Second Forbearance Period, and (xi) no later than
February 23, 2009, the Company must obtain the consent of the second lien term
loan syndication for the Company to defer until no earlier than the termination
of the Second Forbearance Period, payment of the scheduled interest payment
currently payable to the second lien term loan syndication on February 24,
2009.





The
Company’s failure to comply with the Second Forbearance Covenants will terminate
the Second Forbearance Agreement and allow the syndication to exercise any or
all of their rights and remedies purportedly provided to them under the senior
secured credit facility.





On
February 18, 2009, the Company executed the mortgages, security agreement and
pledge agreements necessary to provide the senior secured credit facility
lenders a first secured lien on substantially all of the Company’s oil and gas
properties not previously pledged to them. The Company has also complied with
the other Second Forbearance Covenants, except that the Company has not obtained
the consent of the second lien lenders to defer payment of the $1.6 million
interest payment scheduled to be paid by the Company on the second lien term
loan on February 24, 2009.  The Company has received correspondence
from BNP dated February 27, 2009 indicating that the first lien lenders agree
not to declare a forbearance termination event as a result of the Company’s
failure to obtain the consent of the second lien lenders to defer payment of the
interest scheduled to be paid on February 24, 2009, as long as the Company does
not actually make the interest payment during the Second Forbearance
Period.  The Company has recorded the $1.6 million interest payment
owed to the second lien lenders as a liability included with the second lien
term loan obligation.  As more fully described above, Laminar and the
second lien term loan syndication cannot take any enforcement or similar actions
against the company’s property for at least 180 days beginning November 24,
2008.


99


AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Continued)


During
March 2009, the Company repurchased a 2.5% membership interest in HPPC from
Lawson & Kidd, LLC for $0.1 million and is pursuing the repurchase of the
remaining outside interest in HPPC.


100


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
retained the service of an independent petroleum consultant, Data &
Consulting Services, Division of Schlumberger Technology Corporation
(“Schlumberger”), to estimate its proved natural gas reserves at December 31,
2008, 2007, and 2006.  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 which were estimated by Netherland,
Sewell & Associates, Inc.





The
Company emphasizes that reserve estimates are inherently imprecise and strictly
technical judgments.  The accuracy of any reserve estimate is a
function of the quality of data available and of the engineering and geological
interpretations.  The reserve estimates presented below are believed
reasonable, however, they are estimates only and should be accepted with the
understanding that reservoir performance subsequent to the date of the estimate
may justify their revision as future information becomes
available.  Accordingly, these estimates are expected to change and
such changes could be material and occur in the near term as future information
becomes available.





Reserves
were assigned to the proved developed producing, proved non-producing, and
proved undeveloped reserve categories.  Oil and gas reserves by
definition fall into one of the following categories:  proved,
probable, and possible.  The proved category is further divided into
developed and undeveloped.  The developed reserve category is even
further divided into the appropriate reserve status subcategories of producing
and non-producing.  The reserves and income attributable to the
various reserve categories below have not been adjusted to reflect the varying
degrees of risk associated with them.





A
majority of the undeveloped properties in the proved category are within fields
containing complete infrastructure (including a central production facility and
gathering system), an existing gas market and a demonstrated history of
production and sales.  All estimates of capital expenditures were
supplied by the Company.  A formal inspection of the Company’s
financial status was not made by Schlumberger and Schlumberger assumes that the
Company’s capital expenditures will proceed as planned.  The Company’s
capital expenditures are dependent on restructuring its current debt or securing
alternative financing arrangements.  There can be no assurance that
the Company will be able to restructure its current debt or secure alternative
financing arrangements.


101




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 a summary of changes in estimated reserves for 2008,
2007 and 2006:





Estimates of Proved Reserves
                
                Oil
                  (mbbl)
                
                
                Natural Gas
                  (mmcf)
                
                
                Total
                  (mmcfe)Proved
      reserves as of December 31, 2005
                
                
                99
                
                
                
                63,322
                
                
                
                63,916Revisions
      of previous estimates
                
                
                (40
                )
                
                
                4,880
                
                
                
                4,640Purchases
      of minerals in place
                
                
                -
                
                
                
                22,843
                
                
                
                22,843Extensions
      and discoveries
                
                
                45
                
                
                
                65,095
                
                
                
                65,365Production(a)
                
                
                (23
                )
                
                
                (2,511
                )
                
                
                (2,649
                )Sales
      of minerals in place
                
                
                -
                
                
                
                (665
                )
                
                
                (665
                )Proved
      reserves as of December 31, 2006
                
                
                81
                
                
                
                152,964
                
                
                
                153,450Revisions
      of previous estimates
                
                
                20
                
                
                
                (34,651
                )
                
                
                (34,531
                )Purchases
      of minerals in place
                
                
                -
                
                
                
                2,943
                
                
                
                2,943Extensions
      and discoveries
                
                
                131
                
                
                
                47,256
                
                
                
                48,042Production(a)
                
                
                (28
                )
                
                
                (3,034
                )
                
                
                (3,202
                )Sales
      of minerals in place
                
                
                (16
                )
                
                
                (11
                )
                
                
                (107
                )Proved
      reserves as of December 31, 2007
                
                
                188
                
                
                
                165,467
                
                
                
                166,595Revisions
      of previous estimates
                
                
                (74
                )
                
                
                (67,843
                )
                
                
                (68,287
                )Purchases
      of minerals in place
                
                
                -
                
                
                
                -
                
                
                
                -Extensions
      and discoveries
                
                
                26
                
                
                
                2,630
                
                
                
                2,786Production
                
                
                (25
                )
                
                
                (2,894
                )
                
                
                (3,044
                )Sales
      of minerals in place
                
                
                -
                
                
                
                -
                
                
                
                -Proved
      reserves as of December 31, 2008
                
                
                115
                
                
                
                97,360
                
                
                
                98,050Proved
      developed reserves:December
      31, 2006
                
                
                54
                
                
                
                82,580
                
                
                
                82,904December
      31, 2007
                
                
                74
                
                
                
                100,887
                
                
                
                101,331December
      31, 2008
                
                
                73
                
                
                
                54,830
                
                
                
                55,268





(a)   Production
for both 2007 and 2006 does not reflect 5 mcfe and 4 mcfe, respectively, of
production the Company received in association with certain non-operated wells
excluded in the year end reserve report.


102


AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 SUPPLEMENTAL
INFORMATION ON OIL AND NATURAL
 GAS
EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
 (Unaudited-continued)


During
2008, the Company recorded upward revisions of 1.0 bcfe from our New Albany
properties and downward revisions to certain Antrim properties of 69.3 bcfe to
the December 31, 2007 estimates of our reserves.  The downward
revision to certain Antrim properties was due to the following
developments:





·
            Reserves
      were reduced by 3.0 bcfe due to production during the
  year.


·
            A
      reduction in natural gas prices (from an average of $7.18 per mcf on
      December 31, 2007, to an average of $6.07 per mcf on December 31, 2008)
      has caused a reduction in the volume of natural gas that can be
      economically produced.  The Company attributes approximately 7.9
      bcfe of the reduction in Antrim shale proved reserves to be attributable
      to lower natural gas prices.


·
            As
      a result of changes in regulatory criteria, the Michigan Department of
      Environmental Quality (“DEQ”) forced the Company to plug 5 wells and shut
      in 13 wells during 2008 due to water quality issues, resulting in a
      setback in the Company’s efforts to dewater the Antrim shale in the
      Arrowhead project.  Furthermore, the DEQ blocked the Company’s
      efforts to drill additional wells needed for dewatering.  With
      no means to effectively dewater the project area, performance of the
      existing wells resulted in net reserve reduction of 7.1 bcfe on the three
      producing units in the
project.


·
            Due
      to the DEQ issues cited above, the absence of available capital needed to
      install infrastructure for existing wells and drill additional wells, and
      lack of performance of wells in the Arrowhead project, the proved reserves
      associated with the Blue Lakes Unit, Tomahawk 26 Unit, Tomahawk 27 Unit
      and Tomahawk 35 Unit were eliminated, resulting in a reduction of 12.8
      bcfe.


·
            The
      Company’s Antrim shale proved reserves have historically been determined
      by the Company’s third party reserve engineers using type curves derived
      from a combination of reservoir simulation and production performance from
      nearby more mature Antrim shale units operated by others.  At
      the end of 2007, the type curves were modified to conform to our
      historical production history to date, but the Company had an insufficient
      amount of production on our working interest units to significantly alter
      the type curves.  Now that the Company has sufficient data to
      develop decline curves for its wells, the Company’s engineers have based
      their projections of future production volumes on actual historical data
      from the Company’s own wells instead of representative data from other
      wells in the Antrim play.  Not only did this affect the proved
      developed producing reserves, but the type curves for proved undeveloped
      reserves were modified accordingly.  This resulted in type
      curves projecting lower reserves, and certain future drilling locations
      with proved undeveloped reserves were eliminated due to unacceptable
      economics. The Company estimates that approximately 41.3 bcfe of the
      reduction in Antrim shale proved reserves is attributable to this
      change.


·
            The
      Company added 2.8 bcfe in extensions to proved reserves due to drilling
      activities in various areas.





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.


103




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


SUPPLEMENTAL
INFORMATION ON OIL AND NATURAL


GAS
EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES


(Unaudited-continued)


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.





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.


104




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


SUPPLEMENTAL
INFORMATION ON OIL AND NATURAL


GAS
EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES


(Unaudited-continued)


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  standardized measure prescribed
in SFAS 69:





Year Ended December 31,
                
                2008
                
                
                2007
                
                
                2006Future
      gross revenues
                
                $
                594,586,340
                
                
                $
                1,204,891,690
                
                
                $
                884,186,810Future
      production costs
                
                
                (329,939,650
                )
                
                
                (556,123,590
                )
                
                
                (378,345,360
                )Future
      development costs
                
                
                (25,979,520
                )
                
                
                (42,298,790
                )
                
                
                (37,324,420
                )Future
      income tax expense
                
                
                (334,173
                )
                
                
                (102,354,760
                )
                
                
                (83,566,133
                )Future
      net cash flows after income taxes
                
                
                238,332,997
                
                
                
                504,114,550
                
                
                $
                384,950,897Discount
      at 10% per annum
                
                
                (169,762,231
                )
                
                
                (328,571,410
                )
                
                
                (254,489,076
                )Standardized
      measure of discounted future net cash flows relating to proved oil and
      natural gas reserves
                
                $
                68,570,766
                
                
                $
                175,543,140
                
                
                $
                130,461,821





The
standardized measure of discounted future net cash flows (discounted at 10%)
from production of proved reserves was developed as follows:





1.
            An
      estimate was made of the quantity of proved reserves and the future
      periods in which they are expected to be produced based on year-end
      economic conditions.





2.
            In
      accordance with SEC guidelines, the engineers’ estimates of future net
      revenues from our proved properties and the present value thereof are made
      using oil and gas sales prices in effect at December 31 of the year
      presented and are held constant throughout the life of the
      properties.  The overall average year-end sales prices used in
      the reserve reports were supplied to Schlumberger by the Company as of
      December 31, 2008, 2007, and 2006 are summarized as
    follows:





As of December 31,
                    
                    2008
                    
                    
                    2007
                    
                    
                    2006Natural
      gas (per mmbtu)
                    
                    $
                    6.07
                    
                    
                    $
                    7.18
                    
                    
                    $
                    5.84Oil
      (per barrel)
                    
                    $
                    41.30
                    
                    
                    $
                    90.18
                    
                    
                    $
                    57.81





3.
            The
      future gross revenue streams were reduced by estimated future operating
      costs (including production and severance taxes) and future development
      and abandonment costs, all of which were based on current costs in effect
      at December 31 of the year presented and held constant throughout the life
      of the prosperities.





4.
            Future
      income taxes were calculated by applying the statutory federal and state
      income tax rate to pre-tax future net cash flows, net of the tax basis of
      the properties involved and utilization of available tax carryforwards
      related to oil and gas
operations.


105


AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES
 SUPPLEMENTAL
INFORMATION ON OIL AND NATURAL
 GAS
EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
 (Unaudited-continued)


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,
                
                2008
                
                
                2007
                
                
                2006Beginning
      balance
                
                $
                175,543,140
                
                
                $
                130,461,821
                
                
                $
                152,868,240Revisions
      to reserves proved in prior years:Net
      change in prices and production costs(a)
                
                
                (32,722,722
                )
                
                
                28,130,498
                
                
                
                (113,774,170
                )Net
      changes in future development costs
                
                
                569,101
                
                
                
                (5,261,045
                )
                
                
                (802,360
                )Net
      changes due to revisions in quantity estimates(b)
                
                
                (96,743,063
                )
                
                
                (42,260,444
                )
                
                
                3,484,229Net
      change in accretion of discount(c)
                
                
                18,993,578
                
                
                
                15,878,281
                
                
                
                19,950,751Other(d)
                
                
                (2,050,639
                )
                
                
                4,469,457
                
                
                
                (15,976,530
                )Total
      revisions to reserves provided in prior years
                
                
                (111,953,745
                )
                
                
                956,747
                
                
                
                (107,118,080
                )New
      discoveries and extensions, net of future development and production
      costs
                
                
                2,794,056
                
                
                
                65,772,000
                
                
                
                62,343,872Purchases
      of minerals in place
                
                
                -
                
                
                
                4,371,832
                
                
                
                23,605,950Sales
      of oil and gas properties
                
                
                -
                
                
                
                (1,023,701
                )
                
                
                (4,756,826
                )Sales
      of oil and natural gas produced, net of production costs
                
                
                (13,867,399
                )
                
                
                (16,839,303
                )
                
                
                (14,436,361
                )Previously
      estimated development costs incurred
                
                
                1,689,808
                
                
                
                5,772,092
                
                
                
                -Net
      change in income taxes
                
                
                14,364,906
                
                
                
                (13,928,348
                )
                
                
                17,955,026Net
      change in standardized measure of discounted cash flows
                
                
                (106,972,374
                )
                
                
                45,081,319
                
                
                
                (22,406,419
                )Ending
      balance
                
                $
                68,570,766
                
                
                $
                175,543,140
                
                
                $
                130,461,821





(a) “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 2006, 2007 and 2008. 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
                      Cost2008
                    
                    $
                    6.07
                    
                    
                    $
                    (1.11
                    )
                    
                    $
                    2.70
                    
                    
                    $
                    (0.64
                    )2007
                    
                    $
                    7.18
                    
                    
                    $
                    1.34
                    
                    
                    $
                    3.34
                    
                    
                    $
                    0.872006
                    
                    $
                    5.84
                    
                    
                    $
                    (4.05
                    )
                    
                    $
                    2.47
                    
                    
                    $
                    (0.39
                    )2005
                    
                    $
                    9.89
                    
                    
                    
                    -
                    
                    
                    $
                    2.86
                    
                    
                    
                    -


106




AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


SUPPLEMENTAL
INFORMATION ON OIL AND NATURAL


GAS
EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES


(Unaudited-continued)


(b)
“Revisions in quantity estimates” – The quantity estimates varied significantly
between 2006, 2007 and 2008.  The significant reduction reflected in
2008 resulted when a reduction of year end prices were applied to the downward
adjustments of 63 bcfe to the 12/31/2007, reserves for certain Antrim
properties, then discounted back to present value.  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.





(c)
“Accretion of the discount” – In 2006, 2007, and 2008, this line
item  was computed using the industry-recognized method as a
computation of the 10% of the pre-tax present value of the prior year reserve
report.





(d)
“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 2006, 2007, and 2008.





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,
                
                2008
                
                
                2007
                
                
                2006Proved
      properties
                
                $
                88,380,779
                
                
                $
                162,724,004
                
                
                $
                128,381,121Unproved
      properties
                
                
                47,855,625
                
                
                
                56,937,683
                
                
                
                43,718,594Total
      oil and natural gas properties
                
                
                136,236,404
                
                
                
                219,661,687
                
                
                
                172,099,715Less
      accumulated depletion and amortization
                
                
                (19,810,023
                )
                
                
                (14,401,584
                )
                
                
                (10,628,438
                )Oil
      and natural gas properties—net
                
                $
                116,426,381
                
                
                $
                205,260,103
                
                
                $
                161,471,277





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.





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





Years Ended December 31,
                  
                  2008
                  
                  
                  2007
                  
                  
                  2006Property
      acquisition costsProved
                  
                  $
                  -
                  
                  
                  $
                  3,005,609
                  
                  
                  $
                  24,011,335Unproved
                  
                  
                  3,923,728
                  
                  
                  
                  16,012,328
                  
                  
                  
                  27,718,336Exploration
                  
                  
                  490,300
                  
                  
                  
                  11,687,015
                  
                  
                  
                  8,360,779Development
                  
                  
                  6,055,508
                  
                  
                  
                  23,494,779
                  
                  
                  
                  46,575,829Ceiling
      write-down
                  
                  
                  (78,457,801
                  )
                  
                  
                  -
                  
                  
                  
                  -Total
      costs incurred
                  
                  
                  (67,988,265
                  )
                  
                  
                  54,199,731
                  
                  
                  
                  106,666,279Sales
      of oil and natural gas properties
                  
                  
                  (15,437,018
                  )
                  
                  
                  (2,079,518
                  )
                  
                  
                  (11,489,456
                  )Total(a)
                  
                  $
                  (83,425,283
                  )
                  
                  $
                  52,120,213
                  
                  
                  $
                  95,176,823


107


AURORA
OIL & GAS CORPORATION AND SUBSIDIARIES


SUPPLEMENTAL
INFORMATION ON OIL AND NATURAL


GAS
EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES


(Unaudited- continued)





(a)Total costs incurred includes (a) capitalized general and
administrative costs directly associated with the acquisition, exploration, and
development efforts of approximately $0.6 million, $1.3 million, and $1.3
million for years ended December 31, 2008, 2007, and 2006, respectively, and
(b) capitalized interest on unproven properties of $4.5 million, $4.5
million, and $3.9 million for years ended December 31, 2008, 2007, and 2006,
respectively.  Certain non-cash transactions are included as
follows:  (a) 2008, 2007, and 2006 asset retirement obligation of
$0.1 million, $0.1 million, and $0.2 million, respectively, (b) 2008, 2007, and
2006 capitalized stock based compensation of $0.6 million, $1.3 million, and
$0.5 million, respectively, (c) 2008 sale proceeds of $12.0 million, and (d) net
transfer of $0.3 million from 2005 deposits to 2006 oil and natural gas
properties.





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, ceiling write-down of oil
and gas properties, 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,
                          
                          2008
                          
                          
                          2007
                          
                          
                          2006Oil
      and natural gas sales
                          
                          $
                          25,201,777
                          
                          
                          $
                          26,723,818
                          
                          
                          $
                          21,591,811Production
      taxes
                          
                          
                          (1,338,397
                          )
                          
                          
                          (1,123,070
                          )
                          
                          
                          (877,319
                          )Production
      and lease operating costs
                          
                          
                          (9,995,981
                          )
                          
                          
                          (8,424,096
                          )
                          
                          
                          (5,966,341
                          )Depletion
      and amortization
                          
                          
                          (5,380,106
                          )
                          
                          
                          (3,769,104
                          )
                          
                          
                          (2,681,290
                          )Results
      of operations from producing activities
                          
                          $
                          8,487,293
                          
                          
                          $
                          13,407,548
                          
                          
                          $
                          12,066,861


108


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 Commission’s Internal Control-Integrated
Framework (“COSO framework”) in conducting the required assessment of
effectiveness of our internal control over financial reporting.





Disclosure
controls and procedures are controls and other procedures that are designed to
ensure that information required to be disclosed by the Company is recorded,
processed, summarized and reported, within the time periods specified in the
rules and forms of the Securities and Exchange Commission.  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
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.


109


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, 2008.  Based on the evaluation and considering the
material weakness in internal control over financial reporting described below,
our CEO and CFO concluded that the Company’s reserve reporting controls were not
effective.





Changes
in Internal Controls over Financial Reporting





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 and includes those policies and procedures
that:





·
            Pertain
      to the maintenance of records that, in reasonable detail, accurately and
      fairly reflect the transactions and dispositions of the assets of the
      issuer;





·
            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





·
            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 control may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.





A
material weakness is a deficiency, or combination of deficiencies, in internal
control over financial reporting, such that there is a reasonable possibility
that a material misstatement of our annual or interim financial statements will
not be prevented or detected on a timely basis.  In the course of
auditing our year-end financial statements, our auditors identified a material
weakness that resulted from an error made by us during our initial pricing of
our reserve report.  We initially priced our reserve report using the
effective price at December 31, 2008, including an adjustment of the price based
on a contract that expired on December 31, 2008.  Since the contract
expired on December 31, 2008, the contract price was incorrectly used to
initially price future reserves.  Prior to the audit of our December
31, 2008 financial statements, the effect of this error was recorded and
resulted in understating impairment of the full cost pool by approximately $20.0
million as a result of the ceiling test at December 31, 2008.  An
audit adjustment was made to correct the error and is reflected in the December
31, 2008 financial statements.  This error had no impact on the
December 31, 2007 or 2006 financial statements.





As a
result of the error in initially pricing our reserves, we are currently
formulating a remediation plan to address this material weakness.  We
will have this plan in place prior to commencing preparation procedures for the
next reserve report.  This remediation plan is expected to include
certain checklists, additional education and training for those employees
involved in the reserve reporting process, expanded reserve planning and
assumption meetings, and require supporting documentation for the prices to be
used in calculating reserve values and any other assumptions that have a
material impact in the reserve evaluation.





Since the
above error was a failure in a one-time annual control historically occurring
during the first quarter, there have been no changes in our internal controls
over financial reporting during the period covered by this report that have
materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting.  As noted above, we are currently
formulating a remediation plan to address this material weakness which will
result in changes to our internal controls during 2009.


110


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.




111




PART
III





ITEM
10.        DIRECTORS, EXECUTIVE
OFFICERS, AND CORPORATE GOVERNANCE




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





Name
                
                Age
                
                Position(s) with the
  CompanyWilliam
      W. Deneau
                
                64
                
                Director,
      Chairman and Chief Executive OfficerGilbert
      A. Smith
                
                61
                
                President
      and Vice President, Business DevelopmentJohn
      C. Hunter
                
                57
                
                Vice
      President, Exploration and ProductionBarbara
      E. Lawson
                
                50
                
                Chief
      Financial OfficerRichard
      M. Deneau
                
                62
                
                DirectorJohn
      E. McDevitt
                
                62
                
                DirectorGary
      J. Myles
                
                63
                
                DirectorWayne
      G. Schaeffer
                
                62
                
                DirectorKevin
      D. Stulp
                
                52
                
                DirectorEarl
      V. Young
                
                68
                
                Director





Under the Company’s by-laws, the
authorized number of directors is set at no fewer than three and no more than
ten directors. The Board of Directors currently has seven members. Each member
of the Board of Directors serves for a term of one year that expires at the
following annual shareholders’ meeting. Each officer serves at the pleasure of
the Board of Directors and until a successor has been qualified and
appointed.





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





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





William W.
Deneau has served on our Board of Directors and as Chief Executive
Officer and Chairman of the Board of Directors since November 1, 2005. Mr.
Deneau also served as President until May 30, 2007. Mr. Deneau became an
employee of Aurora Energy, Ltd. (“AEL”) on April 22, 1997, when he sold his
interest in Jet/LaVanway Exploration, L.L.C. to AEL in exchange for AEL’s stock.
On June 25, 1997, and July 17, 1997, respectively, Mr. Deneau became a Director
and President of AEL, which became a wholly-owned subsidiary of the Company on
October 31, 2005. Mr. Deneau continued to manage the affairs of AEL through
January 1, 2008, when it was merged with the Company. William W. Deneau is the
brother of Richard M. Deneau, another one of our Directors.





Gilbert A.
Smith has served as our President since November 15, 2008, and 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, a position he
continues to hold.  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.


112


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.





Barbara E.
Lawson has served as our Chief Financial Officer since January 22, 2008.
From March 2006 until she became our Chief Financial Officer, Ms. Lawson worked
for us 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. Ms. Lawson managed up to $450 million investment
portfolio, administered compliance on $1.7 billion of bond debt, implemented
Sarbanes-Oxley compliance requirements, and managed at least 12 internal audits
annually.





Richard M.
Deneau has served on our Board of Directors since November 21, 2005. Mr.
Deneau served as a Director and President of Anchor Glass Container Corporation
(“Anchor”) from 1997 until his retirement in 2004. He was also the Chief
Operating Officer of Anchor from 1997 to 2002, and the Chief Executive Officer
of Anchor from 2002 until his retirement. Anchor, which was publicly traded and
listed on NASDAQ, is the third largest glass container manufacturer in the
United States, with annual revenues of about $750 million.  Mr. Deneau
is the brother of William W. Deneau, who is also a director and is our Chief
Executive Officer and Chairman of the Board.





John E.
McDevitt has served as a Director since January 22, 2008. Mr. McDevitt
also served as our President and Chief Operating Officer from January 22, 2008,
until his resignation on November 15, 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, 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 CFO 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.





Gary J.
Myles has served on our Board of Directors since November 21, 2005. Mr.
Myles also served as a Director of AEL (which became a wholly-owned subsidiary
of the Company on October 31, 2005) from June 1997 until January 1, 2008, when
AEL was merged into the Company. He is currently retired from his primary
employment. Prior to his retirement, Mr. Myles served as Vice President and
Consumer Loan Manager for Fifth Third Bank of Northern Michigan (previously Old
Kent Mortgage Company), a wholly owned subsidiary of Fifth Third Bank
(previously Old Kent Financial Corporation). Mr. Myles had been with Fifth Third
Bank and its predecessor, Old Kent Mortgage Company, since July 1988 and retired
on October 14, 2005.





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





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


113


Earl V.
Young has served on our Board of Directors since November 21, 2005. Mr.
Young has also served as a Director of AEL (which became a wholly-owned
subsidiary of the Company on October 31, 2005) from June 1997 until January 1,
2008, when AEL was merged into the Company. He is currently President of Earl
Young & Associates of Dallas, Texas, which he founded in 1999. Mr. Young is
also a Director and chair of the Audit Committee for Diamond Fields
International, a Canadian company that is listed on the Toronto Stock Exchange
and is a producer of offshore diamonds in Nambia with exploration activity in
Sierra Leone and Liberia. Mr. Young is a Director of Madagascar Resources, an
Australian public company that is engaged in mineral exploration in
Madagascar.




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




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





THE BOARD OF DIRECTORS AND
STANDING


COMMITTEES OF
DIRECTORS





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





We require that all members of our
standing Board committees be independent directors. Our Board committees are as
follows:





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





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





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





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





We have adopted a Code of Conduct and
Ethics, a copy of which is available on our website at www.auroraogc.com.
This Code applies to all Directors, officers, and employees.





Audit
Committee





We have a separately designated
standing Audit Committee established in accordance with Section 3(a)(58)(A) of
the Securities Exchange Act of 1934, as amended (“Exchange Act”). Members of the
Audit Committee currently include Wayne G. Schaeffer, Earl V. Young, and Gary J.
Myles. Each of them is an independent outside director. Wayne G. Schaeffer was
designated by the Board as a financial expert. We have included in the
biographical information above a brief summary of his relevant
experience.


114





ITEM
11.        EXECUTIVE
COMPENSATION




COMPENSATION DISCUSSION AND
ANALYSIS





General Objectives of
Compensation Program





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





Process





Our executive officers may from time
to time make recommendations to the Compensation Committee regarding executive
compensation. The Compensation Committee may accept or reject these
recommendations. If they are accepted, the Compensation Committee presents them
as recommendations to the Board of Directors. Our Board of Directors has
ultimate authority over executive compensation and may follow or disregard the
recommendations of the Compensation Committee. Executive officers are excused
from Board deliberations on executive compensation, and executive officers who
are also directors do not vote on any matters that affect their own
compensation.





Compensation of our
Executive Officers





Objectives





As we entered 2008, our primary
objective for the year 2008 was to maintain a fair compensation level while we
continued to work on developing a more comprehensive compensation philosophy. At
that time, we were working with an investment banker to evaluate strategic
alternatives, and we thought it best to defer work on a comprehensive
compensation philosophy until our strategic direction was clearer. In July 2008,
we identified a compensation consultant who we were interested in engaging to
help us develop our executive compensation strategy. However, in light of our
deteriorating financial condition, we decided to defer any strategic planning
for executive compensation and focus instead on retaining the management team we
need to lead us through these rough economic times. Once our financial condition
is less precarious, we intend to return to work on our executive compensation
plan. In the meantime, our interim approach is described below.





Elements of Executive
Compensation





Base Salary.  It is
our practice to re-evaluate base salary for our executive officers each year. In
general, our philosophy is to pay a base salary that is fair in the sense of
being competitive enough in the market place to attract and retain our executive
officers, given the circumstances of each individual involved, but no more. Our
philosophy is not to match the base salary paid by our peers, but to determine
what is fair and competitive overall compensation under the circumstances. In
2006, we retained the services of a compensation consulting firm that provided
us with data regarding compensation for peer executive officers within our
industry.





With the exception of our CEO, by the
end of the first quarter of 2008, our executive management team was completely
different than the team we had in place during the first quarter of 2007.
Accordingly, as new executive officers were hired, their salaries were set at a
level that we believed would be sufficient to attract, retain and motivate
competent employees. We awarded our CEO a modest salary increase in
2008.


115





We
generally do not make material changes in base salary compensation levels unless
there is a significant change in job responsibilities or if the present level of
an incumbent's compensation is substantially below competitive levels. We will
generally look at modest annual increases as a means of making up for
inflationary cost of living increases and to provide some modest merit-based
increase for work done during the prior year.





Annual Performance Bonus. Our
approach to the use of annual performance bonuses will vary from year to year.
During the year 2009, we hope to develop bonus-based compensation for our
executive officers tied to their achievement of performance metrics or the
character of their assigned duties. Although we do not yet have our anticipated
bonus plans in place, it is the goal of the Compensation Committee to
significantly increase the proportion of the compensation we pay to our
executive officers that is based on performance bonuses. Annual bonuses will be
used to align compensation with performance based upon performance metrics.
However, this work will be deferred until our financial condition is more
stable.





Special Purpose Bonuses. In
2007, we implemented three special purpose bonuses, as described in our December
31, 2007 Form 10-K. During 2008, these bonuses were modified as described
below.





•
            Stay Bonus – the Stay
      Bonus Arrangement was adopted in 2007 to encourage employees to remain
      employed by us through any possible change-in-control. For purposes of
      this arrangement, "change-in-control" was defined to mean any transaction
      or occurrence (including a sale of stock or merger) where our shareholders
      before the transaction or occurrence owned less than 50% of our voting
      shares after the transaction or occurrence, or a sale or disposition of a
      majority of our assets. Under the Stay Bonus Arrangement, if a
      change-in-control occurred on or before September 1, 2008, and the
      employees who received this benefit remained continuously employed by us
      through a change-in-control, the employees who participated in the Stay
      Bonus Arrangement would have been eligible for a stay bonus in the amount
      of 50% of their then current annual
salary.





During
2008, the Stay Bonus Arrangement was extended to changes in control that
occurred by December 31, 2008. Because we did not undergo a change-in-control by
December 31, 2008, the Stay Bonus Arrangement that we adopted in 2007 expired
without the award of any bonuses.





•
            Change-in-Control
      Agreements – the Change-in-Control Agreements were adopted in 2007
      to encourage certain key officers and employees to remain employed with us
      through any potential change-in-control. The Change-in-Control Agreements
      provide that during a two-year period following a change-in-control, the
      employees who were provided these agreements would: (i) have a position
      and duties commensurate to those the employee had prior to the
      change-in-control; (ii) perform his or her services at a location within a
      35-mile radius from his or her previous worksite before the
      change-in-control; and (iii) receive an annual base salary at least equal
      to the employee's annual base salary prior to the change-in-control unless
      a reduction in salary occurs on a proportional basis simultaneously with a
      Company-wide reduction in senior management salaries. If any of the
      foregoing commitments are not met, a "covered termination" is deemed to
      have occurred. In the event of a covered termination during the two-year
      period following a change-in-control, the arrangement provides for the
      payment of an amount equal to either one or two times the employee's
      annual salary, the provision of medical and dental benefits for up to 24
      months following the date of termination, and benefits continuation
      substantially similar to those to which the employee was entitled prior to
      the date of termination.





In 2008,
we modified which executive officers were entitled to receive Change-in-Control
Agreements and the multiplier of annual salary some of the executives are
entitled to receive. The executive officers who are currently covered by these
Change-in-Control Agreements are: William W. Deneau, our current Chief Executive
Officer, who would receive two times his annual salary in the event of an
applicable post change-in-control termination; Gilbert A. Smith, our President
and Vice President of Business Development, who would receive one times his
annual salary in the event of an applicable post change-in-control termination;
John C. Hunter, our Vice President of Exploration and Production, who would
receive two times his annual salary in the event of an applicable post
change-in-control termination; and Barbara E. Lawson, our Chief Financial
Officer, who would receive two times her annual salary in the event of an
applicable post change-in-control termination.


116








•
            Retention Bonus – The
      Retention Bonus Arrangement was adopted in 2007 to encourage certain key
      officers and employees to remain employed by us through any possible
      changes in control. The Compensation Committee and Board of Directors
      recognized that certain key officers and employees would have increased
      responsibilities and duties during the evaluation of strategic
      alternatives, and that they would also contribute significantly to the
      process. The Retention Bonus Arrangement consisted of equal payments to be
      made on October 26, 2007, December 26, 2007, February 26, 2008 and April
      28, 2008. The participating officers and employees were required to remain
      continuously employed through each of the scheduled payment
      dates.  The final payment was made in April 2008 to those
      employees actively participating in the strategic alternative process at
      that time.





Executive
officers who participated in the Retention Bonus Arrangement included Ronald E.
Huff, our former President and Chief Financial Officer in the aggregate amount
of $100,000; John C. Hunter, one of our Vice Presidents, in the aggregate amount
of $80,000; John V. Miller, one of our former Vice Presidents, in the
aggregate amount of $40,000; and Barbara E. Lawson, our current Chief
Financial Officer, in the aggregate amount of $40,000. In each case, one quarter
of the dollar amount specified was payable on each bonus date based upon active
employment.





Stock Options.  We
use stock options from time to time to serve as a long-term incentive to keep
our employees' performance aligned with our overall corporate goals. Because of
the tax preferred treatment of incentive stock options, we evaluate the tax
benefits of incentive stock options when evaluating compensation for our
executive officers.





Philosophically, the Compensation
Committee has agreed that stock options and other equity incentive awards should
be reserved for situations in which the executive officer meets stated goals or
to incentivize desired outcomes. Stock options may also be used as a signing
bonus.





In 2008, we awarded stock options to
executive officers and other management employees, with a goal of incentivizing
them through our difficult financial circumstances. Each stock option has a
10-year term and vests over 3 years. The awards to executive officers were as
follows:





Name
                                          
                                          No. of SharesJohn
      E. McDevitt
                                          
                                          
                                          1,000,000
                                          (a)William
      W. Deneau
                                          
                                          
                                          250,000Gilbert
      A. Smith
                                          
                                          
                                          225,000John
      C. Hunter
                                          
                                          
                                          225,000Barbara
      E. Lawson
                                          
                                          
                                          225,000(a)  Mr.
      McDevitt resigned before any of these options
vested.




Stock Awards. In addition to
the issuance of stock options, we also have used, and from time to time expect
to continue to use, stock awards as an element of executive compensation. This
determination will be made on a case-by-case basis. We did not provide any stock
awards to our executive officers during 2008.





In the future, we anticipate that
stock awards will be reserved for use in the context of a signing bonus or, in
some cases, if certain performance goals are satisfied.





Other Types of Compensation.
We do not have in place at this time any other types of long-term incentive
compensation or special executive benefits not provided to all of our employees
on the same terms.


117





Equity Ownership Guidelines
and Requirements





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





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





Compensation Committee
Report





The Compensation Committee has
reviewed and discussed the foregoing Compensation Discussion and Analysis with
management, and based on this review and discussions, the Compensation Committee
recommended to the Board of Directors that the foregoing Compensation Discussion
and Analysis be included in this Form 10-K. This report is submitted by the
members of the Compensation Committee.





Gary
      J. Myles, ChairmanWayne
      G. SchaefferKevin
      D. Stulp




Compensation Committee
Interlocks And Insider Participation





None of our Compensation Committee
members were, during our fiscal year ending December 31, 2008, or at any prior
time, employed as an officer or employee of the Company. There are no
relationships between the members of our Compensation Committee and the Company
that require disclosure.


118


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




SUMMARY
COMPENSATION TABLE




Name
      and Principal
                                                                                              Position
                                                                                            
                                                                                            Year
                                                                                            
                                                                                            Salary
                                                                                              ($)
                                                                                            
                                                                                            
                                                                                            Bonus
                                                                                              ($)
                                                                                            
                                                                                            
                                                                                            Stock
                                                                                              Awards
                                                                                              ($)
                                                                                            
                                                                                            
                                                                                            Option
                                                                                              Awards
      ($)
                                                                                            
                                                                                            
                                                                                            All
      Other
                                                                                              Compen-
                                                                                              sation
      ($)
                                                                                            
                                                                                            
                                                                                            Total
                                                                                              ($)William
      W. Deneau
                                                                                            
                                                                                            2008(f)
                                                                                            
                                                                                            
                                                                                            173,333
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            92,375
                                                                                            (a)
                                                                                            
                                                                                            
                                                                                            5,200
                                                                                            (b)
                                                                                            
                                                                                            
                                                                                            270,908Chief  Executive
      Officer
                                                                                            
                                                                                            2007
                                                                                            
                                                                                            
                                                                                            150,000
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            118,958
                                                                                            (a)
                                                                                            
                                                                                            
                                                                                            4,500
                                                                                            (b)
                                                                                            
                                                                                            
                                                                                            273,4582006
                                                                                            
                                                                                            
                                                                                            140,000
                                                                                            
                                                                                            
                                                                                            
                                                                                            28,000
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            196,974
                                                                                            (a)
                                                                                            
                                                                                            
                                                                                            2,450
                                                                                            (b)
                                                                                            
                                                                                            
                                                                                            367,424Gilbert
      A. Smith
                                                                                            
                                                                                            2008(f)
                                                                                            
                                                                                            
                                                                                            183,333
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            41,919
                                                                                            (a)
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            225,252President(g)Barbara
      E. Lawson
                                                                                            
                                                                                            2008(f)
                                                                                            
                                                                                            
                                                                                            180,616
                                                                                            
                                                                                            
                                                                                            
                                                                                            20,000
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            55,489
                                                                                            (a)
                                                                                            
                                                                                            
                                                                                            5,418
                                                                                            (b)
                                                                                            
                                                                                            
                                                                                            261,523Chief Financial
      Officer(h)John
      C. Hunter
                                                                                            
                                                                                            2008(f)
                                                                                            
                                                                                            
                                                                                            143,000
                                                                                            
                                                                                            
                                                                                            
                                                                                            40,000
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            48,128
                                                                                            (a)
                                                                                            
                                                                                            
                                                                                            16,460
                                                                                            (c)
                                                                                            
                                                                                            
                                                                                            247,588Vice
      President
                                                                                            
                                                                                            2007
                                                                                            
                                                                                            
                                                                                            119,167
                                                                                            
                                                                                            
                                                                                            
                                                                                            40,000
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            21,974
                                                                                            (a)
                                                                                            
                                                                                            
                                                                                            3,575
                                                                                            (b)
                                                                                            
                                                                                            
                                                                                            184,7162006
                                                                                            
                                                                                            
                                                                                            109,167
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            35,992
                                                                                            (a)
                                                                                            
                                                                                            
                                                                                            1,650
                                                                                            (b)
                                                                                            
                                                                                            
                                                                                            146,809John
      E. McDevitt
                                                                                            
                                                                                            2008(f)
                                                                                            
                                                                                            
                                                                                            218,384
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            186,265
                                                                                            (a)
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            404,649President and Chief
      Operating Officer(i)John
      V. Miller, Jr.
                                                                                            
                                                                                            2008(f)
                                                                                            
                                                                                            
                                                                                            25,096
                                                                                            
                                                                                            
                                                                                            
                                                                                            10,000
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            753
                                                                                            (b)
                                                                                            
                                                                                            
                                                                                            35,849Vice President(j)
                                                                                            
                                                                                            2007
                                                                                            
                                                                                            
                                                                                            130,000
                                                                                            
                                                                                            
                                                                                            
                                                                                            20,000
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            3,900
                                                                                            (b)
                                                                                            
                                                                                            
                                                                                            153,900Ronald
      E. Huff
                                                                                            
                                                                                            2008(f)
                                                                                            
                                                                                            
                                                                                            137,897
                                                                                            
                                                                                            
                                                                                            
                                                                                            25,000
                                                                                            
                                                                                            
                                                                                            
                                                                                            492,909
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            4,137
                                                                                            (b)
                                                                                            
                                                                                            
                                                                                            659,943President
      and Chief
                                                                                            
                                                                                            2007
                                                                                            
                                                                                            
                                                                                            208,333
                                                                                            
                                                                                            
                                                                                            
                                                                                            50,000
                                                                                            
                                                                                            
                                                                                            
                                                                                            1,050,570
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            6,167
                                                                                            (b)
                                                                                            
                                                                                            
                                                                                            1,315,070Financial
      Officer(e)
                                                                                            
                                                                                            2006
                                                                                            
                                                                                            
                                                                                            105,400
                                                                                            (d)
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            566,521
                                                                                            
                                                                                            
                                                                                            
                                                                                            -
                                                                                            
                                                                                            
                                                                                            
                                                                                            2,000
                                                                                            (b)
                                                                                            
                                                                                            
                                                                                            673,921




(a)
            The
      assumptions used to calculate value in accordance with FAS 123R may be
      found in Note 11 “Common Stock Options” of our financial statements
      provided above.


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


(c)
            We
      paid Mr. Hunter $12,500 for a housing allowance and made 401(k) matching
      contributions of $3,630.


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


(e)
            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 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 was honored by the Company through its June
      18, 2008 termination date. This agreement was 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.  In June 2008,
      350,000 shares of the Company’s stock were issued in connection with Mr.
      Huff’s stock bonus.  Mr. Huff forfeited 150,000 shares in
      exchange for us paying taxes associated with the stock bonus in the amount
      of $90,450.


(f)
            Due
      to our change in frequency of pay during 2008 from monthly to bi-weekly,
      there is one additional pay date included in the 2008
    totals.


(g)
            Mr.
      Smith became a Vice President on February 1, 2008, and became President on
      November 15, 2008.


(h)
            Ms.
      Lawson was appointed CFO effective January 21, 2008.  Before
      that, she served as our SEC Reporting
Manager.


119




(i)
            Mr.
      McDevitt was appointed President and Chief Operating Officer effective
      January 21, 2008 and resigned effective November 15,
  2008.


(j)
            Mr.
      Miller resigned effective February 29,
2008.





The
following table sets forth information on grants of equity-based awards to
executive officers during 2008.





GRANTS
OF PLAN-BASED AWARDS





Name
                            
                            Grant
                              Date
                            
                            Date of
                              Board
                              Action
                            
                            Stock
                              Awards
                              No. of
                              Shares of
                              Stock
                            
                            
                            Option
                              Awards
                              No. of
                              Shares of
                              Stock
                              Underlying
                              Options
                            
                            
                            Exercise
                              Price of
                              Option
                              Award
                            
                            
                            Closing
                              Market
                              Price on
                              Grant
                              Date
                            
                            
                            Grant
                              Date
                              Fair Value
                              of Stock
                              And
                              Option
                              AwardsWilliam
      W. Deneau
                            
                            05/30/08
                            
                            05/30/08
                            
                            
                            -
                            
                            
                            
                            250,000
                            
                            
                            $
                            0.75
                            
                            
                            $
                            0.75
                            
                            
                            $
                            129,025Gilbert
      A. Smith
                            
                            05/30/08
                            
                            05/30/08
                            
                            
                            -
                            
                            
                            
                            225,000
                            
                            
                            $
                            0.75
                            
                            
                            $
                            0.75
                            
                            
                            $
                            116,123Barbara
      E. Lawson
                            
                            05/30/08
                            
                            05/30/08
                            
                            
                            -
                            
                            
                            
                            225,000
                            
                            
                            $
                            0.75
                            
                            
                            $
                            0.75
                            
                            
                            $
                            116,123John
      C. Hunter
                            
                            05/30/08
                            
                            05/30/08
                            
                            
                            -
                            
                            
                            
                            225,000
                            
                            
                            $
                            0.75
                            
                            
                            $
                            0.75
                            
                            
                            $
                            116,123John
      E. McDevitt
                            
                            05/30/08
                            
                            05/30/08
                            
                            
                            -
                            
                            
                            
                            1,000,000
                            (a)
                            
                            $
                            0.75
                            
                            
                            $
                            0.75
                            
                            
                            $
                            516,100





Options
awarded during 2008 vest one-third annually over a three year
period.  The options expire on May 30, 2018.





(a) Mr.
McDevitt resigned before any of these options vested.





The
following table sets forth information on exercised options and unvested stock
awards held by our executive officers as of December 31, 2008.





OUTSTANDING
EQUITY AWARDS AT FISCAL YEAR-END





Name
                                                                                
                                                                                No. of Shares
                                                                                  Underlying
                                                                                  Unexercised
                                                                                  Options–No.
                                                                                  Exercisable
                                                                                
                                                                                
                                                                                No. of Shares
                                                                                  Underlying
                                                                                  Unexercised
                                                                                  Options–No.
                                                                                  Unexercisable
                                                                                
                                                                                
                                                                                Option
                                                                                  Exercise
                                                                                  Price
                                                                                
                                                                                Option
                                                                                  Expiration
                                                                                  DateWilliam
      W. Deneau
                                                                                
                                                                                
                                                                                130,000
                                                                                
                                                                                
                                                                                
                                                                                70,000
                                                                                
                                                                                
                                                                                $
                                                                                3.62
                                                                                
                                                                                11/11/10-
                                                                                
                                                                                
                                                                                
                                                                                250,000
                                                                                
                                                                                
                                                                                $
                                                                                0.75
                                                                                
                                                                                05/30/18Gilbert
      A. Smith
                                                                                
                                                                                
                                                                                -
                                                                                
                                                                                
                                                                                
                                                                                225,000
                                                                                
                                                                                
                                                                                $
                                                                                0.75
                                                                                
                                                                                05/30/18Barbara
      E. Lawson
                                                                                
                                                                                
                                                                                20,000
                                                                                
                                                                                
                                                                                
                                                                                10,000
                                                                                
                                                                                
                                                                                $
                                                                                4.70
                                                                                
                                                                                03/28/1610,000
                                                                                
                                                                                
                                                                                
                                                                                5,000
                                                                                
                                                                                
                                                                                $
                                                                                4.70
                                                                                
                                                                                05/19/16-
                                                                                
                                                                                
                                                                                
                                                                                225,000
                                                                                
                                                                                
                                                                                $
                                                                                0.75
                                                                                
                                                                                05/30/18John
      C. Hunter
                                                                                
                                                                                
                                                                                90,000
                                                                                
                                                                                
                                                                                
                                                                                -
                                                                                
                                                                                
                                                                                $
                                                                                2.55
                                                                                
                                                                                03/01/1010,000
                                                                                
                                                                                
                                                                                
                                                                                5,000
                                                                                
                                                                                
                                                                                $
                                                                                4.70
                                                                                
                                                                                05/19/16-
                                                                                
                                                                                
                                                                                
                                                                                225,000
                                                                                
                                                                                
                                                                                $
                                                                                0.75
                                                                                
                                                                                05/30/18No
      options were exercised by executive officers during 2008.




120


POTENTIAL
PAYMENTS UPON CHANGE IN CONTROL





Had a
change of control taken place on December 31, 2008, and certain other provisions
of the change in control agreement been triggered, the following executive
officers would have been paid in accordance with the change of control agreement
referenced above.





Name
                    
                    AmountBarbara
      E. Lawson
                    
                    $
                    400,000William
      W. Deneau
                    
                    $
                    320,000John
      C. Hunter
                    
                    $
                    264,000Gilbert
      A. Smith
                    
                    $
                    200,000





COMPENSATION OF
DIRECTORS





The table below sets forth the
compensation we paid to our non-employee directors during 2008.





DIRECTOR
COMPENSATION TABLE





Name
                    
                    Fees Earned or
                      Paid in Cash
                    
                    
                    Value of OptionAwards
                    
                    
                    TotalRichard
      M. Deneau
                    
                    $
                    43,000
                    (f)
                    
                    $
                    51,610
                    (a)
                    
                    $
                    94,610Gary
      J. Myles
                    
                    $
                    47,500
                    
                    
                    $
                    51,610
                    (b)
                    
                    $
                    99,110Wayne
      G. Schaeffer
                    
                    $
                    53,000
                    
                    
                    $
                    51,610
                    (c)
                    
                    $
                    104,610Kevin
      D. Stulp
                    
                    $
                    55,000
                    
                    
                    $
                    51,610
                    (d)
                    
                    $
                    106,610Earl
      V. Young
                    
                    $
                    48,000
                    
                    
                    $
                    51,610
                    (e)
                    
                    $
                    99,610





(a)
            At
      December 31, 2008, Richard M. Deneau owned options to purchase an
      aggregate of 300,000 shares of our common stock, 130,000 of which are
      vested and 170,000 of which are
unvested.


(b)
            At
      December 31, 2008, Gary J. Myles owned options to purchase an aggregate of
      366,666 shares of our common stock, 196,666 of which are vested, and
      170,000 of which are unvested.


(c)
            At
      December 31, 2008, Wayne G. Schaeffer owned options to purchase an
      aggregate of 240,000 shares of our common stock, 70,000 of which are
      vested, and 170,000 of which are
unvested.


(d)
            At
      December 31, 2008, Kevin D. Stulp owned options to purchase an aggregate
      of 300,000 shares of our common stock, 130,000 of which are vested, and
      170,000 of which are unvested.


(e)
            At
      December 31, 2008, Earl V. Young owned options to purchase an aggregate of
      366,666 shares of our common stock, 196,666 of which are vested, and
      170,000 of which are unvested.


(f)
              Mr.
      Deneau’s compensation does not include $45,500 related to consulting
      services performed for us during 2008 more fully described in Item 13 of
      this report.





For 2008,
our standard compensation arrangement for service as a non-employee director was
as follows:





§
            Annual
      retainer of $25,000.





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





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





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


121





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





§
            Compensation
      for meetings is a daily aggregate fee without regard to the number of
      meetings held in proximity to each other and, for purposes hereof, Board
      meetings and Committee meetings shall be considered together and shall be
      covered by a single aggregate daily
fee.





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





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




The
following table sets forth, as of March 4, 2009, certain information regarding
the ownership of voting securities of the Company by each shareholder known by
the management of the Company to be (i) the beneficial owner of more than 5% of
our outstanding common stock, (ii) our directors, (iii) our current executive
officers and (iv) all executive officers and directors as a group. Except as
otherwise reflected in the notes below, the Company believes that the beneficial
owners of the common stock listed below, based on information furnished by such
owners, have sole investment and voting power with respect to such
shares.





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





Name and Address of Beneficial Owner(a)
                
                Amount and Nature
                  of Beneficial
                  Ownership(b)
                
                
                Percent of
                  Outstanding
                  SharesNathan
      A. Low Roth IRA and affiliates
                
                
                8,586,409
                (c)
                
                
                8
                %641
      Lexington AvenueNew
      York, New York 10022William
      W. Deneau
                
                
                3,854,814
                (d)
                
                
                4
                %Kevin
      D. Stulp
                
                
                727,500
                (e)
                
                
                *Earl
      V. Young
                
                
                616,204
                (f)
                
                
                *Gary
      J. Myles
                
                
                508,798
                (g)
                
                
                *Richard
      M. Deneau
                
                
                240,000
                (h)
                
                
                *John
      C. Hunter
                
                
                129,400
                (i)
                
                
                *Wayne
      G. Schaeffer
                
                
                160,000
                (j)
                
                
                *Barbara
      E. Lawson
                
                
                67,500
                (k)
                
                
                *John
      E. McDevitt
                
                
                130,000
                (l)
                
                
                *Gilbert
      A. Smith
                
                
                -0-
                (m)
                
                
                *All
      executive officers and directors as a group
    (10 persons)
                
                
                6,434,216
                (n)
                
                
                6
                %




* Less
than 1%




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


122




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




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




(d)
            Includes
      options currently exercisable for 200,000 shares of common stock;
      3,272,000 shares of common stock held by the Patricia A. Deneau Trust;
      360,146 shares of common stock held by the Denthorn Trust; 20,000 shares
      of common stock held by White Pine Land Services, Inc.; and 2,668 shares
      of common stock held by Circle D, Ltd. (shared investment interest). Does
      not include options to purchase 250,000 shares of common stock vesting as
      follows: 83,333 shares on May 30, 2009; 83,333 shares on May 30, 2010; and
      83,334 shares on May 30, 2011.




(e)
            Includes
      options currently exercisable for 200,000 shares of common stock; 2,750
      shares of common stock owned by the Kevin Dale Stulp IRA; and 1,750 shares
      of common stock owned by the Kevin and Marie Stulp Charitable Remainder
      Unitrust of which Mr. Stulp is a co-trustee. Does not include options to
      purchase 100,000 shares of common stock vesting as follows: 33,333 shares
      on May 30, 2009; 33,333 shares on May 30, 2010; and 33,334 shares on May
      30, 2011.




(f)
            Includes
      options currently exercisable for 266,666 shares of common stock. Does not
      include options to purchase 100,000 shares of common stock vesting as
      follows: 33,333 on May 30, 2009; 33,333 on May 30, 2010; and 33,334 on May
      30, 2011.




(g)
            Includes
      211,132 shares of common stock held by the Gary J. Myles & Rosemary
      Myles Inter Vivos Trust and options currently exercisable for 266,666
      shares of common stock. Does not include options to purchase 100,000
      shares of common stock vesting as follows: 33,333 shares on May 30, 2009;
      33,333 shares on May 30, 2010, and 33,334 shares on May 30,
      2011.




(h)
            Includes
      options currently exercisable for 200,000 shares of common stock. Does not
      include options to purchase 100,000 shares of common stock vesting as
      follows: 33,333 shares on May 30, 2009; 33,333 shares on May 30, 2010; and
      33,334 shares on May 30, 2011.




(i)
            Includes
      2,000 shares of common stock held by his minor son and options currently
      exercisable for 100,000 shares of common stock. Does not include options
      to purchase 230,000 shares of common stock vesting as follows: 5,000
      shares on May 19, 2009; 75,000 shares on May 30, 2009; 75,000 shares on
      May 30, 2010; and 75,000 on May 30,
2011.




(j)
            Includes
      options currently exercisable for 140,000 shares of common stock. Does not
      include options to purchase 100,000 shares of common stock vesting as
      follows: 33,333 shares on May 30, 2009; 33,333 shares on May 30, 2010; and
      33,334 shares on May 30, 2011.




(k)
            Includes
      12,000 shares held by her spouse and options currently exercisable for
      45,000 shares of common stock. Does not include options to purchase
      225,000 shares of common stock vesting as follows: 75,000 shares on May
      30, 2009; 75,000 shares on May 30, 2010; and 75,000 shares on May 30,
      2011.




(l)
            Includes
      30,000 shares of common stock by Financial Intermediaries, Ltd.; 100,000
      shares of common stock owned by the John E. McDevitt
  IRA.


123




(m)
            Does
      not include options to purchase 225,000 shares vesting as follows: 75,000
      shares on May 30, 2009; 75,000 shares on May 30, 2010; and 75,000 shares
      on May 30, 2011.




(n)
            Includes
      options currently exercisable for a total of 1,418,332 shares of common
      stock.





SECTION 16(A) BENEFICIAL
OWNERSHIP REPORTING COMPLIANCE




Section 16(a) of the Exchange Act
(“Section 16(a)”) requires certain defined persons to file reports of and
changes in beneficial ownership of a security registered with the Securities and
Exchange Commission (the “Commission”) in accordance with the rules and
regulations promulgated by the Commission to implement the provisions of Section
16. Under the regulatory procedure, officers, directors, and persons who own
more than ten percent of a registered class of a company’s equity securities are
also required to furnish the Company with copies of all Section 16(a) forms they
file.





To the Company’s knowledge, based
solely on a review of the copies of Forms 3, 4 and 5, and all amendments
thereto, furnished to the Company with respect to its fiscal year ending
December 31, 2008, the Company’s officers, directors and greater than 10%
beneficial owners complied with all Section 16(a) filing requirements, except as
follows:  All five non-employee directors filed a late Form 4 for the
October 23, 2008 regarding rescission of a prior stock award.





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




CERTAIN RELATIONSHIPS OR
RELATED TRANSACTIONS




Presidium Energy,
LC





AOK
Energy LLC Purchase and Sale Agreement





In March 2006, we entered into a joint
venture agreement with certain unrelated parties.  The joint venture
covered the acquisition and development of oil and gas leases in various
counties located in Oklahoma.  The joint venture project was known as
the “Oak Tree Project.”  We participated in the joint venture through
a wholly owned subsidiary, AOK Energy, LLC (“AOK”).  Effective March
28, 2008, we entered into an Agreement for the Purchase and Sale of Limited
Liability Company Memberships with Presidium, which is wholly owned and operated
by John V. Miller, who served as our Vice President from November 1, 2005, until
he resigned on February 29, 2008.  Under the terms of the agreement,
we would sell to Presidium all of the outstanding member interests in AOK for a
purchase price that included the payment by Presidium of certain liabilities
that the operator alleged were owed by us to other participants in the joint
venture, a cash payment to us in the amount of $10,500,000, and an assignment to
us of a 3% overriding royalty in certain leases in the Oak Tree
Project.





Effective July 21, 2008, we amended the
Purchase and Sale of Limited Liability Company Memberships with Presidium (the
“First Amendment”) to extend Presidium’s exclusive right to purchase all of the
outstanding member interests in AOK until September 15, 2008.  In
exchange for the extension, Presidium made a $2.0 million non-refundable payment
to us.





Effective September 12, 2008, we
amended the Purchase and Sale of Limited Liability Company Memberships with
Presidium (the “Second Amendment”) increasing the purchase price to
$15,000,000.  The Second Amendment also required Presidium to pay us
another $1,000,000 in cash and execute a promissory note in the amount of
$12,000,000 (“Promissory Note”).  In order to induce us to enter into
the Second Amendment, Mr. Miller granted us an option to buy up to one million
membership units in Presidium for the sum of $0.50 per unit during the period
from six months to five years after closing.  If the Promissory Note
is repaid in full within the first six months after closing, our option to
purchase units in Presidium is null and void.  The sale of the
membership to Presidium closed effective September 15, 2008.


124


Under the
terms of the Promissory Note, Presidium is required to make monthly interest
only payments calculated at the lesser of the maximum rate allowed by law or
9.0%. As security for repayment of the Promissory Note, Presidium granted a
first priority security interest in all of AOK interests and delivered mortgages
on all oil and gas leases Presidium holds or will acquire in the Oak Tree
Project.  In the event Presidium plans to drill a well in the Oak Tree
Project, a principal payment on the Promissory Note equal to the amount of $400
per net acre of leases to be included in the drilling unit must be submitted to
us in order for us to subordinate any mortgages held on leases that fall within
the drilling unit.  Presidium shall be entitled to have outstanding
mortgage subordinations for no more than five undrilled well sites at any one
time.  The entire outstanding principal balance along with all accrued
interest is due September 10, 2010.  For the year ended December 31,
2008, we recorded $0.3 million of interest income related to the Promissory
Note.





Consulting
Agreement and Other





Effective May 20, 2008, we entered into
a consulting agreement with Presidium in which we agreed to provide Presidium
services in connection with certain oil and gas leasing, exploration,
development, and business projects.  This agreement expired December
31, 2008.  For the year ended December 31, 2008, we billed Presidium
$0.1 million for services rendered.





In the normal course of business we
engage in certain operational transactions with Presidium.  For the
year ended December 31, 2008, we sold inventory to Presidium in the amount of
$0.1 million and billed Presidium for lease bonus extensions in the amount of
$0.1 million.





Acadian
Energy, LLC





On
January 25, 2008, we announced the signing of a non-binding Letter of Intent to
acquire Acadian Energy, LLC (“Acadian”).   Acadian is jointly
owned and operated by John E. McDevitt and Gilbert A. Smith (60% and 40%
beneficial ownership, respectively).  The Letter of Intent was
terminated on October 1, 2008.





Operating
Agreements





Subsequent to us executing a Letter of
Intent with Acadian on June 24, 2008, we entered into an agreement with Acadian
to provide funding to maintain and preserve the value of Acadian’s properties
located in the State of Indiana pending our acquisition of
Acadian.  We agreed to advance approximately $83,000 pursuant to an
authority for expenditure to be used for the purpose of bringing wells into
compliance with the requirements of the State of Indiana and if practical, into
production.  We also agreed to pay certain legal expenses on behalf of
Acadian in connection with the proposed acquisition of Acadian.  The
agreement also stated if we did not acquire Acadian or its assets by October 1,
2008, Acadian would be required to reimburse us for the entire amount advanced
no later than October 1, 2009.





Effective April 1, 2008, we entered
into an agreement with Acadian to provide oil and gas operating services on
properties located in the State of Indiana.  This agreement expired
December 31, 2008. Under the terms of the agreement, we were not entitled to
monetary consideration.  Services were performed to maintain the value
of the properties prior to transfer of ownership from Acadian to
us.





For the year ended December 31, 2008,
we incurred expenses in the amount of $0.1 million under the operating
agreements with Acadian.  Due to the termination of the Letter of
Intent agreement with Acadian, amounts we incurred on behalf of Acadian in the
amount of $0.1 million were reimbursed to us at December 31, 2008, with the
exception of $21,899 which has been recorded as a receivable at December 31,
2008.





125


Simple
Financial Solutions, Inc.





Consulting
Agreements





Effective January 22, 2008, Barbara E.
Lawson was named Chief Financial Officer of the Company.  Simple
Financial Solutions, Inc., which is owned and operated by Ms. Lawson’s spouse,
provides consulting services on a continuous basis including to Bach Services
and Manufacturing Co., LLC, one of our subsidiaries.  For the year
ended December 31, 2008, Simple Financial Solutions, Inc. billed us $0.1 million
for services rendered.





Effective May 1, 2008, we entered into
a month-to-month agreement with Simple Financial Solutions, Inc. to provide
professional services for a subsidiary of the Company, Hudson Pipeline &
Processing Co., LLC (“HPPC”).  On a monthly basis, Simple Financial
Solutions, Inc. will be paid 2% of the gross revenues of HPPC and 3.5% of the
net income to HPPC before compensation.  Certain revenue resulting
from gas transportation will be excluded from the calculations.  For
the year ended December 31, 2008, we paid $0.1 million for services received
from Simple Financial Solutions, Inc. pursuant to this HPPC
agreement.





Disposition
of Membership Interest





Effective June 28, 2008, Lawson &
Kidd, LLC purchased a 2.5% membership interest in HPPC for $0.1
million.  Lawson & Kidd, LLC is solely owned by Barbara E. Lawson
who is our Chief Financial Officer and Ms. Lawson’s spouse.  Lawson
& Kidd, LLC’s interest will increase to 5% upon HPPC receiving income equal
to 125% of total costs spent on construction of the pipelines owned and operated
by HPPC.  For the year ended December 31, 2008, we received $0.1
million in capital call contributions from Lawson & Kidd, LLC and paid
Lawson & Kidd, LLC total distributions in the amount of
$20,002.  During March 2009, we repurchased the 2.5% membership
interest in HPPC from Lawson & Kidd, LLC for $0.1 million and we are
pursuing the repurchase of the remaining outside interest in
HPPC.





Other





Consulting
Agreements





Effective August 15, 2008, we entered
into a consulting agreement with Richard M. Deneau to provide advice and
services at an hourly rate of $125 (not to exceed $1,000 per day) in connection
with management’s negotiations with our existing bankers and the creation and
maintenance of new banking relationships.  For the year ended December
31, 2008, we paid $45,500 for consulting services received from Mr.
Deneau.





Interests
in Certain Properties





Effective
May 30, 2007, the Board of Directors named John C. Hunter as Vice President of
Exploration and Production.  He has worked for us since 2005 as Senior
Petroleum Engineer. Prior to that, Mr. Hunter was instrumental in certain
projects associated with our New Albany shale play. Over a series of agreements
with us, 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. We are 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, 2008, there is no production associated with this working interest
and development costs were approximately $13.3 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 (which has since merged into the
Company) 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.


126





William
Deneau, our CEO, and John Miller, who was an officer 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 we have an
interest but are operated by unrelated third parties.  During 2006,
these officers divested themselves of all interests for which we served as
operator.





ITEM
14.        PRINCIPAL ACCOUNTING FEES AND
SERVICES




Audit
Fees





The aggregate fees billed by Weaver for
professional services rendered for the audit of our 2008 financial statements
and for review of our quarterly financial statements for fiscal year 2008 were
$201,500.  The aggregate fees billed by Weaver for professional
services rendered for the audit of our 2007 financial statements and for reviews
of our quarterly financial statements for fiscal year 2007 included in one
post-effective amendment of two different SB-2 registration statements and two
different S-3 registration statements were $190,800.





Audit Related
Fees





There were no other fees billed by
Weaver during the last two fiscal years for assurance and related services that
were reasonably related to the performance of the auditor review of our
financial statements and not reported under “Audit Fees” above.





Tax Fees





There were no fees billed by Weaver
during the last two fiscal years for professional services rendered for tax
compliance, tax advice, and tax planning.





All Other
Fees





There were no other fees billed by
Weaver during 2008.





Audit Committee
Process





Our Audit Committee Charter requires
our Audit Committee to pre-approve all audit services provided by our
independent auditors and all non-audit services provided by our independent
auditors that are not eligible for the de minimus exception
contained in Section 10A of the Securities Exchange Act of 1934, as amended. Our
engagement of Weaver to perform our audit for the fiscal year ending December
31, 2008, was pre-approved by our Audit Committee consistent with the
requirements of the Charter.


127




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, 2008, and 2007


Consolidated
Statements of Operations for the Years Ended December 31, 2008, 2007, and
2006


Consolidated
Statements of Shareholders’ Equity for the Years Ended December 31, 2008, 2007,
and 2006


Consolidated
Statements of Cash Flows for the Years Ended December 31, 2008, 2007, and
2006


Notes to
Consolidated Financial Statements





(a)(2)
            Supplemental
      Information on Oil and Natural Gas Exploration, Development and Production
      Activities (unaudited)





(a)(3)
              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.)


128





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 (filed as Exhibit 10.18 to our Form 10-K as originally
      filed with the SEC on March 7, 2008, and incorporated herein by
      reference).10.19
              
              Forbearance
      Agreement and Amendment No. 1 to Credit Agreement dated June 2, 2008,
      among Aurora Oil & Gas Corporation, the Borrower, BNP Paribas, as
      Administrative Agent for the Lenders, the Lenders and the Secured Swap
      Providers. (filed as Exhibit 10.19 to our Form 8-K dated June 6, 2008,
      filed with the SEC on June 12, 2008, and incorporated herein by
      reference.)10.20
              
              Forbearance
      Agreement and Amendment No. 1 to Second Lien Term Loan Agreement dated
      June 2, 2008, among Aurora Oil & Gas Corporation, the Borrower, BNP
      Paribas, as Administrative Agent for the Lenders, and the Lenders (filed
      as Exhibit 10.20 to our Form 8-K dated June 6, 2008, filed with the SEC on
      June 12, 2008, and incorporated herein by reference.)10.21
              
              Forbearance
      Agreement dated February 12, 2009, among Aurora Oil & Gas Corporation,
      as Borrower, BNP Paribas, as Administrative Agent for the Lenders, and the
      Lenders.  (filed as Exhibit 10.21 to our Form 8-K dated February
      12, 2009, filed with the SEC on February 18, 2009, and incorporated herein
      by reference.)14.1
              
              Code
      of Conduct and Ethics (updated 2/1/08) (filed as Exhibit 14.1 to our Form
      10-K as originally filed with the SEC on March 7, 2008, and incorporated
      herein by reference).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, L.L.P.*23.3
              
              Consent
      of Schlumberger Technology Corporation.*23.4
              
              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.


129


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 CORPORATIONDate:  March
      13, 2009
              By:
              /s/
      William W. DeneauName:       William
      W. DeneauTitle:          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
      13, 2009William
      W. Deneau
                  
                  Director
      (Principal Executive Officer)/s/ Barbara E. Lawson
                  
                  Chief
      Financial Officer
                  
                  March
      13, 2009Barbara
      E. Lawson
                  
                  (Principal
      Financial Officer andPrincipal
      Accounting Officer)/s/ Gilbert A. Smith
                  
                  President
                  
                  March
      13, 2009Gilbert
      A. Smith/s/ Richard M. Deneau
                  
                  Director
                  
                  March
      13, 2009Richard
      M. Deneau/s/ Gary J. Myles
                  
                  Director
                  
                  March
      13, 2009Gary
      J. Myles/s/ Wayne G.
Schaeffer
                  
                  Director
                  
                  March
      13, 2009Wayne
      G. Schaeffer/s/ Kevin D. Stulp
                  
                  Director
                  
                  March
      13, 2009Kevin
      D. Stulp/s/ Earl V. Young
                  
                  Director
                  
                  March
      13, 2009Earl
      V. Young/s/ John E. McDevitt
                  
                  Director
                  
                  March
      13, 2009John
      E. McDevitt




130