Aurora Oil & Gas Corporation Announces Year-End 2008 Results

TRAVERSE CITY, Mich., March 13  /PRNewswire-FirstCall/ -- Aurora Oil & Gas Corporation (NYSE Alternext US: AOG) today reported a net loss of $107.4 million for the year ended December 31, 2008, largely related to one-time non-cash items.

William W. Deneau, Chairman and Chief Executive Officer, commented, "This has been a challenging year for our business and the economy at large.  When we entered 2008, we anticipated a favorable conclusion to our strategic alternatives process.  Instead, the year presented a strong headwind of limited capital resources, global credit challenges, and weakening energy markets.  I believe 2009 will present more of the same.  Fortunately, our team has been working to 'batten down the hatches' since the beginning of 2008 and we will continue working diligently to weather this storm."

2008 Financial Review

Oil and natural gas production revenues totaled $25.2 million on sales of over 3 billion cubic feet of natural gas equivalent (Bcfe) for the year.  This equates to an average of 8.3 million cubic feet of natural gas equivalent (Mmcfe) per day, a decrease of approximately 5% from the previous year.  The weighted average sales price of $8.28 for the year includes a loss of $3.5 million in realized losses on natural gas hedges.

Excluding one-time non-cash items, expenses totaled $39.3 million, a 35% increase from 2007.  Production and lease operating expenses ("LOE") increased 19% as a result of increased energy costs, general maintenance across a larger base of properties, and repairs and workover charges related to Aurora's 2008 well enhancement program.  General and administrative costs increased by 13% from 2007, primarily as a result of additional legal and consulting services related to Aurora's refinancing and various restructuring efforts.  Also, interest expense more than doubled from 2007, due to higher utilization of debt and higher interest charges from Aurora's defaulted status.

One-time non-cash items were related to an impairment of goodwill and a ceiling-test write-down of oil and gas properties.  The Company recorded $16 million in goodwill impairment related to the reverse merger of Cadence Resources Corporation, completed in 2005, and $3.4 million related to the acquisition of Bach Services and Manufacturing Company, completed in 2006.  These are determined to be impaired based upon the estimated market value of the assets acquired in the transactions.

A ceiling-test write-down of oil and natural gas reserves in the amount of $78.5 million was recorded as a result of the application of the "ceiling test" under the full cost method of accounting.  Under full cost accounting requirements, 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 proved reserves plus the lower of cost or fair value of unproved 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.  The impairment is driven by changes in the Company's base of proved reserves, as discussed in the "Update on Proved Reserves", below.

Including all items, the net loss totaled $107.4 million or ($1.04) per basic and diluted share for the year ended December 31, 2008, as compared to a net loss of $4.4 million or ($0.04) per basic and diluted share for the same period in 2007.

Complete detail on the financial results can be found in the Company's Form 10-K filed March 13, 2009.  This form can be retrieved from the Securities and Exchange Commission or via the Company website at http://www.auroraogc.com/SEC_Filings.htm.  Selected annual and quarterly historical financial data are provided for reference below.

Update on Acreage

Aurora's acreage portfolio decreased by approximately 8.5% during 2008.  The change was the result of several transactions involving the sale or trade of undeveloped properties.  The most significant change was related to the sale of Aurora's interest in its Oklahoma properties.  The sale was completed in September 2008 and decreased leasehold by approximately 37,000 net acres, as reflected in the table below.  There were also certain less-prospective locations on which the leases were allowed to expire.

Following is a summary of the Company's entire acreage inventory on December 31, 2008 and December 31, 2007.

  Acreage by Play/Trend                    2008                2007
                                     Gross       Net     Gross       Net
  Michigan Antrim Shale            286,390   134,003   310,141   154,643
  New Albany Shale                 787,595   449,183   833,365   441,351
  Woodford Shale                         0         0    37,325    12,785
  Other                             90,475    68,203   102,352    81,112
  Total                          1,164,460   651,389 1,283,183   712,215




During 2009, Aurora will continue to optimize its portfolio of acreage.  The Company will focus on developing its portfolio via partnerships with other operators and allowing less-prospective acreage positions to expire.  This will allow the Company to focus its resources on the best potential locations for development.

2008 Drilling Activities

Aurora's capital constraints and slow-down by its operating partners caused drilling activity to be significantly reduced - from 101 gross (59.13 net) wells in 2007 to 26 gross (6.12 net) wells in 2008.  Of the wells participated in, 14 (2.80 net) wells were in the Antrim shale, no wells were in the New Albany shale, and 12 (3.32 net) wells were drilled in Other project areas.  A summary of 2008 drilling activity is provided below:

  Drilling Activities -
   FY 2008             Operated          Non-Operated            Total
                    Gross      Net      Gross      Net      Gross      Net
  Producing            0      0.00         1      0.72         1      0.72
  Waiting on Hook-Up   0      0.00        16      3.40        16      3.40
  Resource Assessment  0      0.00         6      0.97         6      0.97
  Dry                  0      0.00         3      1.03         3      1.03
  Total                0      0.00        26      6.12        26      6.12


  The Company's inventory of wells at the end of 2008 is as follows:



  Well Status as of December 31,
   2008                               Antrim Operated  Antrim Non-Operated
                                     Gross       Net     Gross       Net
  Producing                            177    168.15       390     93.74
  Waiting on Hook-Up                     0      0.00        24      4.80
  Res. Assessment                        1      0.97         9      1.87
  Total                                178    169.12       423    100.41



  Well Status as of December 31,
   2008                            New Albany Operated   New Albany Non-
                                                             Operated
                                     Gross       Net     Gross       Net
  Producing                              0      0.00        25      1.25
  Waiting on Hook-Up                     6      6.00         0      0.00
  Res. Assessment                        0      0.00         0      0.00
  Total                                  6      6.00        25      1.25




  Well Status as of December 31,
   2008                                   Other                Total
                                     Gross       Net     Gross       Net
  Producing                             36     18.35       628    281.49
  Waiting on Hook-Up                     1      0.10        31     10.90
  Res. Assessment                       10      4.00        20      6.84
  Total                                 47     22.45       679    299.23




Many companies in the oil and gas industry have cited pricing issues for slowdown in development of properties.  Though Aurora has other challenges as well, the case is no different with Aurora and its operating partners.  Without a change in the broader energy markets, the Company does not expect development in 2009 greater than what was experienced in 2008.

2008 Production Activities

Total company production during 2008 averaged 8.3 net Mmcfe per day, a 5% decrease from the previous year.  A summary of production for 2008 and 2007 is provided below:

  Estimated Production by Play/
   Trend (net mcfe)                        2008                 2007
                                   Total       Daily     Total       Daily
                                              Average               Average
    Antrim Shale                 2,789,727     7,622   2,975,715     8,153
    New Albany Shale               100,678       275      57,186       157
    Other                          153,707       420     174,254       477
  Total                          3,044,112     8,317   3,207,155     8,787
    Operated                     1,924,947     5,259   2,292,429     6,281
    Non-operated                 1,119,165     3,058     914,726     2,506
  Total                          3,044,112     8,317   3,207,155     8,787




During 2008, Aurora attempted to address its declining operated production.  Faced with minimal available capital, efforts to proactively address production declines were limited.  Beginning October 1, 2008, production sales are subject to market fluctuations, resulting in property gross margins declining with falling natural gas prices.  This further limits Company spending on production enhancement efforts.  Nonetheless, Aurora management is working to review various alternatives presented by its engineering team and consulting experts, which may address the declining production.

Update on Proved Reserves

Aurora's year-end 2008 proved reserves decreased 41% from year-end 2007 to 98 Bcfe. Of the 98 Bcfe, approximately 56% is considered proved developed, of which 17% is behind pipe or waiting on hook-up.  The remaining 27% of total proved reserves is considered proved undeveloped.  With respect to proved reserves by property location, 71.1 Bcf is in the Antrim shale, 26 Bcf is in the New Albany shale, and 1 Bcfe is held in Other project areas.

  A summary of the proved reserves reconciliation is provided below:


  Reconciliation of Reserves               Proved Reserves (Bcfe)
  Proved Reserves as of December 31, 2007         166.6
  Revisions of previous estimates                 -68.3
  Extensions and discoveries                        2.8
  Production                                       -3.0
  Proved Reserves as of December 31, 2008          98.1



The significant revision in previous estimates was driven by the use of production data from the Company's Antrim shale projects to estimate reserves. Aurora's Antrim shale reserves have historically been determined by our third-party reserve engineers using type curves derived from a combination of reservoir simulation and nearby production performance from more mature Antrim shale units operated by others.  Now that sufficient historical data is available to develop decline curves for Aurora's wells, the 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.  This not only affected the proved developed producing reserves, but also the type curves used for proved undeveloped reserves.  Additional impacts to the reserve base were the result of capital constraints, regulatory concerns on some of Aurora's northernmost properties, and lower market prices for oil and natural gas.

After integrating these impacts and using price levels required by the SEC (an average natural gas price of $6.07 per mcf, as compared to $7.18 per mcf in 2007), Aurora's pre-tax PV-10 decreased 64%, from $190 million in 2007 to $68.6 million in 2008.  If the benefit of Aurora's pipeline ownership were included in the SEC evaluation, the PV-10 would improve by $9.2 million for a total pre-tax PV-10 value of $77.8 million.

Management Comments

Mr. William W. Deneau commented further on Aurora's activities and prospects:

"Currently, we are focused on meeting the obligations of our forbearance agreement as well as working with our lenders to develop a collaborative solution to our situation.  Given the challenging economic times, we cannot predict when our situation will be resolved.  However, we will continue to adapt to our changing environment by quickly making the necessary changes to our business to enhance operational efficiency and drive down controllable costs.  With diligence, time, and improvement in the markets in which we work, we expect to not only survive, but thrive in what we still believe to be the most important industry in the world."

Selected Financial Data

The following table sets forth Aurora's quarterly unaudited statement of operations for the quarter ended December 31, 2008 and September 30, 2008, respectively. You should review this information together with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the audited consolidated financial statements and related notes included in Aurora's Form 10-K for the year ending December 31, 2008.

                                                Three Months Ended
                                          December 31,     September 30,
                                              2008              2008
  Statement of operations data
  Revenues
    Oil and natural gas sales              $4,306,161        $7,657,965
    Pipeline transportation and marketing     176,815           215,540
    Field service and sales                 1,057,145         1,280,206
    Interest and other income                 427,197           205,983
      Total revenue                         5,967,318         9,359,694
  Expenses
    Production taxes                          219,939           376,381
    Production and lease operating
     expenses                               2,131,907         2,557,330
    Pipeline and processing operating
     expenses                                 147,641           179,977
    Field services expense                    884,999           977,235
    General and administrative expenses     2,506,467         2,770,028
    Oil and natural gas depletion and
     amortization                           2,597,539           874,426
    Other assets depreciation and
     amortization                             342,859           265,040
    Interest expense                        3,952,227         2,023,411
    Ceiling write-down of oil and gas
     properties                            78,457,801                 -
    Goodwill impairment                     3,399,918        15,973,346
    Taxes, other                               93,912            29,005
      Total expenses                       94,735,209        26,026,179
  Loss before minority interest           (88,767,891)      (16,666,485)
  Minority interest in income of
   subsidiaries                               (17,605)          (28,385)
  Net loss                               $(88,785,496)     $(16,694,870)
  Net loss per common share - basic
   and diluted                                 $(0.86)           $(0.16)


  Selected Historical Financial Data



The following tables set forth our December 31, 2008, 2007, and 2006, 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, and 2006, 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 in our Form 10-K for the year ending December 31, 2008.

  Statement of Operations Data             2008        2007        2006
  Revenues:
     Oil and natural gas sales         $25,201,777 $26,723,818 $21,591,811
     Pipeline 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
        Total revenues                  29,840,934  28,491,388  22,427,487

  Expenses:
     Production taxes                    1,338,397   1,123,070     877,319
     Production and lease operating
      expense                            9,995,981   8,424,096   5,966,341
     Pipeline 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
     Oil and natural gas depletion
      and amortization                   5,380,106   3,769,104   2,681,290
     Other assets depreciation and
      amortization                       1,193,993   2,396,026   2,083,191
     Interest expense                    9,201,343   4,582,021   4,573,785
     Ceiling 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     250,884
       Total expenses                  137,127,457  32,595,380  24,321,236
  Loss before minority interest       (107,286,523) (4,353,992) (1,893,749)
  Minority interest in (income)
   loss 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

  Cash Flow Data
  Cash provided by (used in) operating
   activities                           $4,098,818 $10,079,049  $5,467,910
  Cash used by investing activities    (10,701,427)(61,100,489)(89,606,098)
  Cash provided by financing
   activities                           14,182,069  51,711,722  73,892,946


                                                As of December 31,
  Balance Sheet Data                          2008              2007
  Cash and cash equivalents              $ 10,005,138       $ 2,425,678
  Other current assets                      5,411,250         8,901,774
  Oil and natural gas properties, net
   (using full cost accounting)           116,426,381       209,818,344
  Other property and equipment, net        14,451,523        10,365,599
  Other assets                             13,906,789        23,160,273
       Total assets                      $160,201,081      $254,671,668

  Current liabilities                    $127,312,547       $ 8,580,990
  Long-term debt, net of current
   maturities                               5,265,459       113,835,028
  Minority interest in nets assets of
   subsidiaries                               467,937       112,661
  Shareholders' equity                     27,155,138       132,142,989
       Total liabilities and shareholders'
        equity                           $160,201,081      $254,671,668


  About Aurora Oil & Gas Corporation



Aurora Oil & Gas Corporation is an independent energy company focused on unconventional natural gas exploration, acquisition, development and production with its primary operations in the Antrim Shale of Michigan and the New Albany Shale of Indiana and Kentucky.

Cautionary Note on Forward-Looking Statements

Statements regarding future events, occurrences, circumstances, activities, performance, outcomes, beliefs and results, including future revenues, renegotiation of existing credit facilities, the procurement of new credit facilities, the continued forbearance and future relations with our existing lenders, anticipated capital availability, anticipated capital expenditures, estimated reserve values, anticipated partnerships with other operators, activities intended to address declining production, expected improvement in the domestic or global economies, anticipated improvement in energy prices, drilling results, and plans for future growth through drilling and production are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Although we believe that the forward-looking statements described are based on reasonable assumptions, we can give no assurance that they will prove accurate. Important factors that could cause our actual results to differ materially from those included in the forward-looking statements include the timing and extent of changes in commodity prices for oil and gas, drilling and operating risks, the availability of drilling rigs, changes in laws or government regulations, unforeseen engineering and mechanical or technological difficulties in drilling the wells, operating hazards, weather-related delays, the loss of existing credit facilities, availability of capital, and other risks more fully described in our filings with the Securities and Exchange Commission. All forward-looking statements contained in this release, including any forecasts and estimates, are based on management's outlook only as of the date of this release and we undertake no obligation to update or revise these forward-looking statements, whether as a result of subsequent developments or otherwise.

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          Jeffrey W. Deneau, Investor Relations
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          http://www.auroraogc.com/

DATASOURCE: Aurora Oil & Gas Corporation



CONTACT:  Jeffrey W. Deneau, Investor Relations, Aurora Oil & Gas

Corporation, [phone]



Web Site:  http://www.auroraogc.com/ 

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