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


February 22, 2011 - DENVER, CO

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 resultsfor the fourth quarter and full-year 2010. The company reported net incomefor the year of $68 million. Total revenues for the year were $295 million,realized commodity derivative gains were $54 million, and unrealizedcommodity derivative gains were $39 million.

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

Highlights for 2010 included the following:

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

"Last year we invested in the science of the onshore Monterey shale and I'mpleased with the progress we've made in that area. I'm also happy with theresults we saw from focusing on costs at our legacy assets. We were able tobeat our LOE guidance while keeping production within 2% of guidance," saidTim Marquez, Venoco's Chairman and CEO. "We believe we've made goodprogress advancing the science in 2010 on the Monterey shale, and see 2011as 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% fromthe third quarter of 2010 and down 7% from the fourth quarter of 2009 (proforma for the sale of the company's producing Texas assets). Fourth quarterproduction was negatively impacted by mechanical failures and heavy rainsthat delayed projects.

"As we previously announced, we had a number of relatively minor issues in2010 that in total caused us to slightly miss our annual productionguidance," commented Mr. Marquez. "The new year is off to a good start.Production from our legacy Southern California assets has recovered from adip in the fourth quarter. We expect our production from those assets andthe Sacramento Basin to be relatively flat in 2011 and that productiongrowth will come from our planned onshore Monterey shale drilling," addedMr. 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 BOEwere up slightly from $12.44 per BOE in the third quarter due primarily tolower production levels in the fourth quarter compared to the thirdquarter. The company's full-year 2010 lease operating expenses of $12.65per BOE were below the company's guidance of $13.00 per BOE.

 Quarter Ended Year Ended --------------------------- ------------------- Full YearUNAUDITED (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 $ 13.00Production/ Property Taxes 0.72 1.05 0.87 1.35 1.01 1.15DD&A Expense 11.35 11.70 12.74 11.46 11.79 12.00G&A Expense (1) 5.49 4.31 4.93 4.63 4.78 4.70Interest 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, seismicand capitalized G&A costs. In addition, the company also spent $2 millionfor acquisitions of proved properties targeting the onshore Monterey shaleformation. Total costs incurred in 2010 for the company's E&P operationswere $215 million (including a reduction in asset retirement obligations of$5 million).

In 2010 the company spent $104 million or 47% of its capital expendituresin the Sacramento Basin. The company spud 93 wells, completed 75 wells,performed 213 recompletions, and hydraulically fractured 12 wells in thebasin during 2010. The company plans to reduce activity levels in thebasin in 2011 as a result of depressed natural gas prices and the company'sincreased focus on oil-based Monterey shale activities. The company's 2011capital expenditure budget for the Sacramento Basin of $60 million includes40 wells, 220 recompletions, and 20 hydraulic fractures. The companyidentified several anomalies from 3D seismic data on lands it acquired in2009 and drilled a successful discovery well in December on one of theseanomalies -- it is an extension of the Grimes field and tested at a rate ofabout 2 million cubic feet per day. The company has two additionallocations on this anomaly that it plans to drill later this year. Itrecently TD'd a well on a second anomaly that appears to be another goodwell, and plans to drill a well on a third anomaly this spring. Thecompany expects 2011 activity levels to result in average daily productionin 2011 that is roughly flat compared to 2010 average daily production;however production is expected to decline throughout the year as a resultof the lower activity.

The company's Southern California legacy fields accounted for $39 millionor 18% of its 2010 capital expenditures. Projects completed during theyear include the completion of two wells at the West Montalvo field and adual-completion well at the Sockeye field that produces from the Montereyshale formation and enhances the sweep of the field's waterflood byinjecting water into the Upper Topanga formation. At the South Ellwoodfield, the company performed six recompletions and continued work toadvance the permitting process for the field's proved undeveloped locationsand performed facilities work required to begin drilling those locations.The company's 2011 capital expenditure budget of $40 million for legacySouthern California properties includes plans to drill four wells andperform additional recompletions in order to keep average daily productionin 2011 relatively flat with 2010 average daily production.

The company significantly increased its capital expenditures on its onshoreMonterey shale development in 2010, spending approximately $74 million or34% of its 2010 capital expenditures on the emerging play. The companyspud 11 gross wells during the year including seven vertical "science"wells and four horizontal wells. The company completed the first half ofthe joint 3D seismic shoot over its acreage in the San Joaquin Basin during2010. The company's 2011 capital expenditure budget for the onshoreMonterey shale development is $100 million; however, the company mayallocate additional capital to the Monterey shale program as the yearprogresses.

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

Reserves Review

As previously announced, the company's proved oil and gas reserves as ofDecember 31, 2010 were 85.1 MMBOE using SEC benchmark pricing. Year-end2010 reserves were relatively flat with year-end 2009 reserves, net ofproduction and pro forma for the second quarter 2010 sale of Texas assetsand the December sale of the Gato Ridge field. Though permitted by new SECguidance regarding oil and gas reserves, the company's year-end reservereport did not utilize statistical methods for booking undeveloped oil andgas reserves; rather, the methodologies used were consistent with thoseused in prior years.

The pre-tax PV-10 of the company's reserves using SEC pricing of $79.43 perbarrel for oil and $4.38 per MMBTU for gas is $1.1 billion. The company'sestimate of reserves using a year-end NYMEX 5-year forward strip pricing is86.1 MMBOE, with a pre-tax PV-10 of $1.6 billion. See the end of thisrelease for a reconciliation of PV-10 to a standardized measure ofdiscounted future net cash flows.

Balance Sheet & Liquidity

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

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

The company expects to fund its 2011 capital expenditure budget ofapproximately $200 million primarily with cash flow from operations,supplemented with borrowings under its revolving credit facility andproceeds from the equity transaction completed in February 2011.Additionally, the company continues to pursue joint venture transactionsrelated 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). Theconference call will be webcast and those wanting to listen may do so byusing a link on the Investor Relations page of the company's website athttp://www.venocoinc.com. Those wanting to participate in the Q & Aportion can call (866) 730-5763 and use conference code 34915104.International participants can call (857) 350-1587 and use the sameconference 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 usingpasscode 37030244. The replay will also be available on the Venoco websitefor 30 days.

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

About the Company

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

Forward-looking Statements

Statements made in this news release relating to Venoco's futureproduction, expenses, capital expenditures and development projects, theexpected rate of return on drilling projects and all other statementsexcept statements of historical fact, are forward-looking statements withinthe meaning of Section 27A of the Securities Act of 1933 and Section 21E ofthe Securities Exchange Act of 1934. These statements are based onassumptions and estimates that management believes are reasonable based oncurrently available information; however, management's assumptions and thecompany's future performance are both subject to a wide range of businessrisks and uncertainties and there is no assurance that these goals andprojections can or will be met. Any number of factors could cause actualresults to differ materially from those in the forward-looking statements,including, but not limited to, the timing and extent of changes in oil andgas prices, the timing and results of drilling and other developmentactivities, the availability and cost of obtaining drilling equipment andtechnical personnel, risks associated with the availability of acceptabletransportation arrangements and the possibility of unanticipatedoperational problems, delays in completing production, treatment andtransportation facilities, higher than expected production costs and otherexpenses, and pipeline curtailments by third parties. The company'sactivities with respect to the onshore Monterey Shale and other projectsare subject to numerous operating, geological and other risks and may notbe successful. The company's results in the onshore Monterey Shale will besubject to greater risks than in areas where it has more data and drillingand production experience. Results from the company's onshore MontereyShale project will depend on, among other things, its ability to identifyproductive intervals and drilling and completion techniques necessary toachieve commercial production from those intervals. All forward-lookingstatements are made only as of the date hereof and the company undertakesno obligation to update any such statement. Further information on risksand uncertainties that may affect the Company's operations and financialperformance, and the forward-looking statements made herein, is availablein the company's filings with the Securities and Exchange Commission, whichare 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 $290,608Other 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 84,255Production and property taxes 1,742 1,387 1,333 1,387 10,128 6,701Transportation expense 2,750 2,613 1,487 2,613 3,163 9,102Depletion, depreciation and amortization 19,475 20,313 20,961 20,313 86,226 78,504Accretion of asset retirement obligation 1,518 1,592 1,591 1,592 5,765 6,241General 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 72,935FINANCING COSTS AND OTHER:Interest expense 10,117 10,045 10,702 10,045 40,984 40,584Interest rate derivative realized (gains) losses 4,495 4,531 4,628 4,531 18,479 18,094Interest rate derivative unrealized (gains) losses 6,553 (9,561) (1,643) (9,561) (1,803) 13,724Amortization of deferred loan costs 499 507 638 507 2,862 2,362Loss 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) 66,220Income 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 52,249Diluted 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 84,417LONG-TERM DEBT 695,029 633,592COMMODITY AND INTEREST DERIVATIVES 15,076 23,430ASSET 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, wehave provided in this release our Adjusted Earnings and Adjusted EBITDA forrecent periods. Both Adjusted Earnings and Adjusted EBITDA are non-GAAPfinancial measures that we use as supplemental measures of our performance.

We define Adjusted Earnings as net income (loss) before the effects of theitems listed in the table below. We calculate the tax effect ofreconciling items by re-performing our period-end tax calculation excludingthe reconciling items from earnings. The difference between thiscalculation and the tax expense/benefit recorded for the period results inthe tax effect disclosed below. We believe that Adjusted Earningsfacilitates comparisons to earnings forecasts prepared by stock analystsand other third parties. Such forecasts generally exclude the effects ofitems that are difficult to predict or to measure in advance and are notdirectly related to our ongoing operations. Adjusted Earnings should not beconsidered a substitute for net income (loss) as reported in accordancewith GAAP.

We define Adjusted EBITDA as net income (loss) before the effects of theitems listed in the table below. Because the use of Adjusted EBITDAfacilitates comparisons of our historical operating performance on a moreconsistent basis, we use this measure for business planning and analysispurposes, in assessing acquisition opportunities and in determining howpotential external financing sources are likely to evaluate our business.

We present Adjusted Earnings and Adjusted EBITDA because we consider themto be important supplemental measures of our performance. Neither AdjustedEarnings nor Adjusted EBITDA is a measurement of our financial performanceunder GAAP and neither should be considered as an alternative to net income(loss), operating income or any other performance measure derived inaccordance with GAAP, as an alternative to cash flow from operatingactivities or as a measure of our liquidity. You should not assume that theAdjusted Earnings or Adjusted EBITDA amounts shown are comparable tosimilarly 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 ReconciliationNet Income $ (7,754) $ 15,388 $ 4,435 $ (47,298) $ 67,520Plus: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) 13,724Texas severance costs - - - - 1,254Loss 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) $ 67,520Interest expense 10,702 10,117 10,045 40,984 40,584Interest rate derivative (gains) losses - realized 4,628 4,495 4,531 18,479 18,094Income taxes (10,100) (200) (900) (14,400) (1,300)DD&A 20,961 19,475 20,313 86,226 78,504Accretion of asset retirement obligation 1,591 1,518 1,592 5,765 6,241Amortization of deferred loan costs 638 499 507 2,862 2,362Loss on extinguishment of debt 7,911 - - 8,493 -Share-based payments 824 1,387 1,535 2,824 5,653Texas severance costs - - - - 1,254Amortization of derivative premiums and other comprehensive loss 6,511 5,657 7,836 24,985 24,808Unrealized 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 compensationcharges and one-time severance charges related to Texas divestiture. Webelieve that these non-GAAP measures are useful in that the items excludeddo not represent cash expenses directly related to our ongoing operations.These non-GAAP measures should not be viewed as an alternative to per BOEG&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 $ 37,554Less: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 31,797MBOE 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-GAAPmeasure because it excludes income tax effects. Management believes thatbefore-tax cash flow amounts are useful for evaluative purposes sincefuture income taxes, which are affected by a company's unique tax positionand strategies, can make after-tax amounts less comparable. We derive PV-10value based on the present value of estimated future revenues to begenerated from the production of proved reserves, net of estimatedproduction and future development costs and future plugging and abandonmentcosts, using the arithmetic twelve-month average of the first of the monthprices 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 andincome taxes, and discounted using an annual discount rate of 10%.Management also believes that the PV-10 based on the NYMEX 5-year forwardstrip pricing is useful for evaluative purposes since the use of a stripprice provides a measure based on current market perception.

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

UNAUDITED ($ in thousands) 12/31/2010 ------------- Standardized measure of discounted future net cash flows $ 902,901Add: 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 ============= 

For further information, please contact:
Mike Edwards
Vice President
(303) 626-8320
http://www.venocoinc.com
Email Contact

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