SOURCE: Venoco, Inc.

Venoco, Inc.

February 16, 2012 06:02 ET

Venoco, Inc. Announces Year-End 2011 Reserves and 4th Quarter and Full-Year 2011 Financial and Operational Results

2011 Net Income of $62 Million; Adjusted EBITDA of $219 Million Full-Year 2011 Production of 6.4 Million BOE or 17,612 BOE/d; Proved Reserve Additions of 17 Million BOE

DENVER, CO--(Marketwire - Feb 16, 2012) - Venoco, Inc. (NYSE: VQ) today reported financial and operational results for the fourth quarter and full-year 2011. The company reported net income for the year of $62 million on total revenues of $329 million.

Adjusted Earnings, which adjusts for unrealized derivative gains and losses and certain one-time charges, were $43 million for the year. Adjusted EBITDA was $219 million in 2011, up slightly from $218 million in 2010. 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 6.4 million barrels of oil equivalent (MMBOE) for the year, or 17,612 BOE per day (BOE/d).
  • Proved reserves of 95.9 MMBOE as of December 31, 2011, up significantly over year-end 2010 proved reserves. Reserve replacement of 265% at an all-in F&D cost of $14.35 per BOE.
  • Ellwood pipeline completed ahead of schedule and is now in service. Transportation savings and higher price realization improve field economics.

"In 2011 we transitioned our focus from the Sacramento Basin toward our oily, Southern California legacy assets, while continuing to delineate our Sevier field and other portions of the onshore Monterey shale acreage," said Tim Marquez, Venoco's Chairman and CEO. "As a result of very strong California oil prices throughout 2011, we realized average oil prices of $91 per barrel for the year, up more than $22 per barrel from the average in 2010 even though only half of our oil production was sold on California postings. As of April 1, 2012, the other 50% of our oil will be sold based on California postings, which we expect to exceed NYMEX pricing in 2012 based on current differentials."

Fourth Quarter and Full-Year Production

Production in the fourth quarter of 2011 of 17,810 BOE/d was up over 3% from the third quarter of 2011 as well as up 3% from the fourth quarter of 2010.

"We recovered from the production delays in the third quarter to finish with a solid fourth quarter," commented Mr. Marquez. "We have had a good start in the new year as we concentrate our efforts on our oily assets. With natural gas prices expected to remain low in 2012, our plan is to minimize expenditures in the Sacramento Basin. As a result, we expect to see production volumes from the Basin trend down throughout 2012. However, our increased activity in the legacy Southern California assets, where we expect to see a 15-20% increase in oil volumes in 2012 compared to 2011, is expected to largely offset the decline in natural gas production. While we are forecasting basically flat production in 2012 compared to 2011, we expect the increase in our oil mix to result in significant revenue growth. In addition, we believe we've been conservative forecasting production from the Sevier field, so additional successful drilling in the field could further increase our oil over natural gas mix," Mr. Marquez added.

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

Full Year
Region 4Q 2010 3Q 2011 4Q 2011 2010 2011
Sacramento Basin 10,163 10,337 10,635 10,033 10,446
Southern California 7,165 6,928 7,175 7,745 7,166
Texas(2) - - - 463 -
Total 17,328 17,265 17,810 18,241 17,612
(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.
(2) Venoco sold its remaining producing assets in Texas in the first half of 2010.

Fourth Quarter and Full-Year Costs

Venoco's fourth quarter 2011 lease operating expenses of $13.87 per BOE were down from $18.06 per BOE in the third quarter. The third quarter expenses were unusually high on a per BOE basis due primarily to two high-cost electric submersible pump replacements in the quarter and a resulting reduction in production levels. The company's full-year 2011 lease operating expenses of $14.64 per BOE were below the company's revised guidance of $15.00 per BOE.

Quarter Ended Year Ended
UNAUDITED (per BOE) 12/31/10 9/30/11 12/31/11 12/31/10 12/31/11
Lease Operating Expenses $ 12.61 $ 18.06 $ 13.87 $ 12.65 $ 14.64
Production/Property Taxes 0.87 1.13 0.97 1.01 0.99
DD&A Expense 12.74 12.85 13.43 11.79 13.35
G&A Expense (1) 4.93 4.43 5.46 4.78 4.96
(1) Net of amounts capitalized and excluding stock-based compensation costs, costs related to the special committee's review of the going-private proposal from the company's Chairman & CEO and other costs associated with the sale of Texas assets.See the end of this release for a reconciliation of G&A per BOE.

Capital Investment 2011

Venoco's 2011 capital expenditures for exploration, development and other spending were $255 million, including $185 million for drilling and rework activities, $20 million for facilities, and the remaining $50 million for land, seismic and capitalized G&A.

In 2011 the company spent $74 million or 29% of its capital expenditures in the Sacramento Basin. The company spud 40 wells, performed 237 recompletions, and hydraulically fractured 21 wells in the basin. In early 2011 the company drilled a discovery well on an anomaly which was identified using 3D seismic data that was acquired with leasehold in 2009. The discovery well's net average production in 2011 was 2.3 million cubic feet per day and it extended the boundaries of the Grimes field. Additional wells were drilled in 2011 along this extension area which, combined with the discovery well, exited the year at a net rate of 8.3 million cubic feet per day. Additional opportunities have been identified in the area, but will not be pursued at current natural gas prices. In 2012 the company plans to reduce activity levels in the basin as a result of very low natural gas prices.

The company's 2012 capital expenditure budget remains at $255 million. However, the budget has been reallocated to focus resources on oily projects. The company's budget for the Sacramento Basin was reduced from $45 million to $32 million and includes 5 wells, 180 recompletions, and 7 hydraulic fractures. The company expects the decreased activity levels in the basin in 2012 compared to 2011 to result in a decline in average daily production there throughout the year.

The company's Southern California legacy fields accounted for $67 million or 26% of its 2011 capital expenditures. Five wells were spud at the West Montalvo field, one to an onshore bottom-hole and four to the offshore. The company also performed five recompletions in the field during 2011. At the Sockeye field the company redrilled two idle wells to new locations targeting the Monterey shale formation. One was a completion targeting the M4 portion of the Monterey, the other a horizontal well into the M2 portion of the Monterey. At the South Ellwood field, the company completed facilities work on Platform Holly in preparation for drilling activities. The company also permitted and began construction of a new common-carrier pipeline, which was completed and put in service in January 2012. As a result of receiving the approvals to construct the pipeline in 2011, the company was able to add approximately 8 million BOE of reserves at year-end 2011, which is reflected as a component of revisions in the reserve table below. In addition, with the pipeline now in service, the barge contract will terminate by June 1, 2012 and the company will realize a reduction in transportation costs for South Ellwood crude. The company also entered into a new sales contract for the crude oil that is expected to add $5 to $10 per barrel in 2012 to the company's realizations from the field.

The company's 2012 capital expenditure budget for legacy Southern California properties was increased from $110 million to $123 million and includes plans to drill seven wells at West Montalvo, one of which was spud in the fourth quarter of 2011. Two more wells were spud in the first quarter of 2012 with a third well scheduled to spud late in the quarter. The company plans to drill three wells in 2012 at the Sockeye field and four wells at the South Ellwood field. The company expects production levels from its Southern California legacy fields to grow 15-20% in 2012 compared with 2011.

The company increased its capital expenditures on its onshore Monterey shale play for the second year in a row, spending approximately $113 million or 44% of its 2011 capital expenditures. The company spud 12 wells during 2011 including nine vertical and three horizontal wells. Six of the verticals were in the Sevier field including four that spud in the fourth quarter. The company completed the second half of the joint 3D seismic shoot over its acreage in the San Joaquin Basin during 2011.

The company's 2012 capital expenditure budget for the onshore Monterey shale development is $100 million, with an emphasis on delineation and production at the Sevier field where the company plans to spud 15 to 20 wells. To date, the company has not seen material levels of production or reserves from the program. The company does believe it will see production resulting from the drilling and testing efforts at Sevier begun in 2011 and which are continuing into 2012. The company also plans to acquire seismic data at the Sevier and Salinas fields, and to recomplete several wells located in its greater San Joaquin leasehold.

"In the second quarter of 2011, we decided to focus our Monterey drilling on vertical delineation wells in the Sevier field. Each well has confirmed our geologic model and, in some cases, expanded our view of the structure. We have been methodical with our one-rig delineation program, but the data -- from cuttings, logs, and testing -- takes months to gather," commented Mr. Marquez. "We believe we are approaching the point where we can streamline completions, minimize zone-by-zone testing and get wells from spud to sales much more rapidly and efficiently in 2012."

Reserves Review

The company's year-end 2011 total proved reserves were 95.9 million BOE, compared to year-end 2010 reserves of 85.1 million BOE. After adjusting for 2011 production of 6.4 million BOE, the company added reserves of 17.2 million BOE, including revisions, extensions and discoveries, which were primarily related to permitting the crude oil pipeline at South Ellwood, oil price increase from year-end 2010, and drilling in new areas of the Sacramento Basin as well as performance in the Basin and at the Sockeye field.

"We are very pleased with the 17 million BOE of reserve adds this year that resulted from our capital expenditure program, strong California oil prices, new oil sales agreements and permitting the new pipeline to service the South Ellwood field," said Mr. Marquez. "A valuable asset that currently has minimal proven reserves is our 22.3% reversionary working interest in the Hastings field. After a year of flooding the field with CO2, Denbury Resources returned the field to production in mid-January. We have approximately 16 million barrels of probable reserves associated with the reversionary interest -- a portion of which we expect to be converted to proved once the field responds to the flood."

The company's 2011 rollforward of proved reserves is as follows:

2011 Reserve Rollforward MBOE(1)
Beginning of the year reserves 85,098
Revisions of previous estimates 849
Extensions and discoveries 16,298
Purchases of reserves in place 67
Production (6,428)
Sales of reserves in place -
End of year reserves 95,884
Proved developed reserves:
Beginning of year 42,758
End of year 48,765
(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 company's all-in finding and development (F&D) costs in 2011 were $14.35 per BOE and its 3-year and 5-year all-in F&D costs were $19.28 and $24.67 per BOE, respectively. Adjusting for capital related to the Monterey Shale play and the Hastings field before its sale in early 2009, the company estimates its 3-year and 5-year F&D costs would have been approximately $13.76 and $17.92 per BOE, respectively.

The $1.81 billion pre-tax PV-10 value of the company's 95.9 MMBOE of reserves is based on SEC benchmark pricing of $96.19 per barrel of oil and $4.12 per MMBTU for gas. Using the December 31, 2011 NYMEX 5-year strip pricing, the company's estimate of reserves is 96.8 MMBOE and the pre-tax PV-10 value is $1.76 billion. See the end of this release for a reconciliation of PV-10 to a standardized measure.

The following table details the company's reserve categories for the last three years and PV-10 for 2010 and 2011:

Net Proved Reserves (end of period) 2009PF(1) 2010 2011
Oil (MBbls)
Developed 25,750 22,270 25,131
Undeveloped 21,758 20,301 22,282
Total 47,508 42,571 47,413
Natural Gas (MMcf)
Developed 120,052 122,928 141,806
Undeveloped 142,314 132,235 149,018
Total 262,366 255,163 290,824
Total Proved Reserves (MBOE)(2) 91,236 85,098 95,884
PV-10 ($000)
Developed $ 575,152 $ 990,303
Undeveloped 553,544 816,198
Total $ 1,128,696 $ 1,806,501
(1) Pro forma for the sale of the company's Texas assets in the first half of 2010.
(2) 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.

2012 Guidance

The following summarizes the company's 2012 guidance:

  • Production: 17,750 - 18,250 BOE/d
  • Capital Budget: $255 million
  • Lease Operating Expenses: $15.00 - $15.50 per BOE
  • General & Administrative Expenses: $5.25 - $5.50 per BOE
  • Production & Property Taxes: $1.00 - $1.10 per BOE
  • DD&A: $15.00 - $15.50 per BOE

Special Committee Process

On August 26, 2011, the company's board of directors received a proposal from Mr. Marquez, Venoco's Chairman and CEO, to acquire all of the outstanding shares of common stock of Venoco of which he is not the beneficial owner for $12.50 per share in cash. Mr. Marquez is the beneficial owner of approximately 50.3% of Venoco's common stock. On January 16, 2012, the company announced that it entered into a definitive merger agreement under which Mr. Marquez will, through a wholly owned affiliate, acquire all of the outstanding shares of Venoco he does not already own.

Completion of the transaction is subject to certain closing conditions, including procurement of financing. The merger agreement also contains a non-waivable condition that a majority of the outstanding shares of Venoco not owned by Mr. Marquez and his affiliates, or by any director, officer or employee of Venoco or its subsidiaries, vote in favor of the adoption of the merger agreement. Shareholders are cautioned that there can be no assurance that the company will complete the merger.

Earnings Conference Call

Venoco will host a conference call to discuss results today, Thursday, February 16, 2012 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 (800) 706-7748 and use conference code 51448500. International participants can call (617) 614-3473 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 24271802. 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, operates three onshore properties in Southern California, and has extensive operations in Northern California's Sacramento Basin.

Forward-looking Statements

Statements made in this news release relating to Venoco's future production, expenses, revenue, price realizations (including in relation to benchmark prices), oil/gas production mix, reserves, capital expenditures and development projects, and all other statements except statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management's assumptions and the company's future performance are both subject to a wide range of business risks and uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including, but not limited to, the timing and extent of changes in oil and gas prices, the timing and results of drilling and other development activities, the availability and cost of obtaining drilling equipment and technical personnel, risks associated with the availability of acceptable transportation arrangements and the possibility of unanticipated operational problems, delays in completing production, treatment and transportation facilities, higher than expected production costs and other expenses, and pipeline curtailments by third parties. The company's activities with respect to the onshore Monterey Shale and other projects are subject to numerous operating, geological and other risks and may not be successful. The company's results in the onshore Monterey Shale will be subject to greater risks than in areas where it has more data and drilling and production experience. Results from the company's onshore Monterey Shale project will depend on, among other things, its ability to identify productive intervals and drilling and completion techniques necessary to achieve commercial production from those intervals. The closing of the merger agreement with Mr. Marquez is subject to a number of conditions, including a financing condition and a non-waivable condition that a majority of the outstanding shares of Venoco not owned by Mr. Marquez and his affiliates or by any director, officer or employee of Venoco or its subsidiaries vote in favor of the adoption of the merger agreement, and those conditions may not be satisfied. 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 Year Ended
UNAUDITED 9/30/11 12/31/11 % Change 12/31/10 12/31/11 % Change 12/31/10 12/31/11 % Change
Production Volume:
Oil (MBbls) (1) 594 620 4 % 629 620 -1 % 2,792 2,441 -13 %
Natural Gas (MMcf) 5,966 6,111 2 % 5,791 6,111 6 % 23,196 23,923 3 %
MBOE 1,588 1,639 3 % 1,594 1,639 3 % 6,658 6,428 -3 %
Daily Average Production Volume:
Oil (Bbls/d) 6,457 6,739 4 % 6,837 6,739 -1 % 7,649 6,688 -13 %
Natural Gas (Mcf/d) 64,848 66,424 2 % 62,946 66,424 6 % 63,551 65,542 3 %
BOE/d 17,265 17,810 3 % 17,328 17,810 3 % 18,241 17,612 -3 %
Oil Price per Barrel Produced (in dollars):
Realized price before hedging $ 87.24 $ 93.79 8 % $ 74.58 $ 93.79 26 % $ 68.86 $ 91.00 32 %
Realized hedging gain (loss) (5.01 ) (1.35 ) -73 % (3.02 ) (1.35 ) -55 % (1.77 ) (2.48 ) 40 %
Net realized price $ 82.23 $ 92.44 12 % $ 71.56 $ 92.44 29 % $ 67.09 $ 88.52 32 %
Natural Gas Price per Mcf (in dollars):
Realized price before hedging $ 4.18 $ 3.60 -14 % $ 3.96 $ 3.60 -9 % $ 4.34 $ 4.02 -7 %
Realized hedging gain (loss) 0.93 1.29 39 % 2.15 1.29 -40 % 1.70 1.03 -39 %
Net realized price $ 5.11 $ 4.89 -4 % $ 6.11 $ 4.89 -20 % $ 6.04 $ 5.05 -16 %
Expense per BOE (in dollars):
Lease operating expenses $ 18.06 $ 13.87 -23 % $ 12.61 $ 13.87 10 % $ 12.65 $ 14.64 16 %
Production and property taxes $ 1.13 $ 0.97 -14 % $ 0.87 $ 0.97 11 % $ 1.01 $ 0.99 -2 %
Transportation expenses $ 1.49 $ 1.42 -5 % $ 1.64 $ 1.42 -13 % $ 1.37 $ 1.45 6 %
Depreciation, depletion and amortization $ 12.85 $ 13.43 5 % $ 12.74 $ 13.43 5 % $ 11.79 $ 13.35 13 %
General and administrative (2) $ 5.82 $ 6.89 18 % $ 5.72 $ 6.89 20 % $ 5.64 $ 6.10 8 %
Interest expense $ 10.08 $ 10.03 0 % $ 6.30 $ 10.03 59 % $ 6.10 $ 9.51 56 %
(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 Year Ended
UNAUDITED (In thousands) 12/31/10 9/30/11 12/31/11 12/31/10 12/31/11
REVENUES:
Oil and natural gas sales $ 71,275 $ 77,296 $ 81,890 $ 290,608 $ 323,423
Other 791 1,635 1,478 4,684 5,355
Total revenues 72,066 78,931 83,368 295,292 328,778
EXPENSES:
Lease operating expense 20,103 28,684 22,740 84,255 94,100
Property and production taxes 1,387 1,796 1,593 6,701 6,376
Transportation expense 2,613 2,367 2,325 9,102 9,348
Depletion, depreciation and amortization 20,313 20,406 22,007 78,504 85,817
Accretion of asset retirement obligation 1,592 1,623 1,602 6,241 6,423
General and administrative 9,119 9,236 11,297 37,554 39,186
Total expenses 55,127 64,112 61,564 222,357 241,250
Income from operations 16,939 14,819 21,804 72,935 87,528
FINANCING COSTS AND OTHER:
Interest expense 10,045 16,005 16,435 40,584 61,113
Interest rate derivative realized (gains) losses 4,531 - - 18,094 41,147
Interest rate derivative unrealized (gains) losses (9,561 ) - - 13,724 (40,064 )
Amortization of deferred loan costs 507 592 595 2,362 2,310
Loss on extinguishment of debt - - - - 1,357
Commodity derivative realized (gains) losses (29,632 ) (2,571 ) (19,110 ) (53,501 ) (30,656 )
Commodity derivative unrealized (gains) losses and amortization of derivative premiums 37,514 (36,001 ) (6,538 ) (14,548 ) (9,993 )
Total financing costs and other 13,404 (21,975 ) (8,618 ) 6,715 25,214
Income (loss) before taxes 3,535 36,794 30,422 66,220 62,314
Income tax provision (benefit) (900 ) - - (1,300 ) -
Net income (loss) $ 4,435 $ 36,794 $ 30,422 $ 67,520 $ 62,314
Weighted average common shares outstanding:
Basic 53,451 58,738 58,772 52,249 58,106
Diluted 53,817 58,830 58,821 53,018 58,236
CONDENSED CONSOLIDATED BALANCE SHEET INFORMATION
UNAUDITED ($ in thousands) 12/31/10 12/31/11
ASSETS
Cash and cash equivalents $ 5,024 $ 8,165
Accounts receivable 29,602 30,017
Inventories 6,229 7,411
Prepaid expenses and other current assets 4,585 4,296
Income tax receivable 931 -
Commodity derivatives 26,407 47,768
Total current assets 72,778 97,657
Net property, plant and equipment 648,044 810,465
Total other assets 30,101 21,622
TOTAL ASSETS $ 750,923 $ 929,744
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable and accrued liabilities $ 45,396 $ 53,098
Interest payable 5,538 21,854
Commodity and interest derivatives 33,483 2,490
Total current liabilities 84,417 77,442
LONG-TERM DEBT 633,592 686,958
COMMODITY AND INTEREST DERIVATIVES 23,430 308
ASSET RETIREMENT OBLIGATIONS 93,721 92,008
Total liabilities 835,160 856,716
Total stockholders' equity (84,237 ) 73,028
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 750,923 $ 929,744

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) 12/31/10 9/30/11 12/31/11 12/31/10 12/31/11
Adjusted Earnings Reconciliation
Net Income $ 4,435 $ 36,794 $ 30,422 $ 67,520 $ 62,314
Plus:
Unrealized commodity (gains) losses 29,678 (37,991 ) (10,626 ) (39,356 ) (20,051 )
Unrealized interest rate derivative (gains) losses (9,561 ) - - 13,724 (40,064 )
Special Committee related costs - 892 750 - 1,642
Texas severance costs - - - 1,254 -
Loss on extinguishment of debt - - - - 1,357
Settlement of interest rate swap contracts - - - - 38,065
Tax effects - - - - -
Adjusted Earnings $ 24,552 $ (305 ) $ 20,546 $ 43,142 $ 43,263
Quarter Ended Year Ended
UNAUDITED ($ in thousands) 12/31/10 9/30/11 12/31/11 12/31/10 12/31/11
Adjusted EBITDA Reconciliation
Net income $ 4,435 $ 36,794 $ 30,422 $ 67,520 $ 62,314
Interest expense 10,045 16,005 16,435 40,584 61,113
Interest rate derivative (gains) losses - realized 4,531 - - 18,094 41,147
Income taxes (900 ) - - (1,300 ) -
DD&A 20,313 20,406 22,007 78,504 85,817
Accretion of asset retirement obligation 1,592 1,623 1,602 6,241 6,423
Amortization of deferred loan costs 507 592 595 2,362 2,310
Loss on extinguishment of debt - - - - 1,357
Share-based payments 1,535 1,563 1,781 5,653 6,747
Special Committee related costs - 892 750 - 1,642
Texas severance costs - - - 1,254 -
Amortization of derivative premiums 7,836 1,990 4,088 24,808 10,058
Unrealized commodity derivative (gains) losses 29,678 (37,991 ) (10,626 ) (39,356 ) (20,051 )
Unrealized interest rate derivative (gains) losses (9,561 ) - - 13,724 (40,064 )
Adjusted EBITDA $ 70,011 $ 41,874 $ 67,054 $ 218,088 $ 218,813

We also provide per BOE G&A expenses excluding costs associated with the Texas asset sales, costs related to the Special Committee review of the going-private proposal from the company's Chairman & CEO, 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
G&A per BOE Reconciliation 12/31/10 9/30/11 12/31/11 12/31/10 12/31/11
G&A expense $ 9,119 $ 9,236 $ 11,297 $ 37,554 $ 39,186
Less:
Share-based compensation expense (1,255 ) (1,303 ) (1,591 ) (4,503 ) (5,667 )
Special Committee related costs - (892 ) (750 ) - (1,642 )
Texas severance costs - - - (1,254 ) -
G&A Expense Excluding Share-Based Comp, Severance and Special Committee Costs 7,864 7,041 8,956 31,797 31,877
MBOE 1,594 1,588 1,639 6,658 6,428
G&A Expense per BOE Excluding Share-Based Comp, Severance and Special Committee Costs $ 4.93 $ 4.43 $ 5.46 $ 4.78 $ 4.96

PV-10

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

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

UNAUDITED ($ in thousands) 12/31/2010 12/31/2011
Standardized measure of discounted future net cash flows $ 902,901 $ 1,364,146
Add: Present value of future income tax discounted at 10% 225,795 442,355
PV-10 at year end SEC prices $ 1,128,696 1,806,501
Add: Effect of five year NYMEX strip at December 31, 2011 (43,180 )
PV-10 at five year NYMEX strip at December 31, 2011 $ 1,763,321

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