SOURCE: Venoco, Inc.

Venoco, Inc.

August 02, 2011 07:01 ET

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

DENVER, CO--(Marketwire - Aug 2, 2011) - Venoco, Inc. (NYSE: VQ) today reported financial and operational results for the second quarter of 2011. Highlights include the following:

  • Net Income $19 Million; Adjusted Earnings $15 Million
  • Adjusted EBITDA $58 Million, up 14% from 1Q
  • Lease operating expenses $13.14 per BOE, down 3% from 1Q
  • First of four 2011 delineation wells drilled in Sevier discovery
  • Large resource potential identified in Sacramento Basin
  • 2011 guidance revised

The company reported net income of $19 million for the quarter on oil and gas revenues of $86 million and realized commodity derivative gains of $4 million. Adjusted EBITDA was $58 million in the second quarter of 2011, up 14% from $51 million in the first quarter of 2011. Through six months of 2011, the company reported Adjusted EBITDA of $110 million on oil and gas revenues of $164 million and realized commodity derivative gains of $9 million.

Adjusted Earnings were $15 million, up from $8 million for the first quarter of 2011 and $3 million in the second quarter of 2010. Through six months of 2011, the company reported Adjusted Earnings of $23 million. 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).

Production

Overall, production in the second quarter of 2011 remained essentially steady relative to the first quarter of 2011. Production from the Sacramento Basin was up from the second quarter of 2010, but down slightly from the first quarter of 2011 due to intermittent high line-pressures from the company's principal customer PG&E and non-recurring compression maintenance.

Southern California production was up slightly from the first quarter of 2011, despite a very modest capital expenditure program in the area for several previous quarters. Second quarter production was adversely impacted by planned maintenance at the company's Beverly Hills field and its offshore Sockeye field where the company was successful in limiting the 2011 maintenance at Platform Gail -- normally a week -- to a two-day shutdown. Another of the company's offshore platforms, Platform Holly (South Ellwood field), completed its 10-day annual maintenance shutdown early in the third quarter. The shutdown at Platform Holly is expected to negatively affect third quarter production by approximately 300 BOE per day. Offsetting lost production due to downtime during the third quarter will be production from two wells redrilled at Sockeye and a well drilled at West Montalvo during the second quarter. Additionally, continued drilling at West Montalvo is expected to boost production in the second half of the year.

"After minimal activity in the first quarter in our oily Southern California legacy properties, we became quite active by the end of the second quarter and expect higher activity levels for the remainder of the year," commented Tim Marquez, Chairman and CEO. "It's an exciting time for the company; oil prices are strong (with California prices exceeding WTI), we have excellent liquidity, and a significant inventory of proven oil projects to pursue. The potential of our legacy Southern California assets has been somewhat overshadowed by the enormous potential we see with the onshore Monterey shale, but we're equally as excited about these properties and expect to pursue a number of development projects during the second half of this year and in 2012."

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

Region Quarter Ended Six Months Ended
6/30/10 3/31/11 6/30/11 6/30/10 6/30/11
Sacramento Basin 9,864 10,591 10,217 9,840 10,403
Southern California 7,744 7,224 7,343 8,014 7,284
Existing Operations 17,608 17,815 17,560 17,854 17,687
Texas (1) 582 - - 929 -
Total 18,190 17,815 17,560 18,783 17,687
(1) The company sold its producing Texas assets in a series of transactions during 2009 and 2010.

Capital Investment

Total capital costs incurred for the second quarter were $69 million, including $55 million for drilling and recompletion activities, $2 million for facilities, and $12 million for geological and geophysical, leasehold, capitalized G&A, and other. Through six months of 2011, the company has incurred $133 million in capital costs related to its development, exploitation and exploration capital expenditure budget of $200 million.

The company spent $20 million or 29% of its second quarter capital expenditures in the Sacramento Basin. Activities in the Basin consisted of a two-rig drilling program during the quarter. The company spud 13 wells and performed 48 recompletions and 9 fracs in the Basin during the second quarter. The company has spud 27 wells and performed approximately 100 recompletions in the Basin during the first half of the year and expects to drill a total of approximately 40 wells and perform a total of approximately 220 recompletions by the end of the year.

Activities in the company's legacy Southern California assets accounted for $15 million or 21% of the company's second quarter capital expenditures. Capital expenditures in Southern California were related primarily to two redrills at the Sockeye field, and drilling one new well and performing several recompletions at the West Montalvo field. The company expects to drill two to three additional wells at the West Montalvo field and perform three to six recompletions at the South Ellwood field during the second half of the year.

The company spent $34 million or 50% of its second quarter capital expenditures on projects targeting the onshore Monterey shale formation. The company spud two wells during the quarter and set casing on five wells that were spud earlier in the year. During the first half of the year the company spud seven wells and set casing on eight wells (including wells spud during 2010). The company expects to drill three to four additional delineation wells in its Sevier discovery during the second half of the year. The company also continues to expand its onshore Monterey acreage position which is currently approximately 304,000 gross and 214,000 net acres across three basins: Santa Maria, Salinas Valley, and San Joaquin (which includes the Sevier discovery). Of these totals, approximately 60,000 gross and 46,000 net acres with Monterey shale production or potential are held by production.

"We completed and began testing one zone in our Sevier 1-29 sidetrack well during the second quarter. Because this is a redrill, we have smaller casing in the well which limits our production volumes and presents a challenge to reducing fluid levels. With this constraint, we are encouraged by the peak 24-hour rate of 61 BOE per day from that initial zone. We have two other zones in this well to test once we're finished testing the initial zone," commented Mr. Marquez.

2011 Activity

The company is currently operating one rig in its Monterey shale play and is working to identify and secure up to four additional rigs by year-end 2011. The increase in rigs would be in anticipation of much greater activity in 2012 when the company currently expects it may run six to eight rigs in the play and spud between 50 and 75 primarily vertical wells, as warranted by drilling and production results. 2012 drilling activity will be focused on delineation and development wells in the company's Sevier discovery, in the area covered by the company's joint 3-D seismic shoot (with Occidental Petroleum) in the San Joaquin Valley and, after completion of an anticipated 3-D seismic survey, in the Salinas Valley.

"We are shoring up our development plans for the Sevier discovery and have been in contact with the agencies to ensure we have a clear path forward to develop this discovery. We currently expect to drill 30 to 40 wells there next year," said Mr. Marquez.

"We were pleased to see the recent U.S. Energy Information Administration's assessment of emerging resource plays, which confirms a lot of what we've been saying about the Monterey's resource potential. Not only is the Monterey shale the largest overall play, it also dwarfs all other individual U.S. oil shale plays. According to the EIA, at 15.4 billion barrels the Monterey shale represents 64% of the technically recoverable shale oil resources in the lower 48 states," commented Mr. Marquez.

In the Sacramento Basin the company has 457 proved, booked locations engineered by its independent reserve auditors on 20-acre or greater spacing and has identified over 150 additional 20-acre locations. The company has now drilled almost 100 10-acre spaced wells in the Forbes formation and believes the results prove the 10-acre concept in the play. The tighter spacing means that in addition to the 600+ 20-acre locations, the company has hundreds of potential 10-acre spaced locations. In order to accelerate the net present value of this enormous resource, the company plans to increase drilling activity to previous levels of approximately 100-120 wells per year once gas prices appear to be steady at or above $4.50/MCF. In total, the company believes that the infill potential represents about 680 BCF of technically proved resources, which the company believes would be considered reserves in the absence of the SEC five-year rule.

"We have a highly successful track record in the Sac Basin but in light of weak gas prices, we decided to constrain our Sac Basin activity in recent quarters. With prices now firming, I see an opportunity to accelerate our manufacturing process of drilling wells in the Basin and the potential to double our production in a couple years. If prices stabilize at an acceptable level, we currently plan to roughly double drilling rates next year and eventually build up to 200 to 300 wells per year," said Mr. Marquez.

In addition to the tremendous opportunity with further downspacing in the Sacramento Basin's Forbes formation, the company has also drilled and tested nearly two dozen wells to de-risk the deeper Guinda formation. The company estimates the net resource potential in the company's Willows field area is approximately 600 BCF based on about 900 locations and over 260 BCF based on about 400 locations in the company's Greater Grimes area.

Regarding the company's South Ellwood onshore pipeline project, the final Environmental Impact Report has been issued by the County of Santa Barbara and approval hearings are currently scheduled to begin in early August and may be finalized in the third quarter. The 8.5 mile pipeline will replace the double-hulled barge that is currently used to transport crude oil produced from the South Ellwood field. Once the project is approved, the company believes it will be able to add proved reserves at the South Ellwood field of at least 7 million barrels that are currently not recognized by the company's independent reserve engineers. In addition, the company expects to reduce transportation costs from the field by approximately $2 per barrel and eventually realize an additional $3 to $5 per barrel of oil sold as a result of access to a greater number of crude oil purchasers.

Costs and Expenses

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

Quarter Ended Six Months Ended
UNAUDITED (per BOE) 6/30/10 3/31/11 6/30/11 6/30/10 6/30/11
Lease Operating Expenses $ 13.65 $ 13.52 $ 13.14 $ 12.78 $ 13.33
Production/Property Taxes 0.82 0.97 0.90 1.05 0.93
DD&A Expense 11.32 13.53 13.59 11.39 13.56
G&A Expense (1) 5.10 5.22 4.70 4.93 4.96
Interest Expense (2) 9.39 10.17 10.37 9.07 10.27
Total $ 40.28 $ 43.41 $ 42.70 $ 39.22 $ 43.05
(1) Net of amounts capitalized and excluding stock-based compensation costs 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.
(2) Includes interest expense, realized (gain) loss on interest rate swap and amortization of deferred loan fees. In connection with the repayment of the company's second lien term loan, the company settled interest rate derivative swaps in February 2011 for $38.1 million, resulting in a significant realized interest rate derivative loss for Q1 2011. For purposes of the above per BOE metric, the settlement cost of $38.1 million was excluded from the calculation of interest expense.

2011 Guidance Update

As a result of adjustments to the onshore Monterey drilling plans that will shift certain 2011 activity into 2012, and the results of wells drilled to date, the company expects modest production of 150 BOE/d from the Monterey for 2011. Production from the company's legacy assets is expected to average 18,350 BOE/d for the full year 2011. The company also reduced certain expense guidance. The company's updated full-year 2011 guidance is summarized in the table below

Revised Original
Production 18,500 BOE/day 19,500 BOE/day
Lease Operating Expenses $13.50 per BOE $14.25 per BOE
Production/Property Taxes $1.00 per BOE $1.20 per BOE
DD&A Expense $13.00 per BOE $13.00 per BOE
G&A Expense (1) $4.75 per BOE $4.75 per BOE
Capital Expenditures $200 million $200 million
(1) Net of amounts capitalized and excluding stock-based compensation costs.

"The net result of lowering expense and production guidance, along with more favorable price differentials, is an improvement of our profitability from our outlook at the beginning of the year," said Mr. Marquez.

2012 Outlook

The company's average oil realizations in 2012 are expected to improve as a result of the March 31, 2012 expiration of certain crude oil sales contracts tied to NYMEX West Texas Intermediate (WTI) pricing. Approximately half of the company's crude oil is sold under those contracts, while the balance is sold on contracts tied to California posted prices, which have exceeded WTI by up to $13 per barrel during 2011. The company's average 2010 realized oil prices were approximately $10 per barrel less than WTI; however, with the recent higher California postings its average oil price realizations in the first half of 2011 have improved to approximately $6 less than WTI. As the company's WTI based contracts expire in 2012 and based on current forward strip pricing, the company believes its average realized oil prices in 2012 will exceed WTI by approximately $7 per barrel.

Venoco continues to monitor progress at the Hastings field where it has a reversionary interest in the large CO2 flood being implemented by Denbury Resources. The company believes its share of reserves associated with the flood could eventually be up to 40 million BOE. As expected, the field is currently shut-in to build pressure from the CO2 flood and is expected to return to production late in 2011. Depending on the timing and level of response from the CO2 flood, the company believes a portion of its 15.2 million BOE of engineered probable reserves may be reclassified as proven reserves by year-end 2011.

When the Hastings field reaches payout for Denbury, Venoco will earn, at no cost, a 22.3% working interest in this large producing oil field. Venoco currently estimates that the CO2 flood will reach payout in approximately 24 months using $100 per barrel oil pricing. The company also estimates that a sustained decrease in oil pricing of $10 per barrel would extend payout by approximately 4 months. The company currently expects to explore marketing its interest in the field in 2012 after response to the CO2 flood has been demonstrated.

"With higher world-wide oil prices and strong California pricing, we expect 2012 can be both a year of increased drilling activity and, with strong cash flow and the potential sale of Hastings, greatly improved debt metrics," said Mr. Marquez. "We have a tremendous amount of value we are focused on unlocking."

Earnings Conference Call

Venoco will host a conference call to discuss results today, Tuesday, August 2, 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) 788-0545 and use conference code 78465373. International participants can call (857) 350-1683 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 25598339. 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 permitting process for the South Ellwood pipeline project and the potential effect of the project on the company's reserves, 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, (iii) potential reserves and resources associated with the Hastings CO2 flood and Sacramento Basin development projects, (iv) the timing of payout and reserve booking associated with the Hastings CO2 flood and (v) the company's intention to market its interest in the Hastings CO2 project and the effect of such a sale on the company's capital structure. 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 company may not be able to obtain the permits necessary to implement the South Ellwood pipeline project in the time frame it expects or at all. 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. 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
% %
UNAUDITED 3/31/11 6/30/11 Change 6/30/10 6/30/11 Change
Production Volume:
Oil (MBbls) (1) 608 619 2% 700 619 -12%
Natural Gas (MMcf) 5,972 5,874 -2% 5,732 5,874 2%
MBOE 1,603 1,598 0% 1,655 1,598 -3%
Daily Average Production Volume:
Oil (Bbls/d) 6,756 6,802 1% 7,692 6,802 -12%
Natural Gas (Mcf/d) 66,356 64,549 -3% 62,989 64,549 2%
BOE/d 17,815 17,560 -1% 18,190 17,560 -3%
Oil Price per Barrel Produced (in dollars):
Realized price before hedging $ 86.38 $ 96.37 12% $ 66.96 $ 96.37 44%
Realized hedging gain (loss) (1.51 ) (5.37 ) 256% (1.54 ) (5.37 ) 249%
Net realized price $ 84.87 $ 91.00 7% $ 65.42 $ 91.00 39%
Natural Gas Price per Mcf (in dollars):
Realized price before hedging $ 4.03 $ 4.29 6% $ 4.12 $ 4.29 4%
Realized hedging gain (loss) 1.07 0.82 -23% 1.99 0.82 -59%
Net realized price $ 5.10 $ 5.11 0% $ 6.11 $ 5.11 -16%
Expense per BOE (in dollars):
Lease operating expenses $ 13.52 $ 13.14 -3% $ 13.65 $ 13.14 -4%
Production and property taxes $ 0.97 $ 0.90 -7% $ 0.82 $ 0.90 10%
Transportation expenses $ 1.24 $ 1.67 35% $ 1.61 $ 1.67 4%
Depreciation, depletion and amortization $ 13.53 $ 13.59 0% $ 11.32 $ 13.59 20%
General and administrative (2) $ 6.13 $ 5.52 -10% $ 6.50 $ 5.52 -15%
Interest expense $ 7.92 $ 10.00 26% $ 6.22 $ 10.00 61%
Six Months Ended
%
UNAUDITED 6/30/10 6/30/11 Change
Production Volume:
Oil (MBbls) (1) 1,481 1,227 -17%
Natural Gas (MMcf) 11,513 11,846 3%
MBOE 3,400 3,201 -6%
Daily Average Production Volume:
Oil (Bbls/d) 8,182 6,779 -17%
Natural Gas (Mcf/d) 63,608 65,448 3%
BOE/d 18,783 17,687 -6%
Oil Price per Barrel Produced (in dollars):
Realized price before hedging $ 67.80 $ 91.42 35%
Realized hedging gain (loss) (1.46 ) (3.46 ) 137%
Net realized price $ 66.34 $ 87.96 33%
Natural Gas Price per Mcf (in dollars):
Realized price before hedging $ 4.73 $ 4.16 -12%
Realized hedging gain (loss) 1.32 0.95 -28%
Net realized price $ 6.05 $ 5.11 -16%
Expense per BOE (in dollars):
Lease operating expenses $ 12.78 $ 13.33 4%
Production and property taxes $ 1.05 $ 0.93 -11%
Transportation expenses $ 1.10 $ 1.45 32%
Depreciation, depletion and amortization $ 11.39 $ 13.56 19%
General and administrative (2) $ 5.93 $ 5.83 -2%
Interest expense $ 6.01 $ 8.96 49%
(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 Six Months Ended
UNAUDITED (In thousands) 6/30/10 3/31/11 6/30/11 6/30/10 6/30/11
REVENUES:
Oil and natural gas sales $ 68,492 $ 78,319 $ 85,918 $ 150,428 $ 164,237
Other 1,566 871 1,371 2,386 2,242
Total revenues 70,058 79,190 87,289 152,814 166,479
EXPENSES:
Lease operating expense 22,595 21,676 21,000 43,445 42,676
Property and production taxes 1,350 1,548 1,439 3,572 2,987
Transportation expense 2,661 1,986 2,670 3,739 4,656
Depletion, depreciation and amortization 18,742 21,691 21,713 38,716 43,404
Accretion of asset retirement obligation 1,546 1,590 1,608 3,131 3,198
General and administrative 10,762 9,829 8,824 20,171 18,653
Total expenses 57,656 58,320 57,254 112,774 115,574
Income from operations 12,402 20,870 30,035 40,040 50,905
FINANCING COSTS AND OTHER:
Interest expense 10,298 12,697 15,976 20,422 28,673
Interest rate derivative realized (gains) losses 4,559 41,147 - 9,068 41,147
Interest rate derivative unrealized (gains) losses 11,717 (40,064 ) - 16,732 (40,064 )
Amortization of deferred loan costs 679 531 592 1,356 1,123
Loss on extinguishment of debt - 1,357 - - 1,357
Commodity derivative realized (gains) losses (10,345 ) (5,468 ) (3,507 ) (13,006 ) (8,975 )
Commodity derivative unrealized (gains) losses and amortization of derivative premiums (8,215 ) 34,595 (2,049 ) (42,029 ) 32,546
Total financing costs and other 8,693 44,795 11,012 (7,457 ) 55,807
Income (loss) before taxes 3,709 (23,925 ) 19,023 47,497 (4,902 )
Income tax provision (benefit) - - - (200 ) -
Net income (loss) $ 3,709 $ (23,925 ) $ 19,023 $ 47,697 $ (4,902 )
Weighted average common shares outstanding:
Basic 51,826 56,159 58,718 51,557 57,446
Diluted 53,043 56,159 58,843 52,629 57,446
CONDENSED CONSOLIDATED BALANCE SHEET INFORMATION
UNAUDITED ($ in thousands) 12/31/10 6/30/11
ASSETS
Cash and cash equivalents $ 5,024 $ 3,023
Accounts receivable 29,602 30,184
Inventories 6,229 7,424
Other current assets 4,585 2,577
Income tax receivable 931 124
Commodity derivatives 26,407 25,611
Total current assets 72,778 68,943
Net property, plant and equipment 648,044 740,494
Total other assets 30,101 32,242
TOTAL ASSETS $ 750,923 $ 841,679
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable and accrued liabilities $ 45,396 $ 40,408
Interest payable 5,538 21,375
Commodity and interest derivatives 33,483 20,393
Total current liabilities 84,417 82,176
LONG-TERM DEBT 633,592 643,609
COMMODITY AND INTEREST DERIVATIVES 23,430 16,569
ASSET RETIREMENT OBLIGATIONS 93,721 99,136
Total liabilities 835,160 841,490
Total stockholders' equity (84,237 ) 189
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 750,923 $ 841,679

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 Six Months Ended
UNAUDITED ($ in thousands) 6/30/10 3/31/11 6/30/11 6/30/10 6/30/11
Adjusted Earnings Reconciliation
Net Income $ 3,709 $ (23,925 ) $ 19,023 $ 47,697 $ (4,902 )
Plus:
Unrealized commodity (gains) losses (13,873 ) 32,605 (4,039 ) (53,344 ) 28,566
Unrealized interest rate derivative (gains) losses 11,717 (40,064 ) - 16,732 (40,064 )
Texas severance costs 1,254 - - 1,254 -
Loss on extinguishment of debt - 1,357 - - 1,357
Settlement of interest rate swap contracts - 38,065 - - 38,065
Tax effects - - - - -
Adjusted Earnings $ 2,807 $ 8,038 $ 14,984 $ 12,339 $ 23,022
Quarter Ended Six Months Ended
UNAUDITED ($ in thousands) 6/30/10 3/31/11 6/30/11 6/30/10 6/30/11
Adjusted EBITDA Reconciliations:
Net income $ 3,709 $ (23,925 ) $ 19,023 $ 47,697 $ (4,902 )
Interest expense 10,298 12,697 15,976 20,422 28,673
Interest rate derivative (gains) losses - realized 4,559 41,147 - 9,068 41,147
Income taxes - - - (200 ) -
DD&A 18,742 21,691 21,713 38,716 43,404
Accretion of asset retirement obligation 1,546 1,590 1,608 3,131 3,198
Amortization of deferred loan costs 679 531 592 1,356 1,123
Loss on extinguishment of debt - 1,357 - - 1,357
Share-based payments 1,408 1,824 1,579 2,731 3,403
Texas severance costs 1,254 - - 1,254 -
Amortization of derivative premiums 5,658 1,990 1,990 11,315 3,980
Unrealized commodity derivative (gains) losses (13,873 ) 32,605 (4,039 ) (53,344 ) 28,566
Unrealized interest rate derivative (gains) losses 11,717 (40,064 ) - 16,732 (40,064 )
Adjusted EBITDA $ 45,697 $ 51,443 $ 58,442 $ 98,878 $ 109,885

We also provide per BOE G&A expenses excluding costs associated with the Texas asset sale 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 Six Months Ended
6/30/10 3/31/11 6/30/11 6/30/10 6/30/11
G&A per BOE Reconciliation
G&A expense $ 10,762 $ 9,829 $ 8,824 $ 20,171 $ 18,653
Less:
Share-based compensation expense (1,068 ) (1,454 ) (1,319 ) (2,151 ) (2,773 )
Texas severance costs (1,254 ) - - (1,254 ) -
G&A Expense Excluding Share-Based Comp 8,440 8,375 7,505 16,766 15,880
MBOE 1,655 1,603 1,598 3,400 3,201
G&A Expense per BOE Excluding Share-Based Comp $ 5.10 $ 5.22 $ 4.70 $ 4.93 $ 4.96

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