SOURCE: Venoco, Inc.

Venoco, Inc.

November 01, 2011 05:02 ET

Venoco, Inc. Announces Third Quarter 2011 Financial and Operational Results

DENVER, CO--(Marketwire - Nov 1, 2011) - Venoco, Inc. (NYSE: VQ) today reported financial and operational results for the third quarter of 2011. Highlights include the following:

  • Net Income $37 Million
  • Adjusted EBITDA $42 Million
  • South Ellwood Pipeline Approved; Construction Underway
  • Onshore Monterey Sevier Field Delineation Wells on Production

The company reported net income of $37 million, Adjusted EBITDA of $42 million, and an Adjusted Loss of $0.3 million for the quarter on oil and gas revenues of $77 million and realized commodity derivative gains of $3 million. Through nine months of 2011, the company reported net income of $32 million, Adjusted EBITDA of $152 million, and Adjusted Earnings of $23 million on oil and gas revenues of $242 million and realized commodity derivative gains of $12 million. Please see the end of this release for a definition of Adjusted Earnings and Adjusted EBITDA and a reconciliation of those measures to net income (loss).

Production

Production averaged 17,265 barrels of oil equivalent (BOE) per day during the third quarter, down slightly from 17,560 BOE per day during the second quarter. Through the first nine months of 2011, production averaged 17,544 BOE per day, down from 17,931 BOE per day through nine of months of 2010 (pro forma for the sale of the company's producing properties in Texas).

Southern California production was down during the third quarter as the result of a planned, annual maintenance shutdown at South Ellwood and a subsequent pump failure on one of the largest producing wells in the field, which combined reduced third quarter production by approximately 300 BOE per day. The company began a drilling / workover program at its legacy Southern California assets late in the second quarter of 2011 which will continue through year-end and is expected to result in quarter-to-quarter production growth. Activity levels in the Sacramento Basin were steady quarter-to-quarter and production was up slightly.

"We were pleased to establish commercial production in our first delineation well at our onshore Monterey Sevier field, which has a net resource potential of 76 million BOE. The well is shut in while we drill another delineation well from the same pad, however its last 30-days of production averaged 43 BOE per day," commented Tim Marquez, Venoco's Chairman and CEO. The company's first well at Sevier, initially drilled and completed in early 2010, tested oil from various zones for a cumulative 170 BOE per day. The company calculated the initial production potential of the well, if fully pumped, would have been 300 BOE per day. "Our second delineation well was recently completed and had a peak 24-hour production rate of 221 BOE per day, a stabilized 7-day production rate of about 190 BOE per day, and has average production of 165 BOE per day over a 26-day period. The logs on the third delineation well are encouraging and we are anxious to get test results."

"We've also experienced recent success at West Montalvo where we completed our first well of the year during the third quarter and have subsequently spud three additional wells. Between recompletions and drilling new wells, current production at the West Montalvo field is up almost 20% over the average for the first nine months," commented Mr. Marquez. "We plan to spud two additional West Montalvo wells during the fourth quarter. With improving production from the West Montalvo field, we expect to enter 2012 well above company-wide average 2011 production levels. However, we do not expect fourth quarter production to have much impact on 2011 averages, so we are adjusting our full year 2011 production guidance down to 17,500 BOE per day."

The following table details the company's daily production by region for each of the periods presented (BOE/d):

Region Quarter Ended Nine Months Ended Full Year 2011
9/30/10 6/30/11 9/30/11 9/30/10 9/30/11 Guidance
Sacramento Basin 10,284 10,217 10,337 9,990 10,381 n/a
Southern California 7,803 7,343 6,928 7,941 7,163 n/a
Existing Operations 18,087 17,560 17,265 17,931 17,544 17,500
Texas(1) - - - 618 - -
Total 18,087 17,560 17,265 18,549 17,544 17,500
(1) The company sold its producing Texas assets in a series of transactions during 2009 and 2010.

Costs and Expenses

Venoco's third quarter lease operating expenses (LOE) of $18.06 per BOE were higher than previous quarters due primarily to non-recurring work at its offshore platforms, which included returning an idle well to production at Platform Grace. In addition, the annual maintenance shutdown and wellwork at Platform Holly resulted in higher expenses and reduced volumes at the South Ellwood field. Wellwork at Platform Gail also contributed to the higher LOE during the third quarter. Due to this abnormally high quarter and projects planned for the fourth quarter, the company has updated its projections for full year 2011 LOE to $15.00 per BOE.

The following table details the company's costs and expenses per BOE for each of the periods presented:

Quarter Ended Nine Months Ended Full Year 2011
UNAUDITED (per BOE) 9/30/10 6/30/11 9/30/11 9/30/10 9/30/11 Guidance
Lease Operating Expenses $ 12.44 $ 13.14 $ 18.06 $ 12.67 $ 14.90 $ 15.00
Production/Property Taxes $ 1.05 $ 0.90 $ 1.13 $ 1.05 $ 1.00 $ 1.00
DD&A Expense $ 11.70 $ 13.59 $ 12.85 $ 11.49 $ 13.32 $ 13.00
G&A Expense(1) $ 4.31 $ 4.70 $ 4.43 $ 4.73 $ 4.79 $ 4.75
(1) Net of amounts capitalized and excluding stock-based compensation costs, costs related to the Special Committee's review of a going-private proposal from the company's Chairman and Chief Executive Officer, and severance costs associated with the sale of Texas assets. See the end of this release for a reconciliation of these amounts to GAAP G&A per BOE.

2011 Capital Expenditure Program

Total capital costs incurred in the third quarter were $55 million, including $41 million for drilling and recompletion activities, $3 million for facilities, and $11 million for geological and geophysical, leasehold, capitalized G&A, and other. Through nine months of 2011, the company has incurred $188 million in capital costs related to its development, exploitation and exploration capital expenditure budget of $250 million.

The company spent $17 million or 31% of its third quarter capital expenditures in the Sacramento Basin. The company began the quarter with two rigs and ended the quarter with one rig drilling in the Basin. The company spud 8 wells and performed 71 recompletions in the Basin during the third quarter. During the first nine months of the year the company spud 35 wells and performed 174 recompletions and 18 fracs in the Basin. The company plans to keep one rig drilling through the end of the year, to spud approximately 40 wells and to perform a total of approximately 220 recompletions and 20 fracs for the year.

Activities in the company's legacy Southern California assets accounted for $18 million or 33% of the company's third quarter capital expenditures. Capital expenditures in Southern California related primarily to drilling at West Montalvo where one well was completed and two additional wells were spud. The company expects to spud three additional wells at the West Montalvo field during the fourth quarter (one of which was spud in October) and to incur costs related to constructing the new, onshore pipeline for its South Ellwood field.

The company spent $19 million or 35% of its third quarter capital expenditures on projects targeting the onshore Monterey shale formation. The company spud two wells during the quarter and set casing on two wells that were spud earlier in the year. During the first nine months of the year the company spud nine wells and set casing on ten wells (including wells spud during 2010). The company completed its second delineation well at Sevier during the third quarter. This well was completed in the lowest zone in the wellbore, a zone that exhibited limited log response but has produced commercial levels of oil. The company has additional zones in each of its first two delineation wells yet to be tested, and also plans to re-evaluate other existing wellbores for additional recompletion opportunities based on recent results at Sevier. The company recently completed and is beginning to test its third delineation well. The company spud its fourth delineation well in Sevier early in the fourth quarter and expects to spud a fifth delineation well before year-end.

Currently the company's Monterey shale acreage position is approximately 312,000 gross and 214,000 net acres. The company's onshore acreage position is across three basins: Santa Maria, Salinas Valley, and San Joaquin (which includes the Sevier discovery). Of the company's total acreage position, approximately 60,000 gross and 46,000 net acres with Monterey shale production or potential are held by production in the company's legacy assets.

Improved California Crude Oil Pricing

Sales contracts under which the company currently sells a significant portion of its oil, which are based on the NYMEX WTI ("WTI") crude price index, will expire at the end of the first quarter of 2012. Prior to expiration of those contracts, Venoco expects to enter into new sales contracts based on certain Southern California crude price indexes, which have recently been at a premium to WTI and have more closely tracked with the Inter-Continental Exchange Brent crude price index ("Brent"). Approximately half of the company's crude oil is currently sold under the WTI-based contracts, while the balance is sold on contracts tied to California posted prices, which have exceeded WTI by up to $30 per barrel during 2011. The company's average 2010 realized oil prices were approximately $10 per barrel less than WTI; however, as a result of recent higher California postings, its average oil price realizations during the first nine months of 2011 have improved to approximately $5 less than WTI. Assuming the company replaces its existing WTI-based oil sales contracts upon expiration with Southern California index-based sales contracts and using the current forward strip pricing with the current California basis differentials, Venoco's company-wide average realized oil prices in 2012 would exceed WTI by approximately $17 per barrel, or a $22 per barrel improvement over current realized pricing. This includes price realization improvements expected as a result of completing the South Ellwood pipeline in 2012.

South Ellwood Pipeline

As previously announced, the company received the final approvals needed to install an onshore pipeline to transport crude oil from the company's South Ellwood field. The company began preliminary construction of the pipeline in the third quarter and began critical-path borings in early October. Venoco believes it can complete the project in the first quarter of 2012 subject to possible weather-related delays. Based on SEC pricing as of September 30, 2011, the company added approximately nine million BOE of proved reserves as of September 30, 2011 as a result of receiving approvals to construct the pipeline.

"We are extremely pleased to be moving forward with the pipeline project after having spent several years in the permitting process," commented Mr. Marquez. "In addition to adding reserves as a result of receiving project approval, once the pipeline is operational we also anticipate receiving an additional $5 to $7 per barrel for our crude as a result of lower transportation costs and increased marketability," added Mr. Marquez.

2012 Overview

"We are in the process of developing our 2012 capital budget. Overall, we expect capital expenditures in 2012 will likely be below 2011 levels, but anticipate increased spending at legacy Southern California fields, which received approximately 25% of the 2011 capital budget but will likely receive about 40% of the 2012 capital allocation. With an increase in spending at our legacy Southern California fields our production mix would become more oil weighted next year and our realized per BOE prices could increase by over 20% next year," commented Mr. Marquez. "We've been able to establish commercial production at our Sevier field in zones that exhibited limited log response. The results from the next few wells we drill in Sevier, as well as our re-evaluation of existing wellbores, could impact how we decide to allocate the remainder of the 2012 budget between onshore Monterey shale activities and the Sacramento Basin," added Mr. Marquez.

Hastings Field

The company continues to monitor progress at the Hastings field where it owns a 22.3% reversionary working interest in the CO2 flood that Denbury Resources is in the process of implementing. It is expected that the new CO2 processing facilities will be commissioned beginning late in December with full production from the first phase of the project expected late in the first quarter of 2012. Venoco will earn, at no cost, its 22.3% working interest in this large producing oil field when the Hastings field reaches payout for Denbury.

Special Committee Process

On August 26, 2011, the company's board of directors received a proposal from Mr. Marquez 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. The proposal is subject to, among other things, Mr. Marquez being able to secure financing with acceptable terms. The company's board of directors has formed a special committee comprised of all independent directors to evaluate and consider this proposal as well as third party alternatives. The special committee has retained Bank of America Merrill Lynch and Strategic Energy Advisors as independent financial advisors to assist it in, among other things, evaluating and determining the company's response to the non-binding proposal made by Mr. Marquez, as well as soliciting and evaluating any third-party proposals. The special committee process is ongoing and no decisions have been made with respect to the company's response to the proposal or any third party alternatives. Shareholders are cautioned that there can be no assurance that the company will complete a transaction with any party.

Earnings Conference Call

Venoco will host a conference call to discuss results today, Tuesday, November 1, 2011 at 11:00 a.m. Eastern time (9 a.m. Mountain). The conference call will be webcast and those wanting to listen may do so by using a link on the Investor Relations page of the company's website at http://www.venocoinc.com. Those wanting to participate in the Q&A portion can call (866) 831-6267 and use conference code 64487044. International participants can call (617) 213-8857 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 75813967. 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 (including the effect of exploration, development and maintenance activities on production rates), and future expenses, capital expenditures, development projects and reserves, 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. Among other things, forward-looking statements relate to (i) the construction process for the South Ellwood pipeline project and the potential effect of the project on the company's price realizations and costs, (ii) potential future sales contracts based on California posted oil prices and the effect of those contracts on the company's price realizations, and (iii) the timing and results of the CO2 flood project at the Hastings field. 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 and sales 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 company may not be able to complete the South Ellwood pipeline project in the time frame it expects. It may not be able to complete future transactions, including with respect to the potential sale of its interest in the Hastings CO2 project and future oil sales contracts, on the terms it anticipates or at all. The going-private proposal submitted by Mr. Marquez was not a definitive offer, and there can be no assurance that any definitive offer will be made, that any agreement will be executed or that a definitive offer, if made, with respect to the proposal or any other transaction will be approved or consummated. 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.

The term discovery, as used in this press release, refers to a petroleum accumulation or accumulations for which one or several exploratory wells have, in the company's judgment, established through testing, sampling and/or logging the existence of a significant quantity of potentially moveable hydrocarbons.

References to resource potential and other potential reserve estimates reflect internal estimates of resources that may potentially be recoverable through additional drilling or recovery techniques. Such estimates are by their nature more uncertain than estimates of proved reserves and are not discounted to reflect the risk of production impediments, unsuccessful development activity, permitting issues, cost increases and other potential problems. Accordingly, those estimated resources 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 Nine Months Ended
UNAUDITED 6/30/11 9/30/11 % Change 9/30/10 9/30/11 % Change 9/30/10 9/30/11 % Change
Production Volume:
Oil (MBbls)(1) 619 594 -4 % 682 594 -13 % 2,163 1,821 -16 %
Natural Gas (MMcf) 5,874 5,966 2 % 5,892 5,966 1 % 17,405 17,812 2 %
MBOE 1,598 1,588 -1 % 1,664 1,588 -5 % 5,064 4,790 -5 %
Daily Average Production Volume:
Oil (Bbls/d) 6,802 6,457 -5 % 7,413 6,457 -13 % 7,923 6,670 -16 %
Natural Gas (Mcf/d) 64,549 64,848 0 % 64,043 64,848 1 % 63,755 65,245 2 %
BOE/d 17,560 17,265 -2 % 18,087 17,265 -5 % 18,549 17,544 -5 %
Oil Price per Barrel Produced (in dollars):
Realized price before hedging $ 96.37 $ 87.24 -9 % $ 65.88 $ 87.24 32 % $ 67.20 $ 90.06 34 %
Realized hedging gain (loss) (5.37 ) (5.01 ) -7 % (1.28 ) (5.01 ) 291 % (1.40 ) (3.97 ) 184 %
Net realized price $ 91.00 $ 82.23 -10 % $ 64.60 $ 82.23 27 % $ 65.80 $ 86.09 31 %
Natural Gas Price per Mcf (in dollars):
Realized price before hedging $ 4.29 $ 4.18 -3 % $ 3.93 $ 4.18 6 % $ 4.46 $ 4.16 -7 %
Realized hedging gain (loss) 0.82 0.93 13 % 1.99 0.93 -53 % 1.55 0.91 -41 %
Net realized price $ 5.11 $ 5.11 0 % $ 5.92 $ 5.11 -14 % $ 6.01 $ 5.07 -16 %
Expense per BOE (in dollars):
Lease operating expenses $ 13.14 $ 18.06 37 % $ 12.44 $ 18.06 45 % $ 12.67 $ 14.90 18 %
Production and property taxes $ 0.90 $ 1.13 26 % $ 1.05 $ 1.13 8 % $ 1.05 $ 1.00 -5 %
Transportation expenses $ 1.67 $ 1.49 -11 % $ 1.65 $ 1.49 -10 % $ 1.28 $ 1.47 15 %
Depreciation, depletion and amortization $ 13.59 $ 12.85 -5 % $ 11.70 $ 12.85 10 % $ 11.49 $ 13.32 16 %
General and administrative(2) $ 5.52 $ 5.82 5 % $ 4.97 $ 5.82 17 % $ 5.62 $ 5.82 4 %
Interest expense $ 10.00 $ 10.08 1 % $ 6.08 $ 10.08 66 % $ 6.03 $ 9.33 54 %
(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 Nine Months Ended
UNAUDITED (In thousands) 9/30/10 6/30/11 9/30/11 9/30/10 9/30/11
REVENUES:
Oil and natural gas sales $ 68,905 $ 85,918 $ 77,296 $ 219,333 $ 241,533
Other 1,507 1,371 1,635 3,893 3,877
Total revenues 70,412 87,289 78,931 223,226 245,410
EXPENSES:
Lease operating expense 20,707 21,000 28,684 64,152 71,360
Property and production taxes 1,742 1,439 1,796 5,314 4,783
Transportation expense 2,750 2,670 2,367 6,489 7,023
Depletion, depreciation and amortization 19,475 21,713 20,406 58,191 63,810
Accretion of asset retirement obligation 1,518 1,608 1,623 4,649 4,821
General and administrative 8,264 8,824 9,236 28,435 27,889
Total expenses 54,456 57,254 64,112 167,230 179,686
Income from operations 15,956 30,035 14,819 55,996 65,724
FINANCING COSTS AND OTHER:
Interest expense 10,117 15,976 16,005 30,539 44,678
Interest rate derivative realized (gains) losses 4,495 - - 13,563 41,147
Interest rate derivative unrealized (gains) losses 6,553 - - 23,285 (40,064 )
Amortization of deferred loan costs 499 592 592 1,855 1,715
Loss on extinguishment of debt - - - - 1,357
Commodity derivative realized (gains) losses (10,863 ) (3,507 ) (2,571 ) (23,869 ) (11,546 )
Commodity derivative unrealized (gains) losses and amortization of derivative premiums (10,033 ) (2,049 ) (36,001 ) (52,062 ) (3,455 )
Total financing costs and other 768 11,012 (21,975 ) (6,689 ) 33,832
Income (loss) before taxes 15,188 19,023 36,794 62,685 31,892
Income tax provision (benefit) (200 ) - - (400 ) -
Net income (loss) $ 15,388 $ 19,023 $ 36,794 $ 63,085 $ 31,892
Weighted average common shares outstanding:
Basic 52,410 58,718 58,738 51,844 57,881
Diluted 53,529 58,843 58,830 52,750 58,038

CONDENSED CONSOLIDATED BALANCE SHEET INFORMATION
UNAUDITED ($ in thousands) 12/31/10 9/30/11
ASSETS
Cash and cash equivalents $ 5,024 $ 9
Accounts receivable 29,602 31,715
Inventories 6,229 6,494
Other current assets 4,585 5,036
Income tax receivable 931 -
Commodity derivatives 26,407 50,870
Total current assets 72,778 94,124
Net property, plant and equipment 648,044 760,730
Total other assets 30,101 48,520
TOTAL ASSETS $ 750,923 $ 903,374
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable and accrued liabilities $ 45,396 $ 49,553
Interest payable 5,538 6,085
Commodity and interest derivatives 33,483 25,449
Total current liabilities 84,417 81,087
LONG-TERM DEBT 633,592 681,781
COMMODITY AND INTEREST DERIVATIVES 23,430 14,171
ASSET RETIREMENT OBLIGATIONS 93,721 86,561
Total liabilities 835,160 863,600
Total stockholders' equity (84,237 ) 39,774
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 750,923 $ 903,374

GAAP RECONCILIATIONS

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 items listed in the Adjusted Earnings reconciliation set forth in the table 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.

We define Adjusted EBITDA as net income (loss) before the items listed in the Adjusted EBITDA reconciliation set forth 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 Nine Months Ended
UNAUDITED ($ in thousands) 9/30/10 6/30/11 9/30/11 9/30/10 9/30/11
Adjusted Earnings Reconciliation
Net Income $ 15,388 $ 19,023 $ 36,794 $ 63,085 $ 31,892
Plus:
Unrealized commodity (gains) losses (15,690 ) (4,039 ) (37,991 ) (69,034 ) (9,425 )
Unrealized interest rate derivative (gains) losses 6,553 - - 23,285 (40,064 )
Special committee-related costs - - 892 - 892
Texas severance costs - - - 1,254 -
Loss on extinguishment of debt - - - - 1,357
Settlement of interest rate swap contracts - - - - 38,065
Tax effects - - - - -
Adjusted Earnings $ 6,251 $ 14,984 $ (305 ) $ 18,590 $ 22,717

Quarter Ended Nine Months Ended
UNAUDITED ($ in thousands) 9/30/10 6/30/11 9/30/11 9/30/10 9/30/11
Adjusted EBITDA Reconciliations:
Net income $ 15,388 $ 19,023 $ 36,794 $ 63,085 $ 31,892
Interest expense 10,117 15,976 16,005 30,539 44,678
Interest rate derivative (gains) losses - realized 4,495 - - 13,563 41,147
Income taxes (200 ) - - (400 ) -
DD&A 19,475 21,713 20,406 58,191 63,810
Accretion of asset retirement obligation 1,518 1,608 1,623 4,649 4,821
Amortization of deferred loan costs 499 592 592 1,855 1,715
Loss on extinguishment of debt - - - - 1,357
Share-based payments 1,387 1,579 1,563 4,118 4,966
Special committee-related costs - - 892 - 892
Texas severance costs - - - 1,254 -
Amortization of derivative premiums 5,657 1,990 1,990 16,972 5,970
Unrealized commodity derivative (gains) losses (15,690 ) (4,039 ) (37,991 ) (69,034 ) (9,425 )
Unrealized interest rate derivative (gains) losses 6,553 - - 23,285 (40,064 )
Adjusted EBITDA $ 49,199 $ 58,442 $ 41,874 $ 148,077 $ 151,759

We also provide per BOE G&A expenses excluding costs associated with the Texas asset sale, costs related to the Special Committee's review of the going-private proposal from the company's Chairman and Chief Executive Officer, 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 Nine Months Ended
9/30/10 6/30/11 9/30/11 9/30/10 9/30/11
G&A per BOE Reconciliation
G&A expense $ 8,264 $ 8,824 $ 9,236 $ 28,435 $ 27,889
Less:
Share-based compensation expense (1,097 ) (1,319 ) (1,303 ) (3,248 ) (4,076 )
Special Committee-related costs - - (892 ) - (892 )
Texas severance costs - - - (1,254 ) -
G&A Expense Excluding Share-Based Comp 7,167 7,505 7,041 23,933 22,921
MBOE 1,664 1,598 1,588 5,064 4,790
G&A Expense per BOE Excluding Share-Based Comp $ 4.31 $ 4.70 $ 4.43 $ 4.73 $ 4.79

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