SOURCE: Venoco, Inc.

Venoco, Inc.

February 22, 2011 05:02 ET

Venoco, Inc. Announces 2010 4th Quarter and Full-Year Financial and Operational Results

DENVER, CO--(Marketwire - February 22, 2011) - Venoco, Inc. (NYSE: VQ)

  • 2010 Net Income of $68 Million; Adjusted Earnings of $43 Million
  • Full-year 2010 Production of 6.7 Million BOE or 18,241 BOE/d
  • Average Lifting Costs of $12.65 per BOE

Venoco, Inc. (NYSE: VQ) today reported financial and operational results for the fourth quarter and full-year 2010. The company reported net income for the year of $68 million. Total revenues for the year were $295 million, realized commodity derivative gains were $54 million, and unrealized commodity derivative gains were $39 million.

Adjusted Earnings, which adjusts for unrealized derivative gains and losses and certain one-time charges were $43 million for the year, up from $31 million for 2009, primarily as a result of higher commodity prices realized throughout 2010. Adjusted EBITDA was $218 million in 2010, up 10% from $198 million for 2009. Please see the end of this release for definitions of Adjusted Earnings and Adjusted EBITDA and a reconciliation of those measures to net income/loss.

Highlights for 2010 included the following:

  • Production of 6.7 million barrels of oil equivalent (MMBOE) for the year or 18,241 BOE per day (BOE/d).
  • Lifting costs remained flat with 2009 levels, averaging $12.65 per BOE in 2010.
  • Paid down debt $61MM during year while building onshore Monterey shale asset.
  • Proved reserves of 85.1 MMBOE as of December 31, 2010, relatively flat with year-end 2009 proved reserves when adjusted for production and asset sales.

"Last year we invested in the science of the onshore Monterey shale and I'm pleased with the progress we've made in that area. I'm also happy with the results we saw from focusing on costs at our legacy assets. We were able to beat our LOE guidance while keeping production within 2% of guidance," said Tim Marquez, Venoco's Chairman and CEO. "We believe we've made good progress advancing the science in 2010 on the Monterey shale, and see 2011 as the year we begin to execute on the development."

Fourth Quarter and Full-Year Production

Production in the fourth quarter of 2010 of 17,328 BOE/d was down 4% from the third quarter of 2010 and down 7% from the fourth quarter of 2009 (pro forma for the sale of the company's producing Texas assets). Fourth quarter production was negatively impacted by mechanical failures and heavy rains that delayed projects.

"As we previously announced, we had a number of relatively minor issues in 2010 that in total caused us to slightly miss our annual production guidance," commented Mr. Marquez. "The new year is off to a good start. Production from our legacy Southern California assets has recovered from a dip in the fourth quarter. We expect our production from those assets and the Sacramento Basin to be relatively flat in 2011 and that production growth will come from our planned onshore Monterey shale drilling," added Mr. Marquez.

The following table details the company's daily production by region (BOE/d):

                                                              Full Year
                                                          -----------------
Region                       4Q 2009   3Q 2010   4Q 2010    2009     2010
                            --------- --------- --------- --------- -------
Sacramento Basin               10,227    10,284    10,163    10,230  10,033
                            --------- --------- --------- --------- -------
Southern California             8,354     7,803     7,165     8,523   7,745
                            --------- --------- --------- --------- -------
Texas                           1,498         -         -     1,869     463
                            --------- --------- --------- --------- -------
   Total                       20,079    18,087    17,328    20,622  18,241
                            ========= ========= ========= ========= =======

Fourth Quarter and Full-Year Costs

Venoco's fourth quarter 2010 lease operating expenses of $12.61 per BOE were up slightly from $12.44 per BOE in the third quarter due primarily to lower production levels in the fourth quarter compared to the third quarter. The company's full-year 2010 lease operating expenses of $12.65 per BOE were below the company's guidance of $13.00 per BOE.

                        Quarter Ended             Year Ended
                  --------------------------- ------------------- Full Year
UNAUDITED (per                                                      2010
 BOE)             12/31/09  9/30/10 12/31/10  12/31/09  12/31/10  Guidance
                  --------- ------- --------  --------- --------- ---------
Lease Operating
 Expenses         $   12.85 $ 12.44 $   12.61 $   12.65 $   12.65 $   13.00
Production/
 Property Taxes        0.72    1.05      0.87      1.35      1.01      1.15
DD&A Expense          11.35   11.70     12.74     11.46     11.79     12.00
G&A Expense (1)        5.49    4.31      4.93      4.63      4.78      4.70
Interest Expense
 (2)                   8.64    9.08      9.46      8.28      9.17      8.10
                  --------- ------- --------- --------- --------- ---------
  Total           $   39.05 $ 38.58 $   40.61 $   38.37 $   39.40 $   38.95
                  ========= ======= ========= ========= ========= =========

(1) Net of amounts capitalized and excluding stock-based compensation costs
    and Texas severance costs.  See the end of this release for a
    reconciliation of G&A per BOE.
(2) Includes interest expense, realized (gain) loss on interest rate swap 
    and amortization of deferred loan fees.

Capital Investment 2010

Venoco's 2010 capital expenditures for development and other spending were $218 million, including $158 million for drilling and rework activities, $12 million for facilities, and the remaining $48 million for land, seismic and capitalized G&A costs. In addition, the company also spent $2 million for acquisitions of proved properties targeting the onshore Monterey shale formation. Total costs incurred in 2010 for the company's E&P operations were $215 million (including a reduction in asset retirement obligations of $5 million).

In 2010 the company spent $104 million or 47% of its capital expenditures in the Sacramento Basin. The company spud 93 wells, completed 75 wells, performed 213 recompletions, and hydraulically fractured 12 wells in the basin during 2010. The company plans to reduce activity levels in the basin in 2011 as a result of depressed natural gas prices and the company's increased focus on oil-based Monterey shale activities. The company's 2011 capital expenditure budget for the Sacramento Basin of $60 million includes 40 wells, 220 recompletions, and 20 hydraulic fractures. The company identified several anomalies from 3D seismic data on lands it acquired in 2009 and drilled a successful discovery well in December on one of these anomalies -- it is an extension of the Grimes field and tested at a rate of about 2 million cubic feet per day. The company has two additional locations on this anomaly that it plans to drill later this year. It recently TD'd a well on a second anomaly that appears to be another good well, and plans to drill a well on a third anomaly this spring. The company expects 2011 activity levels to result in average daily production in 2011 that is roughly flat compared to 2010 average daily production; however production is expected to decline throughout the year as a result of the lower activity.

The company's Southern California legacy fields accounted for $39 million or 18% of its 2010 capital expenditures. Projects completed during the year include the completion of two wells at the West Montalvo field and a dual-completion well at the Sockeye field that produces from the Monterey shale formation and enhances the sweep of the field's waterflood by injecting water into the Upper Topanga formation. At the South Ellwood field, the company performed six recompletions and continued work to advance the permitting process for the field's proved undeveloped locations and performed facilities work required to begin drilling those locations. The company's 2011 capital expenditure budget of $40 million for legacy Southern California properties includes plans to drill four wells and perform additional recompletions in order to keep average daily production in 2011 relatively flat with 2010 average daily production.

The company significantly increased its capital expenditures on its onshore Monterey shale development in 2010, spending approximately $74 million or 34% of its 2010 capital expenditures on the emerging play. The company spud 11 gross wells during the year including seven vertical "science" wells and four horizontal wells. The company completed the first half of the joint 3D seismic shoot over its acreage in the San Joaquin Basin during 2010. The company's 2011 capital expenditure budget for the onshore Monterey shale development is $100 million; however, the company may allocate additional capital to the Monterey shale program as the year progresses.

"Our 2010 drilling program in the Monterey was focused on gathering core and log data, to better understand reservoir behavior in some of our prospect areas," commented Mr. Marquez. "With the vertical wells we drilled in 2010, we have been able to de-risk a portion of our acreage by identifying pay intervals. We will continue the data gathering in additional prospects while being very focused on optimizing our drilling and completion efforts in 2011."

Reserves Review

As previously announced, the company's proved oil and gas reserves as of December 31, 2010 were 85.1 MMBOE using SEC benchmark pricing. Year-end 2010 reserves were relatively flat with year-end 2009 reserves, net of production and pro forma for the second quarter 2010 sale of Texas assets and the December sale of the Gato Ridge field. Though permitted by new SEC guidance regarding oil and gas reserves, the company's year-end reserve report did not utilize statistical methods for booking undeveloped oil and gas reserves; rather, the methodologies used were consistent with those used in prior years.

The pre-tax PV-10 of the company's reserves using SEC pricing of $79.43 per barrel for oil and $4.38 per MMBTU for gas is $1.1 billion. The company's estimate of reserves using a year-end NYMEX 5-year forward strip pricing is 86.1 MMBOE, with a pre-tax PV-10 of $1.6 billion. See the end of this release for a reconciliation of PV-10 to a standardized measure of discounted future net cash flows.

Balance Sheet & Liquidity

In February 2011, Venoco completed two capital raising transactions which provided additional liquidity. First, the company issued 4.0 million shares of common stock and received net proceeds of approximately $71.4 million from the sale of the shares after deducting estimated offering related expenses. Second, the company issued $500 million of 8.875% senior unsecured notes, which are due in February 2019. The company received net proceeds of approximately $489.7 million from the transaction after deducting offering related expenses. The proceeds from the two transactions were used to repay the outstanding principal and accrued interest related to the company's second lien term loan, settle the related interest rate swap contracts and fully repay the outstanding balance on the company's revolving credit facility. Estimated remaining cash on hand from the transactions after the indicated uses of proceeds and estimated offering related expenses was $21.1 million.

"We are extremely pleased with the re-financing and resulting enhanced liquidity -- we replaced secured debt and the interest rate swap that had us locked in at about 8% with the unsecured debt at 8.875% while extending the maturity almost five years to 2019," said Mr. Marquez. "We were able to pay our revolver balance down to zero and we have cash on hand."

The company expects to fund its 2011 capital expenditure budget of approximately $200 million primarily with cash flow from operations, supplemented with borrowings under its revolving credit facility and proceeds from the equity transaction completed in February 2011. Additionally, the company continues to pursue joint venture transactions related to its Monterey shale development project.

2011 Guidance

The following summarizes the company's 2011 guidance:

  • Production: 19,500 BOE/d
  • Capital Budget: $200 million
  • Lease Operating Expenses: $14.25 per BOE
  • G&A Expenses (excluding stock-based compensation): $4.75 per BOE
  • DD&A: $13.00 per BOE

Earnings Conference Call

Venoco will host a conference call to discuss results today, Tuesday, February 22, 2011 at 11:00 a.m. Eastern time (9 a.m. Mountain). The conference call will be webcast and those wanting to listen may do so by using a link on the Investor Relations page of the company's website at http://www.venocoinc.com. Those wanting to participate in the Q & A portion can call (866) 730-5763 and use conference code 34915104. International participants can call (857) 350-1587 and use the same conference code.

A replay of the conference call will be available for one week by calling (888) 286-8010 or, for international callers, (617) 801-6888, and using passcode 37030244. The replay will also be available on the Venoco website for 30 days.

The company will post slides on the Investor Relations page of its website today prior to the call.

About the Company

Venoco is an independent energy company primarily engaged in the acquisition, exploitation and development of oil and natural gas properties primarily in California. Venoco operates three offshore platforms in the Santa Barbara Channel, has non-operated interests in three other platforms, operates three onshore properties in Southern California, and has extensive operations in Northern California's Sacramento Basin.

Forward-looking Statements

Statements made in this news release relating to Venoco's future production, expenses, capital expenditures and development projects, the expected rate of return on drilling projects and all other statements except statements of historical fact, 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. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management's assumptions and the company's future performance are both subject to a wide range of business risks and uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including, but not limited to, the timing and extent of changes in oil and gas prices, the timing and results of drilling and other development activities, the availability and cost of obtaining drilling equipment and technical personnel, risks associated with the availability of acceptable transportation arrangements and the possibility of unanticipated operational problems, delays in completing production, treatment and transportation facilities, higher than expected production costs and other expenses, and pipeline curtailments by third parties. The company's activities with respect to the onshore Monterey Shale and other projects are subject to numerous operating, geological and other risks and may not be successful. The company's results in the onshore Monterey Shale will be subject to greater risks than in areas where it has more data and drilling and production experience. Results from the company's onshore Monterey Shale project will depend on, among other things, its ability to identify productive intervals and drilling and completion techniques necessary to achieve commercial production from those intervals. All forward-looking statements are made only as of the date hereof and the company undertakes no obligation to update any such statement. Further information on risks and uncertainties that may affect the Company's operations and financial performance, and the forward-looking statements made herein, is available in the company's filings with the Securities and Exchange Commission, which are incorporated by this reference as though fully set forth herein.

                   OIL AND NATURAL GAS PRODUCTION AND PRICES


                         Quarter Ended               Quarter Ended
                  ---------------------------  ---------------------------
                                                                      %
UNAUDITED         9/30/10  12/31/10  % Change  12/31/09  12/31/10  Change
                  -------  --------  --------  --------  --------  -------
Production
 Volume:
Oil (MBbls) (1)       682       629        -8%      809       629      -22%
Natural Gas
 (MMcf)             5,892     5,791        -2%    6,230     5,791       -7%
                  -------  --------  --------  --------  --------  -------
MBOE                1,664     1,594        -4%    1,847     1,594      -14%
                  =======  ========  ========  ========  ========  =======
Daily Average
 Production
 Volume:
Oil (Bbls/d)        7,413     6,837        -8%    8,793     6,837      -22%
Natural Gas
 (Mcf/d)           64,043    62,946        -2%   67,717    62,946       -7%
                  -------  --------  --------  --------  --------  -------
BOE/d              18,087    17,328        -4%   20,079    17,328      -14%
                  =======  ========  ========  ========  ========  =======
Oil Price per
 Barrel Produced
 (in dollars):
Realized price
 before hedging   $ 65.88  $  74.58        13% $  64.33  $  74.58       16%
Realized hedging
 gain (loss)        (1.28)    (3.02)      136%   (10.07)    (3.02)     -70%
                  -------  --------  --------  --------  --------  -------
Net realized
 price            $ 64.60  $  71.56        11% $  54.26  $  71.56       32%
                  =======  ========  ========  ========  ========  =======
Natural Gas Price
 per Mcf (in
 dollars):
Realized price
 before hedging   $  3.93  $   3.96         1% $   4.59  $   3.96      -14%
Realized hedging
 gain (loss)         1.99      2.15         8%     2.06      2.15        4%
                  -------  --------  --------  --------  --------  -------
Net realized
 price            $  5.92  $   6.11         3% $   6.65  $   6.11       -8%
                  =======  ========  ========  ========  ========  =======
Expense per BOE
 (in dollars):
Lease operating
 expenses         $ 12.44  $  12.61         1% $  12.85  $  12.61       -2%
Production and
 property taxes   $  1.05  $   0.87       -17% $   0.72  $   0.87       21%
Transportation
 expenses         $  1.65  $   1.64        -1% $   0.81  $   1.64      102%
Depreciation,
 depletion and
 amortization     $ 11.70  $  12.74         9% $  11.35  $  12.74       12%
General and
 administrative
 (2)              $  4.97  $   5.72        15% $   5.83  $   5.72       -2%
Interest expense  $  6.08  $   6.30         4% $   5.79  $   6.30        9%




                           Year Ended
                  ----------------------------
UNAUDITED         12/31/09  12/31/10  % Change
                  --------  --------  --------
Production
 Volume:
Oil (MBbls) (1)      3,402     2,792       -18%
Natural Gas
 (MMcf)             24,748    23,196        -6%
                  --------  --------  --------
MBOE                 7,527     6,658       -12%
                  ========  ========  ========
Daily Average
 Production
 Volume:
Oil (Bbls/d)         9,321     7,649       -18%
Natural Gas
 (Mcf/d)            67,803    63,551        -6%
                  --------  --------  --------
BOE/d               20,622    18,241       -12%
                  ========  ========  ========
Oil Price per
 Barrel Produced
 (in dollars):
Realized price
 before hedging   $  50.60  $  68.86        36%
Realized hedging
 gain (loss)         (0.95)    (1.77)       86%
                  --------  --------  --------
Net realized
 price            $  49.65  $  67.09        35%
                  ========  ========  ========
Natural Gas Price
 per Mcf (in
 dollars):
Realized price
 before hedging   $   3.84  $   4.34        13%
Realized hedging
 gain (loss)          2.58      1.70       -34%
                  --------  --------  --------
Net realized
 price            $   6.42  $   6.04        -6%
                  ========  ========  ========
Expense per BOE
 (in dollars):
Lease operating
 expenses         $  12.65  $  12.65         0%
Production and
 property taxes   $   1.35  $   1.01       -25%
Transportation
 expenses         $   0.42  $   1.37       226%
Depreciation,
 depletion and
 amortization     $  11.46  $  11.79         3%
General and
 administrative
 (2)              $   4.91  $   5.64        15%
Interest expense  $   5.44  $   6.10        12%

(1)  Amounts shown are oil production volumes for offshore properties and
     sales volumes for onshore properties (differences between onshore
     production and sales volumes are minimal). Revenue accruals are
     adjusted for actual sales volumes since offshore oil inventories
     can vary significantly from month to month based on the timing of
     barge deliveries, oil in tanks and pipeline inventories, and oil
     pipeline sales nominations.
(2)  Net of amounts capitalized.



             CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


                   Quarter Ended      Quarter Ended         Year Ended
                 -----------------  ------------------  ------------------
UNAUDITED (In
 thousands)      9/30/10  12/31/10  12/31/09  12/31/10  12/31/09  12/31/10
                 -------  --------  --------  --------  --------  --------
REVENUES:
Oil and natural
 gas sales       $68,905  $ 71,275  $ 79,715  $ 71,275  $267,163  $290,608
Other              1,507       791       784       791     3,331     4,684
                 -------  --------  --------  --------  --------  --------
Total revenues    70,412    72,066    80,499    72,066   270,494   295,292
                 -------  --------  --------  --------  --------  --------
EXPENSES:
Lease operating
 expense          20,707    20,103    23,728    20,103    95,213    84,255
Production and
 property taxes    1,742     1,387     1,333     1,387    10,128     6,701
Transportation
 expense           2,750     2,613     1,487     2,613     3,163     9,102
Depletion,
 depreciation
 and
 amortization     19,475    20,313    20,961    20,313    86,226    78,504
Accretion of
 asset
 retirement
 obligation        1,518     1,592     1,591     1,592     5,765     6,241
General and
 administrative    8,264     9,119    10,775     9,119    36,939    37,554
                 -------  --------  --------  --------  --------  --------
Total expenses    54,456    55,127    59,875    55,127   237,434   222,357
                 -------  --------  --------  --------  --------  --------
Income from
 operations       15,956    16,939    20,624    16,939    33,060    72,935
FINANCING COSTS
 AND OTHER:
Interest expense  10,117    10,045    10,702    10,045    40,984    40,584
Interest rate
 derivative
 realized
 (gains) losses    4,495     4,531     4,628     4,531    18,479    18,094
Interest rate
 derivative
 unrealized
 (gains) losses    6,553    (9,561)   (1,643)   (9,561)   (1,803)   13,724
Amortization of
 deferred loan
 costs               499       507       638       507     2,862     2,362
Loss on
 extinguishment
 of debt               -         -     7,911         -     8,493         -
Commodity
 derivative
 realized
 (gains) losses  (10,863)  (29,632)   (4,681)  (29,632)  (68,429)  (53,501)
Commodity
 derivative
 unrealized
 (gains) losses
 and
 amortization of
 derivative
 premiums        (10,033)   37,514    20,923    37,514    94,172   (14,548)
                 -------  --------  --------  --------  --------  --------
Total financing
 costs and other     768    13,404    38,478    13,404    94,758     6,715
                 -------  --------  --------  --------  --------  --------
Income (loss)
 before taxes     15,188     3,535   (17,854)    3,535   (61,698)   66,220
Income tax
 provision
 (benefit)          (200)     (900)  (10,100)     (900)  (14,400)   (1,300)
                 -------  --------  --------  --------  --------  --------
Net income
 (loss)          $15,388  $  4,435  $ (7,754) $  4,435  $(47,298) $ 67,520
                 =======  ========  ========  ========  ========  ========

Weighted average
 common shares
 outstanding:
Basic             52,410    53,451    50,909    53,451    50,805    52,249
Diluted           53,259    53,817    50,909    53,817    50,805    53,018



                CONDENSED CONSOLIDATED BALANCE SHEET INFORMATION

UNAUDITED ($ in thousands)                          12/31/09     12/31/10
                                                  -----------  -----------
ASSETS
 Cash and cash equivalents                        $       419  $     5,024
 Accounts receivable                                   33,853       29,602
 Inventories                                            6,139        6,229
 Prepaid expenses and other current assets              4,276        4,585
 Income tax receivable                                  3,116          931
 Deferred income taxes                                  8,400            -
 Commodity derivatives                                 34,611       26,407
                                                  -----------  -----------
  Total current assets                                 90,814       72,778
  Net property, plant and equipment                   619,430      648,044
  Total other assets                                   29,299       30,101
                                                  -----------  -----------
TOTAL ASSETS                                      $   739,543  $   750,923
                                                  ===========  ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
 Accounts payable and accrued liabilities         $    56,855  $    45,396
 Interest payable                                       4,885        5,538
 Commodity and interest derivatives                    49,709       33,483
                                                  -----------  -----------
  Total current liabilities                           111,449       84,417
LONG-TERM DEBT                                        695,029      633,592
COMMODITY AND INTEREST DERIVATIVES                     15,076       23,430
ASSET RETIREMENT OBLIGATIONS                           92,485       93,721
                                                  -----------  -----------
  Total liabilities                                   914,039      835,160
  Total stockholders' equity                         (174,496)     (84,237)
                                                  -----------  -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY        $   739,543  $   750,923
                                                  ===========  ===========

GAAP RECONCILIATIONS

Adjusted Earnings and Adjusted EBITDA

In addition to net income (loss) determined in accordance with GAAP, we have provided in this release our Adjusted Earnings and Adjusted EBITDA for recent periods. Both Adjusted Earnings and Adjusted EBITDA are non-GAAP financial measures that we use as supplemental measures of our performance.

We define Adjusted Earnings as net income (loss) before the effects of the items listed in the table below. We calculate the tax effect of reconciling items by re-performing our period-end tax calculation excluding the reconciling items from earnings. The difference between this calculation and the tax expense/benefit recorded for the period results in the tax effect disclosed below. We believe that Adjusted Earnings facilitates comparisons to earnings forecasts prepared by stock analysts and other third parties. Such forecasts generally exclude the effects of items that are difficult to predict or to measure in advance and are not directly related to our ongoing operations. Adjusted Earnings should not be considered a substitute for net income (loss) as reported in accordance with GAAP.

We define Adjusted EBITDA as net income (loss) before the effects of the items listed in the table below. Because the use of Adjusted EBITDA facilitates comparisons of our historical operating performance on a more consistent basis, we use this measure for business planning and analysis purposes, in assessing acquisition opportunities and in determining how potential external financing sources are likely to evaluate our business.

We present Adjusted Earnings and Adjusted EBITDA because we consider them to be important supplemental measures of our performance. Neither Adjusted Earnings nor Adjusted EBITDA is a measurement of our financial performance under GAAP and neither should be considered as an alternative to net income (loss), operating income or any other performance measure derived in accordance with GAAP, as an alternative to cash flow from operating activities or as a measure of our liquidity. You should not assume that the Adjusted Earnings or Adjusted EBITDA amounts shown are comparable to similarly named measures disclosed by other companies.

                               Quarter Ended               Year Ended
                       -----------------------------  --------------------
UNAUDITED ($ in
 thousands)            12/31/09  9/30/10   12/31/10    12/31/09   12/31/10
                       --------  --------  ---------  ---------  ---------
Adjusted Earnings
 Reconciliation
Net Income             $ (7,754) $ 15,388  $   4,435  $ (47,298) $  67,520
Plus:
Unrealized commodity
 (gains) losses          14,924   (15,690)    29,678     71,511    (39,356)
Unrealized interest
 rate derivative
 (gains) losses          (1,643)    6,553     (9,561)    (1,803)    13,724
Texas severance costs         -         -          -          -      1,254
Loss on extinguishment
 of debt                  7,911         -          -      8,493          -
Tax effects                (344)        -          -       (276)         -
                       --------  --------  ---------  ---------  ---------
Adjusted Earnings      $ 13,094  $  6,251  $  24,552  $  30,627  $  43,142
                       ========  ========  =========  =========  =========



                              Quarter Ended                Year Ended
                     -------------------------------  --------------------
UNAUDITED ($ in
 thousands)          12/31/09    9/30/10   12/31/10   12/31/09   12/31/10
                     ---------  ---------  ---------  ---------  ---------
Adjusted EBITDA
 Reconciliations:
Net income           $  (7,754) $  15,388  $   4,435  $ (47,298) $  67,520
Interest expense        10,702     10,117     10,045     40,984     40,584
Interest rate
 derivative (gains)
 losses - realized       4,628      4,495      4,531     18,479     18,094
Income taxes           (10,100)      (200)      (900)   (14,400)    (1,300)
DD&A                    20,961     19,475     20,313     86,226     78,504
Accretion of asset
 retirement
 obligation              1,591      1,518      1,592      5,765      6,241
Amortization of
 deferred loan costs       638        499        507      2,862      2,362
Loss on
 extinguishment of
 debt                    7,911          -          -      8,493          -
Share-based payments       824      1,387      1,535      2,824      5,653
Texas severance
 costs                       -          -          -          -      1,254
Amortization of
 derivative premiums
 and other
 comprehensive loss      6,511      5,657      7,836     24,985     24,808
Unrealized commodity
 derivative (gains)
 losses                 14,924    (15,690)    29,678     71,511    (39,356)
Unrealized interest
 rate derivative
 (gains) losses         (1,643)     6,553     (9,561)    (1,803)    13,724
                     ---------  ---------  ---------  ---------  ---------
Adjusted EBITDA      $  49,193  $  49,199  $  70,011  $ 198,628  $ 218,088
                     =========  =========  =========  =========  =========

We also provide per BOE G&A expenses excluding share-based compensation charges and one-time severance charges related to Texas divestiture. We believe that these non-GAAP measures are useful in that the items excluded do not represent cash expenses directly related to our ongoing operations. These non-GAAP measures should not be viewed as an alternative to per BOE G&A expenses as determined in accordance with GAAP.

UNAUDITED ($ in
 thousands, except per
 BOE amounts)                     Quarter Ended             Year Ended
                          ----------------------------  ------------------
                          12/31/09  9/30/10   12/31/10  12/31/09  12/31/10
                          --------  --------  --------  --------  --------
G&A per BOE
 Reconciliation

G&A expense               $ 10,775  $  8,264  $  9,119  $ 36,939  $ 37,554
Less:
Share-based compensation
 expense                      (634)   (1,097)   (1,255)   (2,124)   (4,503)
Texas severance costs            -         -         -         -    (1,254)
                          --------  --------  --------  --------  --------
G&A Expense Excluding
 Share-Based Comp           10,141     7,167     7,864    34,815    31,797
MBOE                         1,847     1,664     1,594     7,527     6,658
                          --------  --------  --------  --------  --------
G&A Expense per BOE
 Excluding Share-Based
 Comp                     $   5.49  $   4.31  $   4.93  $   4.63  $   4.78
                          ========  ========  ========  ========  ========

PV-10

The present value of future net cash flows (PV-10 value) is a non-GAAP measure because it excludes income tax effects. Management believes that before-tax cash flow amounts are useful for evaluative purposes since future income taxes, which are affected by a company's unique tax position and strategies, can make after-tax amounts less comparable. We derive PV-10 value based on the present value of estimated future revenues to be generated from the production of proved reserves, net of estimated production and future development costs and future plugging and abandonment costs, using the arithmetic twelve-month average of the first of the month prices without giving effect to hedging activities or future escalation, and costs as of the date of estimate without future escalation, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion, amortization and impairment and income taxes, and discounted using an annual discount rate of 10%. Management also believes that the PV-10 based on the NYMEX 5-year forward strip pricing is useful for evaluative purposes since the use of a strip price provides a measure based on current market perception.

The following table reconciles the standardized measure of future net cash flows to PV-10 value (in thousands):

UNAUDITED ($ in thousands)                                     12/31/2010
                                                              -------------

Standardized measure of discounted future net cash flows      $     902,901
Add:  Present value of future income tax discounted at 10%          225,795
                                                              -------------
PV-10 at year end SEC prices                                      1,128,696
                                                              -------------
Add:  Effect of five year NYMEX strip at December 31, 2010          440,514
                                                              -------------
PV-10 at five year NYMEX strip at December 31, 2010           $   1,569,210
                                                              =============

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