SOURCE: Venoco, Inc.

Venoco, Inc.

February 25, 2010 05:01 ET

Venoco, Inc. Announces 2009 Financial and Operational Results for the Fourth Quarter and Full-Year

DENVER, CO--(Marketwire - February 25, 2010) - Venoco, Inc. (NYSE: VQ)

--  Replaced 210% of 2009 Production at an All-in Finding & Development
    Cost of $12.12 per BOE

--  Reduced Total Debt by Over $100 Million During Year

--  Full-Year Production was up 7% over 2008 Production (Pro Forma for the
    sale of the Hastings Field)

Venoco, Inc. (NYSE: VQ) today reported financial and operational results for the fourth quarter and full-year 2009. The company reported a net loss of $47 million primarily as a result of unrealized commodity derivative losses of $72 million due to increased oil prices at year-end.

Adjusted Earnings were $31 million, down from $78 million for 2008, primarily as a result of lower commodity prices realized throughout 2009. Adjusted Earnings adjusts the net loss of $47 million in 2009 and $391 million in 2008 for the effects of unrealized commodity and interest derivative gains / losses in both years, a loss on early extinguishment of debt in 2009, and the write-off of costs associated with the terminated MLP offering and the ceiling impairment in 2008. Adjusted EBITDA was $193 million, down 36% from $300 million for 2008. Please see the end of this release for definitions of Adjusted Earnings and Adjusted EBITDA and a reconciliation of those measures to net loss.


Highlights for 2009 included the following:

--  Production of 7.5 million barrels of oil equivalent (MMBOE) for the
    year or 20,622 BOE per day (BOE/d). Pro forma for the sale of the
    Hastings field, 2009 daily production of 20,397 was up 7% from 19,088
    BOE/d for 2008.

--  Proved Reserves of 98.3 MMBOE as of December 31, 2009, a 9% increase
    from year-end 2008 pro forma for the sale of the Hastings field.

--  Lifting costs down 25% from 2008 levels, averaging $12.65 per BOE in
    2009, (down 12% from 2008 pro forma for the sale of the Hastings
    field).

--  Achieved goal of paying down debt $100MM during year while maintaining
    pro forma production and reserve growth.

"We are very pleased with our performance in 2009. We exceeded our original production guidance of 19,000 BOE per day by 8.5%, replaced 210% of production at $12.12 per BOE, reduced debt by $100 million, and saw the stock price rise over 370% from the lows of a year ago. We also beat our initial lease operating expense guidance of $15.00 per BOE by nearly 16% and were able to increase our capital budget by $10 million in the fourth quarter as we ramped up for 2010," said Tim Marquez, Venoco's Chairman and CEO. "We are very excited about the momentum we've created and the project inventory we are pursuing in 2010. We also announced our plans for leasing and developing our onshore Monterey shale prospects and expanded our Sacramento Basin drilling inventory by year end. These two projects together have set us up with a very attractive long-term development inventory."

Fourth Quarter Production

Production in the fourth quarter of 2009 of 20,079 BOE/d was, as expected, relatively flat with both the third quarter of 2009 and the fourth quarter of 2008 (pro forma for the sale of the Hastings field).

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

                                                             Full Year
Region                     4Q 2008   3Q 2009   4Q 2009     2008      2009
Sacramento Basin              9,668    10,498    10,227     9,322    10,230
Southern California           8,903     8,207     8,354     8,248     8,523
Texas (and other)             4,103     1,559     1,498     4,104     1,869
   Total                     22,674    20,264    20,079    21,674    20,622
                          ========= ========= ========= ========= =========

   Total excluding
    Hastings                 20,110    20,264    20,079    19,088    20,397
                          ========= ========= ========= ========= =========

Capital Investment 2009

Venoco's 2009 capital expenditures for development and other spending were $161 million, including $101 million for drilling and rework activities, $21 million for facilities, $25 million for capitalized G&A, and $14 million for land, geological and geophysical, and other. In addition, the company also spent $23 million for acquisitions in its core areas, the majority of which went toward a mid-year acquisition of assets in the Sacramento Basin. Total costs incurred in 2009 for the company's E&P operations were $191 million (including asset retirement obligations of $7 million).

In 2009 the company spent $86 million or 53% of its capital expenditures (excluding acquisitions) in the Sacramento Basin. The company completed 63 wells and performed 197 recompletions in the basin during 2009, and realized significant efficiencies and cost savings throughout the year. Development activity during 2010 is expected to be similar to 2009 levels, with a planned capital expenditure budget of $72 million. As previously announced and discussed below, the company intends to sell its Texas assets; pending a successful sale of these assets, the company may elect to accelerate activity in the Sacramento Basin and the Monterey shale in 2010. Although gas prices are relatively low, Venoco has been able to drive drilling costs down in the Sacramento Basin to the point where a $4.00 gas price is expected to generate a 25% rate of return. At today's gas prices the Sac Basin drilling program is competitive with Venoco's oil projects.

In Southern California, the company spent $51 million or 32% of its 2009 capital expenditures. Planned capital expenditures for Southern California in 2010 are $73 million. The company's primary focus in Southern California during 2009 was on the redevelopment of the West Montalvo field, where two wells were completed early in the year and two wells were being drilled at year end, with each subsequently completed and put on production. In 2010, the company expects to drill three additional wells in West Montalvo.

Also in Southern California, the company drilled a dual-completion well in 2009 at the Sockeye field that produces from the Monterey shale formation and enhances the sweep of the waterflood by injecting water into the Upper Topanga formation. The company plans to drill another dual completion well in 2010 and to hydraulically fracture two wells in the field.

The company spent a minimal amount of its 2009 capital expenditures on its onshore Monterey shale development. The company accelerated its leasing activities during the second half of 2009, and expects to aggressively add to its position during 2010. Venoco also expects to drill at least 5 vertical test wells in the Monterey shale and to acquire 3D seismic data over certain portions of its acreage during 2010. The company's 2010 capital expenditure budget for the onshore Monterey shale development is $26 million; however, the company may allocate additional capital to the Monterey shale program as the year progresses.

"Our 2010 drilling program in the Monterey is focused on gathering core and log data, and understanding and predicting reservoir behavior," commented Mr. Marquez. "During the first half of the year the program is focused on science, but as the year progresses we expect to begin testing various completion techniques that have been successful in unconventional reservoirs in other parts of the country."

In Texas, the company spent $8 million or 5% of its 2009 capital expenditures. The company performed several low-cost workovers and drilled a successful well in the South Liberty field during 2009.

Reserves Review

As previously announced, the company's proved oil and gas reserves as of December 31, 2009 were 98.3 MMBOE using SEC pricing. Year-end 2009 reserves increased 18% compared to year-end 2008 reserves, net of production and pro forma for the February 2, 2009 sale of Hastings. Net of production, the company added 15.8 MMBOE to its proven reserves including 3.4 MMBOE from acquisitions. In total, the company replaced 210% of production at a cost of $12.12 per BOE (all-in finding and development cost). 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.

Price-related revisions due to lower natural gas prices between year-end 2008 and 2009 negatively impacted reserves, but were partially offset by positive price-related revisions related to higher oil prices resulting in net negative price-related revisions of 1.1 MMBOE. Performance related revisions and lower drilling and development costs resulted in the addition of 6.1 MMBOE across a number of fields including Sockeye, South Ellwood, West Montalvo, and various fields in the Sacramento Basin. In total, net reserve revisions resulted in the addition of approximately 5 MMBOE.

The pre-tax PV-10 of the company's reserves using SEC pricing of $61.04 per barrel for oil and $3.87 per MMBTU for gas is $801 million. The company's estimate of reserves using a year-end NYMEX 5-year forward strip pricing is 101.3 MMBOE, with a pre-tax PV-10 of $1.7 billion. See the end of this release for a reconciliation of PV-10 to a standardized measure of discounted future net cash flows.

Marketing of Texas Assets

The company is currently marketing its oil and gas interests in Texas including producing and non-producing assets. The company expects to complete the sale of some or all of its Texas assets during the second quarter of 2010. Net production from Venoco's Texas properties for 2009 was 1,641 BOE per day, excluding one month's production from Hastings, which was sold on February 2, 2009. Year-end proved reserves in Texas were 7.8 MMBOE at SEC pricing.

"As I've said before, we have some excellent assets in Texas; however, our focus in the coming years will be on the significant opportunities we have in California. As a result, monetizing our Texas assets would provide additional resources to help us in those efforts," said Mr. Marquez.

Balance Sheet

In October, the company refinanced its existing senior secured notes due in 2011 with new senior unsecured notes due in 2017. As a result of the refinancing, the maturity of the company's second lien term loan was automatically extended from September 2011 to May 2014. Subsequent to the refinancing, the company entered into a revised interest rate swap agreement which extended the terms of the existing interest rate swap through May 2014 so that amounts borrowed up to $500 million will effectively bear interest at a fixed rate of 7.8%. In December of 2009, the company also amended its revolving credit facility to extend the maturity from 2011 to 2013.

The company closed the sale of its Hastings field in Texas to Denbury Resources in early February 2009 for proceeds of approximately $200 million. Venoco used a portion of these proceeds to pay down debt during 2009, and ended the year with approximately $103 million less in long-term debt than at year end 2008.

2010 Guidance

The following summarizes the company's 2010 guidance:

--  Production: 20,250 BOE/d
--  Capital Budget: $180 million
--  Lease Operating Expenses: $14.50 per BOE
--  G&A Expenses (excluding stock-based compensation): $4.50 per BOE
--  DD&A: $12.00 per BOE

The forecasts do not include the effect of the anticipated sale of some or all of the company's Texas assets.

Earnings Conference Call

Venoco will host a conference call to discuss results today, Thursday, February 25, 2010 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) 543-6408 and use conference code 53423730. International participants can call (617) 213-8899 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 31533833. The replay will also be available on the Venoco website for 30 days.

The company will post an updated presentation on the Investor Relations page of its website today.

Annual Stockholders Meeting

The company's Annual Stockholders' meeting will be held on Wednesday, June 2, 2010 at the Brown Palace Hotel, 321 17th Street, Denver, Colorado. Stockholders of record at the close of business on Monday, April 5, 2010, are entitled to receive notice of the meeting and to vote the shares of Venoco common stock they hold as of that date.

About the Company

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

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 may not be able to complete its planned disposition of assets in Texas on acceptable terms, in a timely manner, or at all. 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. For further information, please contact Mike Edwards, Vice President, (303) 626-8320; http://www.venocoinc.com; E-Mail investor@venocoinc.com.

                       OIL AND NATURAL GAS PRODUCTION AND PRICES


                          Quarter Ended                Quarter Ended
                    --------------------------  --------------------------
                                         %                           %
UNAUDITED           9/30/09  12/31/09  Change   12/31/08 12/31/09  Change
                    -------  --------  -------  -------- --------  -------

Production Volume:
Oil (MBbls) (1)         811       809        0%    1,096      809      -26%
Natural Gas (MMcf)    6,320     6,230       -1%    5,940    6,230        5%
                    -------  --------  -------  -------- --------  -------
MBOE                  1,864     1,847       -1%    2,086    1,847      -11%
                    =======  ========  =======  ======== ========  =======
Daily Average
 Production Volume:
Oil (Bbls/d)          8,815     8,793        0%   11,913    8,793      -26%
Natural Gas (Mcf/d)  68,696    67,717       -1%   64,565   67,717        5%
                    -------  --------  -------  -------- --------  -------
BOE/d                20,264    20,079       -1%   22,674   20,079      -11%
                    =======  ========  =======  ======== ========  =======
Oil Price per
 Barrel Produced
 (in dollars):
Realized price
 before hedging     $ 58.09  $  64.85       12% $  48.36 $  64.85       34%
Realized hedging
 gain (loss)          (4.66)   (10.07)     116%     3.83   (10.07)    -363%
                    -------  --------  -------  -------- --------  -------
Net realized price  $ 53.43  $  54.78        3% $  52.19 $  54.78        5%
                    =======  ========  =======  ======== ========  =======
Natural Gas Price
 per Mcf
 (in dollars):
Realized price
 before hedging     $  3.17  $   4.59       45% $   5.76 $   4.59      -20%
Realized hedging
 gain (loss)           3.24      2.06      -36%     0.51     2.06      304%
                    -------  --------  -------  -------- --------  -------
Net realized price  $  6.41  $   6.65        4% $   6.27 $   6.65        6%
                    =======  ========  =======  ======== ========  =======
Expense per BOE
 (in dollars):
Lease operating
 expenses (2)       $ 13.55  $  12.85       -5% $  19.21 $  12.85      -33%
Production and
 property taxes (2) $  1.48  $   0.72      -51% $   0.89 $   0.72      -19%
Transportation
 expenses           $  0.61  $   1.03       69% $   0.78 $   1.03       32%
Depreciation,
 depletion and
 amortization       $ 11.79  $  11.35       -4% $  19.38 $  11.35      -41%
General and
 administrative (3) $  5.15  $   5.83       13% $   5.58 $   5.83        4%
Interest expense    $  5.00  $   5.79       16% $   6.23 $   5.79       -7%



                            Year Ended
                    --------------------------
                                          %
UNAUDITED           12/31/08  12/31/09  Change
                    --------  --------  -------

Production Volume:
Oil (MBbls) (1)        4,091     3,402      -17%
Natural Gas (MMcf)    23,050    24,748        7%
                    --------  --------  -------
MBOE                   7,933     7,527       -5%
                    ========  ========  =======
Daily Average
 Production Volume:
Oil (Bbls/d)          11,178     9,321      -17%
Natural Gas (Mcf/d)   62,978    67,803        8%
                    --------  --------  -------
BOE/d                 21,674    20,622       -5%
                    ========  ========  =======
Oil Price per
 Barrel Produced
 (in dollars):
Realized price
 before hedging     $  89.69  $  51.10      -43%
Realized hedging
 gain (loss)          (20.71)    (0.95)     -95%
                    --------  --------  -------
Net realized price  $  68.98  $  50.15      -27%
                    ========  ========  =======
Natural Gas Price
 per Mcf
 (in dollars):
Realized price
 before hedging     $   8.21  $   3.84      -53%
Realized hedging
 gain (loss)            0.08      2.58        -
                    --------  --------  -------
Net realized price  $   8.29  $   6.42      -23%
                    ========  ========  =======
Expense per BOE
 (in dollars):
Lease operating
 expenses (2)       $  16.86  $  12.65      -25%
Production and
 property taxes (2) $   1.98  $   1.35      -32%
Transportation
 expenses           $   0.75  $   0.65      -13%
Depreciation,
 depletion and
 amortization       $  16.95  $  11.46      -32%
General and
 administrative (3) $   5.43  $   4.91      -10%
Interest expense    $   6.81  $   5.44      -20%


(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)  Lease operating expenses are combined with property and production
taxes to comprise oil and natural gas production expense on the
consolidated statements of operations
(3)  Net of amounts capitalized.



             CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


                Quarter Ended        Quarter Ended         Year Ended
UNAUDITED     ------------------  -------------------  -------------------
(In thousands) 9/30/09  12/31/09   12/31/08  12/31/09   12/31/08  12/31/09
              --------  --------  ---------  --------  ---------  --------
REVENUES:
Oil and
 natural gas
 sales        $ 69,284  $ 80,139  $  94,079  $ 80,139  $ 555,917  $268,865
Other              859       784        791       784      3,603     3,331
              --------  --------  ---------  --------  ---------  --------
Total
 revenues       70,143    80,923     94,870    80,923    559,520   272,196
              --------  --------  ---------  --------  ---------  --------
EXPENSES:
Oil and
 natural gas
 production     28,015    25,061     41,939    25,061    149,504   105,341
Transportation
 expense         1,144     1,911      1,624     1,911      5,958     4,865
Depletion,
 depreciation
 and
 amortization   21,974    20,961     40,436    20,961    134,483    86,226
Impairment           -         -    641,000         -    641,000         -
Accretion of
 asset
 retirement
 obligation      1,429     1,591      1,138     1,591      4,203     5,765
General and
 administrative  9,607    10,775     11,635    10,775     43,101    36,939
              --------  --------  ---------  --------  ---------  --------
Total
 expenses       62,169    60,299    737,772    60,299    978,249   239,136
              --------  --------  ---------  --------  ---------  --------
Income from
 operations      7,974    20,624   (642,902)   20,624   (418,729)   33,060
FINANCING
 COSTS AND
 OTHER:
Interest
 expense         9,327    10,702     12,986    10,702     54,049    40,984
Interest rate
 derivative
 realized
 (gains)
 losses          4,781     4,628      3,136     4,628     10,231    18,479
Interest rate
 derivative
 unrealized
 (gains)
 losses             10    (1,643)    10,623    (1,643)    10,336    (1,803)
Amortization
 of deferred
 loan costs        751       638        721       638      3,344     2,862
Loss on
 extinguish-
 ment of debt        -     7,911          -     7,911          -     8,493
Commodity
 derivative
 realized
 (gains)
 losses        (16,675)   (4,681)   (28,768)   (4,681)    61,446   (68,429)
Commodity
 derivative
 unrealized
 (gains)
 losses and
 amortization
 of derivative
 premiums       24,252    20,923   (224,356)   20,923   (178,203)   94,172
              --------  --------  ---------  --------  ---------  --------
Total
 financing
 costs and
 other          22,446    38,478   (225,658)   38,478    (38,797)   94,758
              --------  --------  ---------  --------  ---------  --------
Income (loss)
 before taxes  (14,472)  (17,854)  (417,244)  (17,854)  (379,932)  (61,698)
Income tax
 provision
 (benefit)      (9,200)  (10,100)    (3,200)  (10,100)    11,200   (14,400)
              --------  --------  ---------  --------  ---------  --------
Net income
 (loss)       $ (5,272) $ (7,754) $(414,044) $ (7,754) $(391,132) $(47,298)
              ========  ========  =========  ========  =========  ========

Weighted
 average
 common
 shares
 outstanding:
  Basic         50,826    50,909     50,697    50,909     50,486    50,805
  Diluted       50,826    50,909     50,697    50,909     50,486    50,805




             CONDENSED CONSOLIDATED BALANCE SHEET INFORMATION


UNAUDITED ($ in thousands)                             12/31/08   12/31/09
                                                      ---------  ---------
ASSETS
  Cash and cash equivalents                           $     191  $     419
  Accounts receivable                                    41,306     33,853
  Inventories                                            12,361      6,139
  Prepaid expenses and other current assets               4,314      4,276
  Income tax receivable                                     546      3,116
  Deferred income taxes                                       -      8,400
  Commodity derivatives                                  57,247     34,611
                                                      ---------  ---------
    Total current assets                                115,965     90,814
    Net property, plant and equipment                   702,734    619,430
    Total other assets                                   45,555     29,299
                                                      ---------  ---------
TOTAL ASSETS                                          $ 864,254  $ 739,543
                                                      =========  =========
LIABILITIES AND STOCKHOLDERS' EQUITY
  Accounts payable and accrued liabilities            $  75,400  $  48,709
  Undistributed revenue payable                           8,277      8,146
  Interest payable                                        5,325      4,885
  Current maturities of long-term debt                    2,598          -
  Commodity and interest derivatives                     21,284     49,709
                                                      ---------  ---------
    Total current liabilities                           112,884    111,449
LONG-TERM DEBT                                          797,670    695,029
COMMODITY AND INTEREST DERIVATIVES                        9,363     15,076
ASSET RETIREMENT OBLIGATIONS                             79,504     92,485
                                                      ---------  ---------
    Total liabilities                                   999,421    914,039
    Total stockholders' equity                         (135,167)  (174,496)
                                                      ---------  ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY            $ 864,254  $ 739,543
                                                      =========  =========




                               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) 12/31/08     9/30/09    12/31/09    12/31/08    12/31/09
                ----------  ----------  ----------  ----------  ----------
Adjusted
 Earnings
 Reconciliation
Net Income      $ (414,044) $   (5,272) $   (7,754) $ (391,132) $  (47,298)
Plus:
Unrealized
 commodity
 (gains) losses   (225,457)     18,253      14,924    (184,459)     71,511
Unrealized
 interest rate
 derivative
 (gains) losses     10,623          10      (1,643)     10,336      (1,803)
Write-off of
 MLP offering
 costs                   -           -           -       2,690           -
Loss on
 extinguishment
 of debt                 -           -       7,911           -       8,493
Ceiling test
 impairment        641,000           -           -     641,000           -
Tax effects              -           -        (344)       (690)       (276)
                ----------  ----------  ----------  ----------  ----------
Adjusted
 Earnings       $   12,122  $   12,991  $   13,094  $   77,745  $   30,627
                ==========  ==========  ==========  ==========  ==========


                           Quarter Ended                 Year Ended
UNAUDITED       ----------------------------------  ----------------------
($ in thousands) 12/31/08     9/30/09    12/31/09    12/31/08    12/31/09
                ----------  ----------  ----------  ----------  ----------
Adjusted EBITDA
 Reconciliations:
Net income      $ (414,044) $   (5,272) $   (7,754) $ (391,132) $  (47,298)
Interest
 expense            12,986       9,327      10,702      54,049      40,984
Interest rate
 derivative
 (gains) losses
 - realized          3,136       4,781       4,628      10,231      18,479
Income taxes        (3,200)     (9,200)    (10,100)     11,200     (14,400)
DD&A                40,436      21,974      20,961     134,483      86,226
Impairment         641,000           -           -     641,000           -
Amortization of
 deferred loan
 costs                 721         751         638       3,344       2,862
Loss on
 extinguishment
 of debt                 -           -       7,911           -       8,493
Share-based
 payments              970         806         824       3,064       2,824
Amortization of
 derivative
 premiums and
 other
 comprehensive
 loss                1,505       6,608       6,511       7,694      24,985
Unrealized
 commodity
 derivative
 (gains) losses   (225,457)     18,253      14,924    (184,459)     71,511
Unrealized
 interest rate
 derivative
 (gains) losses     10,623          10      (1,643)     10,336      (1,803)
                ----------  ----------  ----------  ----------  ----------
Adjusted EBITDA $   68,676  $   48,038  $   47,602  $  299,810  $  192,863
                ==========  ==========  ==========  ==========  ==========

We also provide per BOE G&A expenses excluding costs associated with the terminated MLP offering and share-based compensation charges. 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
                          ----------------------------  ------------------
                          12/31/08   9/30/09  12/31/09  12/31/08  12/31/09
                          --------  --------  --------  --------  --------
G&A per BOE
 Reconciliation

G&A expense               $ 11,635  $  9,607  $ 10,775  $ 43,101  $ 36,939
Less:
Share-based compensation
 expense                      (710)     (616)     (634)   (2,384)   (2,124)
MLP write off                    -         -         -    (2,690)        -
                          --------  --------  --------  --------  --------
G&A Expense Excluding
 Share-Based Comp / MLP     10,925     8,991    10,141    38,027    34,815
MBOE                         2,086     1,864     1,847     7,933     7,527
                          --------  --------  --------  --------  --------
G&A Expense per BOE
 Excluding Share-Based
 Comp / MLP               $   5.24  $   4.82  $   5.49  $   4.79  $   4.63
                          ========  ========  ========  ========  ========

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)                                   12/31/2009
                                                            -----------

Standardized measure of discounted future net cash flows    $   692,805
Add:  Present value of future income tax discounted at 10%      108,248
                                                            -----------
PV-10 at SEC prices                                             801,053
                                                            -----------
Add:  Effect of five year NYMEX strip at December 31, 2009      868,916
                                                            -----------
PV-10 at five year NYMEX strip at December 31, 2009         $ 1,669,969
                                                            ===========

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