News Column

Venoco, Inc. Announces Year-End 2012 Reserves and 4th Quarter and Full-Year 2012 Financial and Operational Results

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DENVER, CO -- (Marketwired) -- 04/15/13 -- Venoco, Inc. today reported financial and operational results for the fourth quarter and full-year 2012. The company reported a net loss for the year of $47 million on total revenues of $357 million.

Adjusted Earnings, which adjusts for unrealized derivative gains and losses and certain one-time charges, were $54 million for the year. Adjusted EBITDA was $239 million in 2012, up 9% from $219 million in 2011. 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 include the following:

•Production of 6.3 million barrels of oil equivalent (MMBOE) for the year, or 17,336 BOE per day (BOE/d). •Oil production of 2.9 million barrels for the year, or 8,033 barrels per day (Bbls/d), a 20% increase over 2011 oil production. •Proved reserves of 52.2 MMBOE as of December 31, 2012, compared to 49.7 MMBOE in 2011, pro forma for the sales of the Sacramento Basin and Santa Clara Avenue properties. PV-10 was $1.5 billion as of December 31, 2012. Please see the end of this release for a definition of PV-10 and a reconciliation of this measure to standardized measure of discounted future cash flows. •Sale of Sacramento Basin properties and certain onshore Monterey acreage on December 31, 2012 for $250 million.

Recent Events

Effective December 31, 2012, the Company sold all of its producing properties in the Sacramento Basin as well as its prospective onshore Monterey acreage in the San Joaquin basin, excluding the Sevier field, to an unrelated third party for $250 million, subject to customary adjustments. As of April 15, 2013, the Company has received $242 million of the proceeds from the sale. The remaining $8 million is currently held in escrow and will be released upon the receipt of consents regarding the transfer of ownership of certain assets. The Company expects to receive those consents and the related proceeds from escrow prior to June 30, 2013.

"Throughout 2012 we concentrated our efforts and capital on our oily, Southern California legacy assets given our bearish outlook on natural gas prices for the short and mid-term period. Although we had great assets in the Sacramento Basin, the depressed natural gas price environment relative to oil prices precluded us from developing the assets to their full potential," said Ed O'Donnell, Venoco's CEO. "The price we received from the sale of our Sacramento Basin assets was highly favorable and allowed us to pay down a significant amount of the debt we took on in the going private transaction."

Fourth Quarter and Full-Year Production

Production in the fourth quarter of 2012 was 16,939 BOE/d compared to 17,899 BOE/d in the third quarter of 2012 and 17,810 BOE/d in the fourth quarter of 2011. Full year production for 2012 was 17,336 BOE/d compared to 17,612 BOE/d in 2011. Oil production in the fourth quarter of 2012 of 8,348 Bbls/d was down compared to 9,120 Bbls/d in the third quarter of 2012 primarily as a result of scheduled annual maintenance at the company's South Ellwood field and well work at the company's West Montalvo field. Fourth quarter 2012 oil production was up 24% over oil production of 6,739 Bbls/d in the fourth quarter of 2011. Oil production was up 20% for the full year 2012 to 8,033 Bbls/d from 6,688 Bbls/d in 2011, primarily as a result of successful drilling at the company's South Ellwood and West Montalvo fields during 2012.

"Our fourth quarter 2012 production was significantly affected by the scheduled annual maintenance shutdown at South Ellwood in November. The field was down for seven days, which resulted in the loss of approximately 400 - 450 BOE/d for the quarter," commented Mr. O'Donnell. "However, during 2012, we focused on developing our legacy Southern California oil projects, which resulted in an increase in our oil production of 20% in 2012 compared to 2011. With the sale of our Sacramento Basin assets, we will continue to focus on the development of oil projects in our legacy Southern California assets in 2013 and we have had a very solid start to the year as we concentrate our early efforts on development of our South Ellwood field. Pro forma for the sale of the Sacramento Basin, we are expecting to see an increase in production of 20-25% in 2013 compared to 2012. A significant amount of the production increase is expected to come from our South Ellwood field where we completed a well in the first quarter of 2013 that has produced at an average rate of approximately 1,500 gross BOE per day in the last 20 days of March. Given our recent success at the South Ellwood field, we are confident in our ability to achieve the significant production growth projected for 2013," Mr. O'Donnell added.

The following table details the company's daily production by region (BOE(1)/d):


---------------------------------------------------------------------------- Full Year----------------------------------------------------------------------------Region 4Q 2011 3Q 2012 4Q 2012 2011 2012----------------------------------------------------------------------------Sacramento Basin 10,635 8,394 8,221 10,446 8,926----------------------------------------------------------------------------Southern California 7,175 9,505 8,718 7,166 8,410---------------------------------------------------------------------------- Total 17,810 17,899 16,939 17,612 17,336-------------------------------------=======-=======-=======-=======-=======(1) Barrel of oil equivalent (BOE) is calculated using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.----------------------------------------------------------------------------




Fourth Quarter and Full-Year Costs

Venoco's fourth quarter 2012 lease operating expenses of $15.69 per BOE were up from $13.90 per BOE in the third quarter. The fourth quarter expenses were negatively affected by the scheduled annual maintenance performed at the South Ellwood field during the quarter, which resulted in higher LOE costs and reduced production levels. The company's full year 2012 lease operating expenses of $14.48 per BOE were slightly lower than full year 2011 lease operating expenses of $14.64 per BOE.

Venoco's fourth quarter G&A costs, excluding going private related costs, severance costs related to the sale of the Sacramento Basin assets and non-cash share-based compensation, was $8.47 per BOE compared to $5.59 per BOE in the third quarter. The company's full year 2012 G&A costs, excluding the costs outlined above, were $6.13 per BOE compared to $4.96 per BOE in 2011. The increase in G&A is primarily the result of the fourth quarter conversion of restricted stock and stock option awards into cash settlement awards as a result of the going private transaction completed in October 2012.

Property and production taxes for the full year 2012 were $1.53 per BOE compared to $0.99 per BOE in 2011. The increase is primarily the result of supplemental ad valorem taxes related to successful oil wells drilled during the second quarter of 2012.


Quarter Ended Year Ended -------------------------- -----------------UNAUDITED (per BOE) 12/31/11 9/30/12 12/31/12 12/31/11 12/31/12 -------- -------- -------- -------- --------Lease Operating Expenses $ 13.87 $ 13.90 $ 15.69 $ 14.64 $ 14.48Production/Property Taxes 0.97 1.01 0.71 0.99 1.53DD&A Expense 13.43 13.50 13.53 13.35 13.68G&A Expense (1) 5.46 5.59 8.47 4.96 6.13




(1) Net of amounts capitalized and excluding non-cash share-based compensation costs, costs related to the going-private transaction and severance costs associated with the sale of our Sacramento Basin assets. See the end of this release for a reconciliation of G&A per BOE.

Capital Investment 2012

Venoco's 2012 capital expenditures for exploration, development and other spending were $219 million, including $154 million for drilling and rework activities, $25 million for facilities, and the remaining $40 million for land, seismic and capitalized G&A.

In 2012, the company spent $117 million or 53% of its capital expenditures on its Southern California legacy fields. At the West Montalvo field, the company spud four wells and completed six wells (including two wells spud in 2011), all targeting the offshore portion of the field. Net production at West Montalvo has increased approximately 25% from 1,428 BOE per day in the fourth quarter of 2011 to 1,806 BOE per day in the fourth quarter of 2012. At the South Ellwood field, the company spud four wells and completed three wells during 2012. The first well averaged about 60 gross BOE per day in the fourth quarter, while the second well (the 3242-12 well) averaged about 2,000 gross BOE per day in the fourth quarter. The third well drilled (3242-4) was wet. This well was re-drilled (as the 3242-4RD) in the fourth quarter and was completed in the first quarter of 2013. The fourth well spud during 2012 (3242-19) was drilled to a probable location but was suspended following setting intermediate casing to facilitate the re-drill of the 3242-4RD well. During 2012, the company drilled three wells and performed one recompletion at the Sockeye field.

The company's capital expenditure budget for 2013 is $91 million. Of that amount, $78 million is anticipated to be spent at the company's legacy Southern California properties. At South Ellwood, the company's capital budget includes completing both the 3242-4RD and the 3242-19 probable well that was suspended in the third quarter of 2012. The budget also includes plans to spud and complete one to two additional wells in the South Ellwood field during 2013. Additionally, the company plans to drill four proved undeveloped locations and one probable location at West Montalvo in 2013. No significant activity is planned at the Sockeye field in 2013. The company expects production levels from its Southern California legacy fields to increase 20-25% in 2013 compared with 2012 as a result of its capital expenditure activity.

In 2012, the company had onshore Monterey capital expenditures of $76 million or 35% of its total 2012 capital expenditures. During the year, the company spud five wells and completed six wells, including one well spud in 2011. All of the wells completed during the year were located in the Sevier field. In addition to the wells spud and completed, the company completed a water pipeline and substantially completed oil and natural gas pipelines from the Sevier field to the respective points of sale.

The company's 2013 capital expenditure budget for the onshore Monterey shale project has been significantly reduced from 2012 levels to $13 million in 2013. Similar to 2012, the company's focus with respect to the onshore Monterey shale will continue to be on the Sevier field. The capital expenditure budget contemplates drilling one horizontal well in the Sevier field and continued improvements to production facilities in the field. The agreement governing the company's revolving credit facility limits the amount of capital that can be deployed in onshore Monterey activities, which could reduce the amount of capital spent in 2013 below the budgeted level.

During 2012, the company spent $26 million or 12% of its capital expenditures in the Sacramento Basin. The company spud four wells and performed approximately 250 recompletions in the basin during the year. The reduced capital activity in the Sacramento Basin was anticipated and was the result of the low natural gas price environment that currently exists.

Reserves Review

The company's year-end 2012 total proved reserves were 52.2 million BOE, compared to year-end 2011 reserves of 95.9 million BOE. Pro forma for the sales of the Sacramento Basin and Santa Clara Avenue (sold in the second quarter of 2012) properties, proved reserves increased by 5% over year-end 2011 reserves of 49.7 million BOE. After adjusting for 2012 production of 3.1 million BOE, pro forma for the sales of the Sacramento Basin and Santa Clara Avenue properties, the company added reserves of 5.6 million BOE, including revisions, extensions and discoveries, which primarily related to progress made by Denbury Resources in implementing the CO2 enhanced oil recovery project at the Hastings field and successful wells drilled at South Ellwood during the year. The increase realized was partially offset by proved undeveloped reserves that were removed at yearend related to the 3242-4 well at South Ellwood, which was wet when initially completed late in 2012. The company's year-end 2012 proved reserves do not include any reserves for the 3242-4RD well completed in the first quarter of 2013.

"The Hastings field was returned to production in mid-January 2012 and it has responded very favorably to the CO2 flood that Denbury Resources has implemented. The response has enabled us to convert a portion of our probable reserves to proved during 2012," said Mr. O'Donnell. "As of yearend, we removed the reserves associated with the 3242-4 well at South Ellwood that we drilled during the year. However, we completed the re-drill of this well in the first quarter of 2013 and it produced at an average rate of approximately 1,500 gross BOE per day in the last 20 days of March and as a result, we expect that we will be able to record proved reserves associated with this well in 2013."

The company's 2012 rollforward of proved reserves is as follows:


2012 Reserve Rollforward MBOE(1) ----------Beginning of the year reserves 95,884Revisions of previous estimates (4,387)Extensions and discoveries 9,948Purchases of reserves in place -Production (6,345)Sales of reserves in place (42,857) ----------End of year reserves 52,243 ==========Proved developed reserves:Beginning of year 48,765End of year 36,324(1) Barrel of oil equivalent (BOE) is calculated using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.




The $1.5 billion pre-tax PV-10 value of the company's 52.2 MMBOE of reserves is based on SEC benchmark pricing of $94.71 per barrel of oil and $2.76 per MMBTU for gas.

The following table details the company's reserve categories and PV-10 for the last three years:


Net Proved Reserves (end of period) 2010 2011 2012 ------------ ------------ ------------Oil (MBbls) Developed 22,270 25,131 35,115 Undeveloped 20,301 22,282 15,320 ------------ ------------ ------------ Total 42,571 47,413 50,435Natural Gas (MMcf) Developed 122,928 141,806 7,255 Undeveloped 132,235 149,018 3,595 ------------ ------------ ------------ Total 255,163 290,824 10,850 ------------ ------------ ------------Total Proved Reserves (MBOE)(1) 85,098 95,884 52,243 ============ ============ ============PV-10 ($000) Developed $ 575,152 $ 990,303 $ 1,076,145 Undeveloped 553,544 816,198 433,588 ------------ ------------ ------------ Total $ 1,128,696 $ 1,806,501 $ 1,509,733 ============ ============ ============(1) Barrel of oil equivalent (BOE) is calculated using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.




Financing Update

In March 2013, the company entered into an amendment to the credit agreement governing its revolving credit facility, which resulted in an increase to the borrowing base to $270 million (subject to commitments of $268 million), revisions to the total debt leverage covenant ratio and the addition of a secured debt leverage covenant. On March 29, 2013, the company used proceeds from the amended revolving credit facility to repay the remaining principal outstanding on the second lien term loan. As of April 15, 2013, $237 million was outstanding on the revolving credit facility.

2013 Guidance

The following summarizes the company's 2013 guidance:

•Production: 10,000 - 10,500 BOE/d •Capital Budget: $90 - $100 million •Lease Operating Expenses: $20.50 - $21.50 per BOE •General & Administrative Expenses (excluding non-cash charges related to share-based compensation): $11.00 - $11.50 per BOE •Production & Property Taxes: $1.80 - $2.20 per BOE •DD&A: $12.50 - $13.50 per BOE

Earnings Conference Call

Venoco will host a conference call to discuss results Tuesday, April 16, 2013 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) 318-8612 and use conference code 37269966. International participants can call (617) 399-5131 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 28595973. The replay will also be available on the Venoco website for 30 days.

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 and operates several onshore properties in Southern California.

Forward-looking Statements

Statements made in this news release relating to Venoco's future production, reserves, expenses, capital expenditures and development projects, final proceeds from its recent asset sale, and all other statements except statements of historical fact, are forward-looking statements. 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.

References to reserve estimates other than proved are by their nature more uncertain than estimates of proved reserves, and are subject to substantially greater risk of not actually being realized by the company.


OIL AND NATURAL GAS PRODUCTION AND PRICES Quarter Ended Quarter Ended -------------------------- --------------------------- % %UNAUDITED 9/30/12 12/31/12 Change 12/31/11 12/31/12 Change ------- -------- ------- -------- -------- -------Production Volume:Oil (MBbls) (1) 839 768 -8% 620 768 24%Natural Gas (MMcf) 4,846 4,742 -2% 6,111 4,742 -22% ------- -------- ------- -------- -------- -------MBOE 1,647 1,558 -5% 1,639 1,558 -5% ======= ======== ======= ======== ======== =======Daily Average Production Volume:Oil (Bbls/d) 9,120 8,348 -8% 6,739 8,348 24%Natural Gas (Mcf/d) 52,674 51,543 -2% 66,424 51,543 -22% ------- -------- ------- -------- -------- -------BOE/d 17,899 16,939 -5% 17,810 16,939 -5% ======= ======== ======= ======== ======== =======Oil Price per Barrel Produced (in dollars):Realized price before hedging $ 96.20 $ 94.53 -2% $ 93.79 $ 94.53 1%Realized hedging gain (loss) (9.68) (11.08) 14% (1.35) (11.08) 721% ------- -------- ------- -------- -------- -------Net realized price $ 86.52 $ 83.45 -4% $ 92.44 $ 83.45 -10% ======= ======== ======= ======== ======== =======Natural Gas Price per Mcf (in dollars):Realized price before hedging $ 2.86 $ 3.60 26% $ 3.60 $ 3.60 0%Realized hedging gain (loss) 0.11 (0.09) -182% 1.29 (0.09) -107% ------- -------- ------- -------- -------- -------Net realized price $ 2.97 $ 3.51 18% $ 4.89 $ 3.51 -28% ======= ======== ======= ======== ======== =======Expense per BOE (in dollars):Lease operating expenses $ 13.90 $ 15.69 13% $ 13.87 $ 15.69 13%Production and property taxes $ 1.01 $ 0.71 -30% $ 0.97 $ 0.71 -27%Transportation expenses $ 0.29 $ 0.01 -97% $ 1.42 $ 0.01 -99%Depreciation, depletion and amortization $ 13.50 $ 13.53 0% $ 13.43 $ 13.53 1%General and administrative (2) $ 7.18 $ 13.56 89% $ 6.89 $ 13.56 97%Interest expense $ 10.02 $ 14.96 49% $ 10.03 $ 14.96 49% OIL AND NATURAL GAS PRODUCTION AND PRICES Year Ended --------------------------- %UNAUDITED 12/31/11 12/31/12 Change -------- -------- -------Production Volume:Oil (MBbls) (1) 2,441 2,940 20%Natural Gas (MMcf) 23,923 20,430 -15% -------- -------- -------MBOE 6,428 6,345 -1% ======== ======== =======Daily Average Production Volume:Oil (Bbls/d) 6,688 8,033 20%Natural Gas (Mcf/d) 65,542 55,820 -15% -------- -------- -------BOE/d 17,612 17,336 -2% ======== ======== =======Oil Price per Barrel Produced (in dollars):Realized price before hedging $ 91.00 $ 97.28 7%Realized hedging gain (loss) (2.48) (10.32) 316% -------- -------- -------Net realized price $ 88.52 $ 86.96 -2% ======== ======== =======Natural Gas Price per Mcf (in dollars):Realized price before hedging $ 4.02 $ 2.88 -28%Realized hedging gain (loss) 1.03 0.25 -76% -------- -------- -------Net realized price $ 5.05 $ 3.13 -38% ======== ======== =======Expense per BOE (in dollars):Lease operating expenses $ 14.64 $ 14.48 -1%Production and property taxes $ 0.99 $ 1.53 55%Transportation expenses $ 1.45 $ 0.81 -44%Depreciation, depletion and amortization $ 13.35 $ 13.68 2%General and administrative (2) $ 6.10 $ 8.70 43%Interest expense $ 9.51 $ 11.25 18%(1) Amounts shown are oil production volumes for offshore properties andsales volumes for onshore properties (differences between onshore productionand sales volumes are minimal). Revenue accruals are adjusted for actualsales volumes since offshore oil inventories can vary significantly frommonth to month based on pipeline inventories, oil pipeline salesnominations, and prior to February 2012, the timing of barge deliveries andoil in tanks.(2) Net of amounts capitalized. CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS Quarter Ended Quarter Ended Year Ended ------------------ ------------------ ------------------UNAUDITED (In thousands) 9/30/12 12/31/12 12/31/11 12/31/12 12/31/11 12/31/12 -------- -------- -------- -------- -------- --------REVENUES:Oil and natural gas sales $ 95,377 $ 90,725 $ 81,890 $ 90,725 $323,423 $350,426Other 1,321 1,231 1,478 1,231 5,355 6,090 -------- -------- -------- -------- -------- --------Total revenues 96,698 91,956 83,368 91,956 328,778 356,516 -------- -------- -------- -------- -------- --------EXPENSES:Lease operating expense 22,899 24,446 22,740 24,446 94,100 91,888Property and production taxes 1,671 1,100 1,593 1,100 6,376 9,688Transportation expense 482 18 2,325 18 9,348 5,169Depletion, depreciation and amortization 22,240 21,073 22,007 21,073 85,817 86,780Accretion of asset retirement obligation 1,457 1,470 1,602 1,470 6,423 5,768General and administrative 11,822 21,134 11,297 21,134 39,186 55,186 -------- -------- -------- -------- -------- --------Total expenses 60,571 69,241 61,564 69,241 241,250 254,479 -------- -------- -------- -------- -------- --------Income from operations 36,127 22,715 21,804 22,715 87,528 102,037FINANCING COSTS AND OTHER:Interest expense 16,498 23,310 16,435 23,310 61,113 71,399Interest rate derivative realized (gains) losses - - - - 41,147 -Interest rate derivative unrealized (gains) losses - - - - (40,064) -Amortization of deferred loan costs 597 1,005 595 1,005 2,310 2,756Loss on extinguishment of debt - 1,520 - 1,520 1,357 1,520Commodity derivative realized (gains) losses 7,597 13,296 (19,110) 13,296 (30,656) (26,989)Commodity derivative unrealized (gains) losses and amortization of derivative premiums 41,492 (13,278) (6,538) (13,278) (9,993) 99,938 -------- -------- -------- -------- -------- --------Total financing costs and other 66,184 25,853 (8,618) 25,853 25,214 148,624 -------- -------- -------- -------- -------- --------Income (loss) before taxes (30,057) (3,138) 30,422 (3,138) 62,314 (46,587)Income tax provision (benefit) - - - - - - -------- -------- -------- -------- -------- --------Net income (loss) $(30,057) $ (3,138) $ 30,422 $ (3,138) $ 62,314 $(46,587) ======== ======== ======== ======== ======== ======== CONDENSED CONSOLIDATED BALANCE SHEET INFORMATIONUNAUDITED ($ in thousands) 12/31/11 12/31/12 ----------- -----------ASSETS Cash and cash equivalents $ 8,165 $ 53,818 Accounts receivable 30,017 108,356 Inventories 7,411 5,101 Other current assets 4,296 4,448 Commodity derivatives 47,768 153 ----------- ----------- Total current assets 97,657 171,876 Net property, plant and equipment 810,465 648,602 Total other assets 21,622 25,603 ----------- -----------TOTAL ASSETS $ 929,744 $ 846,081 =========== ===========LIABILITIES AND STOCKHOLDERS' EQUITY Accounts payable and accrued liabilities $ 53,098 $ 57,315 Interest payable 21,854 27,862 Current maturities of long-term debt - 104,494 Commodity derivatives 2,490 20,607 Share based compensation - 10,424 ----------- ----------- Total current liabilities 77,442 220,702LONG-TERM DEBT 686,958 849,190COMMODITY DERIVATIVES 308 20,287ASSET RETIREMENT OBLIGATIONS 92,008 41,119SHARE BASED COMPENSATION - 10,441 ----------- ----------- Total liabilities 856,716 1,141,739 Total stockholders' equity 73,028 (295,658) ----------- -----------TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 929,744 $ 846,081 =========== ===========




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) 12/31/11 9/30/12 12/31/12 12/31/11 12/31/12 -------- -------- -------- -------- --------Adjusted Earnings ReconciliationNet Income $ 30,422 $(30,057) $ (3,138) $ 62,314 $(46,587)Plus:Unrealized commodity (gains) losses (10,626) 40,289 (14,480) (20,051) 87,514Unrealized interest rate derivative (gains) losses - - - (40,064) -Going private related costs 750 1,277 5,240 1,642 9,997Severance costs - - 1,496 - 1,496Loss on extinguishment of debt - - 1,520 1,357 1,520Settlement of interest rate swap contracts - - - 38,065 -Tax effects - - - - - -------- -------- -------- -------- --------Adjusted Earnings $ 20,546 $ 11,509 $ (9,362) $ 43,263 $ 53,940 ======== ======== ======== ======== ======== Quarter Ended Year Ended ---------------------------- ------------------UNAUDITED ($ in thousands) 12/31/11 9/30/12 12/31/12 12/31/11 12/31/12 -------- -------- -------- -------- --------Adjusted EBITDA ReconciliationNet income $ 30,422 $(30,057) $ (3,138) $ 62,314 $(46,587)Interest expense 16,435 16,498 23,310 61,113 71,399Interest rate derivative (gains) losses - realized - - - 41,147 -DD&A 22,007 22,240 21,073 85,817 86,780Accretion of asset retirement obligation 1,602 1,457 1,470 6,423 5,768Amortization of deferred loan costs 595 597 1,005 2,310 2,756Loss on extinguishment of debt - - 1,520 1,357 1,520Non-cash share-based compensation expense 1,781 1,497 1,952 6,747 6,197Going private related costs 750 1,277 5,240 1,642 9,997Sacramento Basin severance costs - - 1,496 - 1,496Amortization of derivative premiums 4,088 1,203 1,202 10,058 12,424Unrealized commodity derivative (gains) losses (10,626) 40,289 (14,480) (20,051) 87,514Unrealized interest rate derivative (gains) losses - - - (40,064) - -------- -------- -------- -------- --------Adjusted EBITDA $ 67,054 $ 55,001 $ 40,650 $218,813 $239,264 ======== ======== ======== ======== ========




We also provide per BOE G&A expenses excluding costs associated with the going-private transaction, severance costs related to the sale of the Sacramento Basin assets and non-cash 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 ---------------------------- ------------------ 12/31/11 9/30/12 12/31/12 12/31/11 12/31/12 -------- -------- -------- -------- --------G&A per BOE ReconciliationG&A expense $ 11,297 $ 11,822 $ 21,134 $ 39,186 $ 55,186Less:Non-cash share-based compensation expense (1,591) (1,337) (1,500) (5,667) (5,075)Going private related costs (750) (1,277) (5,240) (1,642) (9,997)Sacramento Basin severance costs - - (1,200) - (1,200) -------- -------- -------- -------- --------G&A Expense Excluding Share-Based Comp Going Private Costs 8,956 9,208 13,194 31,877 38,914MBOE 1,639 1,647 1,558 6,428 6,345 -------- -------- -------- -------- --------G&A Expense per BOE Excluding Share-Based Comp and Going Private Costs $ 5.46 $ 5.59 $ 8.47 $ 4.96 $ 6.13 ======== ======== ======== ======== ========




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%.

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


UNAUDITED ($ in thousands) 12/31/2010 12/31/2011 12/31/2012 ----------- ----------- -----------Standardized measure of discounted future net cash flows $ 902,901 $ 1,364,146 $ 1,157,452Add: Present value of future income tax discounted at 10% 225,795 442,355 352,281 ----------- ----------- -----------PV-10 at year end SEC prices $ 1,128,696 $ 1,806,501 $ 1,509,733 =========== =========== ===========





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Kevin Hehn
Investor Relations
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