UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (date of earliest event reported):  August 11, 2009

BERRY PETROLEUM COMPANY

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code:  (303) 999-4400

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

ITEM 8.01             OTHER EVENTS.

Berry Petroleum Company (the “Company”) is filing this Current Report on Form 8-K to update the following items of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 (the “Form 10-K”) as set forth under the corresponding items contained in Exhibit 99.1, which is incorporated herein by reference:

·                  Item 6. Selected Financial Data;

·                  Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operation; and

·                  Item 8.  Financial Statements and Supplementary Data.

These updates are being made to reflect (1) the presentation as discontinued operations of the Company’s natural gas assets in the Denver-Julesburg basin in Colorado (the “DJ Basin assets”) in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, and (2) the Company’s implementation of FASB Staff Position No. EITF 03-06-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-06-01”), which requires the revision of prior period basic and diluted earnings per share data.

As previously disclosed, the Company sold its DJ Basin assets on April 1, 2009.  SFAS 144 requires the Company to report in discontinued operations the results of operations of a property that has either been disposed of or is classified as held for sale, unless certain conditions are met.  SFAS 144 further requires the Company to reclassify results of operations from a property disposed or designated as held for sale as income from discontinued operations during all reported periods. This Current Report on Form 8-K sets forth, among other things, audited financial statements of the Company for the years ended December 31, 2006, 2007 and 2008, including revised notes thereto, which reflect the impact of reclassifying results of operations from the DJ Basin assets in accordance with SFAS 144.

Also as previously disclosed, on January 1, 2009, the Company adopted FSP EITF 03-06-1.   FSP EITF 03-06-1 clarifies that share-based payment awards that entitle their holders to receive nonforfeitable dividends before vesting should be considered participating securities. As participating securities, these instruments should be included in the earnings allocation in computing basic earnings per share under the two-class method described in SFAS No. 128, Earnings per Share. As a result, all prior period earnings per share data presented in the Form 10-K have been updated to conform with the provisions of this pronouncement.

This Current Report on Form 8-K does not reflect events or developments that occurred after February 25, 2009, the date the Company filed the Form 10-K with the Securities and Exchange Commission (the “SEC”). More current information is contained in the Company’s Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009 (the “Form 10-Qs”) and other filings with the SEC.  The information in this Current Report on Form 

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8-K should be read in conjunction with the Form 10-K, the Form 10-Qs and other documents the Company filed with the SEC subsequent to February 25, 2009.

ITEM 9.01             FINANCIAL STATEMENTS AND EXHIBITS.

(d) Exhibits.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

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INDEX TO EXHIBITS

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Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (File Nos.  333-127018, 333-98379, 333-62871 and 333-62799) of Berry Petroleum Company of our report dated February 25, 2009, except with respect to our opinion on the financial statements insofar as it relates to the discontinued operations discussed in Note 1 and the change in accounting for earnings per share discussed in Note 23, as to which the date is August 11, 2009, relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 8-K.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

August 11, 2009

Exhibit 99.1

Item 6. Selected Financial Data

The following table sets forth certain financial information and is qualified in its entirety by reference to the historical financial statements and notes thereto included in Item 8 Financial Statements and Supplementary Data and have been revised from the presentation, except for the reserve data, in our Annual Report on Form 10-K to reflect (1) the presentation as discontinued operations of our DJ Basin assets, which were sold on April 1, 2009, in accordance with the Statement of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-lived Assets, and (2) our implementation of FASB Staff Position No. EITF 03-06-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities, which requires the revision of prior period basic and diluted earnings per share data. The Statements of Income for the years ended December 31, 2008, 2007 and 2006 and Balance Sheet data as of December 31, 2008 and 2007 included in this table were derived from the audited financial statements and the accompanying notes to those financial statements (in thousands, except per share, per BOE and % data).

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(1) See Note 6 to the financial statements

(2) See Supplemental Information About Oil & Gas Producing Activities (unaudited).

(3) Does not give effect to the DJ basin asset sale.

(4) Gives effect to the DJ basin asset sale and represents continuing operations only

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Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operation

As previously disclosed, the Company sold its DJ Basin assets on April 1, 2009.  SFAS 144 requires the Company to report in discontinued operations the results of operations of a property that has either been disposed of or is classified as held for sale, unless certain conditions are met.  SFAS 144 further requires the Company to reclassify results of operations from a property disposed or designated as held for sale as income from discontinued operations during all reported periods. This Current Report on Form 8-K sets forth, among other things, audited financial statements of the Company for the years ended December 31, 2008, 2007 and 2006, including revised notes thereto, which reflect the impact of reclassifying results of operations from the DJ Basin assets in accordance with SFAS 144.

Also as previously disclosed, on January 1, 2009, the Company adopted FSP EITF 03-06-1.   FSP EITF 03-06-1 clarifies that share-based payment awards that entitle their holders to receive nonforfeitable dividends before vesting should be considered participating securities. As participating securities, these instruments should be included in the earnings allocation in computing basic earnings per share under the two-class method described in SFAS No. 128, Earnings per Share. As a result, all prior period earnings per share data presented in the Form 10-K have been updated to conform with the provisions of this pronouncement.

Overview. We seek to increase shareholder value through consistent growth in our production and reserves, both through the drill bit and acquisitions. We strive to operate our properties in an efficient manner to maximize the cash flow and earnings of our assets. The strategies to accomplish these goals include:

·      Developing our existing resource base

·      Investing our capital in a disciplined manner and maintaining a strong financial position

·      Calibrating our cost structure to the current commodity price environment

·      Acquiring additional assets with significant growth potential

·      Accumulating significant acreage positions near our producing operations

Notable Items in 2008.

·                  Achieved record production which averaged 31,968 BOE/D, up 19% from 2007

·                  Added 88 million BOE of proved reserves ending 2008 at 245.9 million BOE

·                  Recorded cash from operating activities of $410 million and funded $398 million of capital expenditures

·                  Closed on our E. Texas acquisition on July 15, 2008, adding approximately 32 MMcf to daily production

·                  Placed 5,000 Bbl/d of $100 WTI floor collars for 2009 and 2010 to protect cash flow

·                  Achieved net income of $134 million

·                  Drilled 85 wells in the diatomite and increased average production to 1,840 Bbl/D, up 86% from 2007

·                  Accomplished an 8 day drilling record on a Piceance mesa location and reduced average drilling days to 11

·                  Drilled 72 gross (44 net) Piceance operated wells which increased net production to average 21 MMcf/D

·                  Increased the borrowing base on our senior secured credit facility from $550 million to $1.25 billion with an increase in bank commitments to $1.21 billion

·      Completed relocation of our corporate headquarters from Bakersfield, California to Denver, Colorado

·      David D. Wolf joined the Company as Executive Vice President and Chief Financial Officer

·                  Temporarily shut in 12,000 Bbl/D in December due to the bankruptcy of Big West Oil in California and recorded an allowance for doubtful accounts of $38.5 million for November and December California crude oil sales

·                  Resumed California operations in late December, marketing California production to multiple refiners

·                  Quickly responded to declining commodity price environment reducing rig count from twelve to two during the fourth quarter of 2008, and reducing our 2009 capital budget to $100 million

Notable Items and Expectations for 2009.

·      Expecting 2009 capital expenditures of $100 million to be fully funded from operating cash flow

·      Anticipating average production between 32,000 and 33,000 BOE/D

·      Entered into short-term agreements with multiple refiners to sell all of our California crude oil

·      Targeting a 20% reduction in both operating and capital costs for 2009

·                  Amended the terms of our senior secured credit facility, increasing our maximum EBITDAX to debt ratio

Overview of the Fourth Quarter of 2008.  We achieved average production from continuing operations of 32,168 BOE/D in the fourth quarter of 2008, up 1% from an average of 35,149 BOE/D in the third quarter of 2008. We had a net loss from continuing operations of $11.1 million, or $0.24 per diluted share.  Net cash from operations was $78 million and capital expenditures during the quarter totaled $92 million.  The net loss from continuing operations resulted primarily from a write-off of $38.5 million (pre-tax) of accounts receivable due from BWOC as a result of their bankruptcy filing.  This write-off included November and 22 days of December production from the majority of our California properties.  We have since contracted with other parties to receive our California production.  Other notable charges taken in the fourth quarter of the year included pre-tax rig termination fees of $2.3 million, $4.2 million related to the disposal and impairment of certain drilling rigs and related equipment, and dry hole and

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impairment expenses of $0.7 million.  We had a net loss from discontinued operations of $0.9 million resulting from the DJ basin operations.

View to 2009. Our challenge for 2009 is to calibrate our cost structure to levels that are consistent with those experienced when commodity prices were at $30 Bbl to $50 Bbl.  Each of our asset teams is actively pursuing cost reductions and we are targeting a 20% reduction in our non-steam operating costs and our capital costs per well when compared to 2008 levels.  Our $100 million capital program is designed to fund high return projects in California and E. Texas and generate excess cash flow.

Capital expenditures. Our capital expenditures for 2008 totaled $398 million for development and were fully funded from our $410 million operating cash flow.  We also funded $668 million in acquisitions through additional borrowing on our senior secured credit facility and capitalized $23 million of interest. This compares to our total capital expenditures in 2007 of $341 million, which consisted of $56 million of acquisitions and $285 million in development. We capitalized $18 million of interest in 2007.

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Excluding the acquisition of new properties, in 2009 we have a developmental capital program of approximately $100 million which we expect to fund fully out of operating cash flow. As we have operational control of all of our assets and we have limited drilling commitments, we have the ability to revise our capital program based on changes in commodity prices.  We expect our capital program will allow us to hold production flat with 2008 levels with average production between 32,000 and 33,000 BOE/D.

Development, Exploitation and Exploration Activity. We drilled 452 gross (381 net) wells during 2008, realizing a gross success rate of 99 percent. As of December 31, 2008, we have two rigs drilling on our properties under long-term contracts.

Drilling Activity. The following table sets forth certain information regarding drilling activities for the year ended December 31, 2008:

(1) Includes 6 gross wells (5 net wells) that were dry holes in 2008.

Net Oil and Gas Producing Properties at December 31, 2008.

Properties

We have seven asset teams as follows: South Midway-Sunset (S. Midway), North Midway-Sunset including diatomite (N. Midway), Southern California including Poso Creek and Placerita (S. Cal), Piceance, Uinta, DJ and E. Texas. Our S. Midway, S. Cal and DJ asset teams are primarily focused on production and generate significant cash flow to fund the drilling inventory in our N. Midway, Piceance, E. Texas and Uinta projects.

S. Midway - We own and operate working interests in 38 properties, including 23 owned in fee. Production from this field relies on thermal EOR methods, primarily cyclic steaming to place steam effectively into the remaining oil column. This is our most mature thermally enhanced asset.

2008 - Capital was focused on adding 20 horizontal wells below existing horizontal wells and further development at Ethel D including drilling 32 producers and the initiation of a pilot steam flood.

2009 - Efforts will be focused on drilling 10 additional, deeper horizontal wells, evaluation of the Ethel D steam flood pilot and lowering operating costs through optimization of well servicing and steam placement.

N. Midway - We began the full scale development of our N. Midway diatomite asset in late 2006 and have drilled 190 wells on this property.

2008 - Capital was focused on drilling approximately 85 diatomite wells, completing major infrastructure upgrades that will support future development, increasing steam injection and further refining our thermal recovery techniques.  Production from our diatomite asset increased by 86% in 2008, averaging approximately 1,840 Bbl/D.

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2009 - We plan to invest $37 million to drill an additional 44 diatomite wells and install additional steam generation facilities. Additionally, we are seeking operating and capital cost reductions through initiatives such as steam management to improve our steam oil ratio and improved project management to reduce overall well costs. Production is expected to increase over 50% averaging approximately 3,000 Bbl/D.

S. Cal - We acquired the Poso Creek properties in the San Joaquin Valley in early 2003 for approximately $3 million and have proceeded with a successful thermal EOR redevelopment. In the Placerita field in Los Angeles County, we own and operate working interests in thirteen properties, including nine leases and four fee properties. Production relies on thermal recovery methods, primarily steam flooding.

2008 — Capital was directed at a 28 well program at Poso Creek and further expansion of the steam flood including the installation of a fourth steam generator and expansion of our water processing facilities.  Average production increased from 1,950 Bbl/D in 2007 to 3,100 Bbl/D in 2008.    A fifth steam generator was purchased and installed allowing further steam flood expansion into 2009.

2009 - Production at Poso Creek will increase as the steam flood patterns we developed in 2008 continue to respond. We expect to focus our efforts in 2009 on improving steam-oil ratios and lowering operating expenses.

Piceance - In 2006, we made two separate acquisitions in Piceance in Colorado, targeting the Williams Fork section of the Mesaverde formation. We acquired a 50% working interest in 6,300 gross acres in the Garden Gulch property and a 5% non-operating working interest on 6,300 gross acres and a net operating working interest of 95% in 4,300 gross acres in the North Parachute Ranch property. We spent $312 million to acquire a majority working interest in several blocks of undeveloped acreage located in the Grand Valley field. We believe we have accumulated a sizable resource base with over 900 drilling locations which will allow us to add significant proved reserves over the next several years.

2008 - Production averaged 20,750 Mcf/D in 2008 in comparison to 10,200 Mcf/D in 2007. We operated a four rig drilling program for most of the year and drilled 54 gross (27 net) wells at Garden Gulch and 18 gross (17 net) wells at North Parachute.  Significant progress was made during 2008 in reducing the days required to drill wells. During the last three months of drilling activity, the number of drilling days on our mesa wells averaged 10 days on Garden Gulch and 11 days in North Parachute, a 40% reduction in drilling times compared to early 2008.

2009 — Our focus in 2009 will be on reducing our drilling and completion cost structure along with evaluating reservoir parameters and completion practices to improve ultimate recoveries.  We believe our focus on cost reduction and improvement of ultimate recovery will allow for attractive returns to continue the development of our over 900 well drilling inventory.   We have an inventory of approximately 40 completions and recompletions that we will be evaluating for supplemental capital should commodity prices warrant.

Uinta - The Brundage Canyon leasehold in Duchesne County, northeastern Utah consists of approximately 30,000 undeveloped gross acres which include federal, tribal and private leases. We are targeting the Green River formation that produces both light oil and natural gas. Along with an industry partner, we also hold a 163,000 gross acre block in the Lake Canyon project, which is located immediately west of our Brundage Canyon producing properties. We will drill and operate the shallow wells, targeting light oil and natural gas in the Green River formation and retain up to a 75% working interest. Our partner will drill and operate deep wells that will target hydrocarbons in the Mesaverde and Wasatch formations. We will hold up to a 25% working interest in these deep wells. The Ute Tribe has the option to participate in each well and obtain a 25% working interest which would reduce our and our partner’s participation.

2008 — Production averaged 6,142 BOE/D in 2008 compared to 5,743 BOE/D in 2007.  We drilled 51 gross (50 net) wells in the Uinta project which included 39 wells at Brundage Canyon, 8 wells in the Ashley Forest and 4 Green River wells at Lake Canyon.  The Ashley Forest results continue to be encouraging with the 2008 wells achieving recoveries similar to Brundage Canyon.  Three of our Lake Canyon wells are waiting on completion which is scheduled for mid-2009.

2009 — In 2009 capital is primarily directed at facility upgrades, pursuing the remaining three Lake Canyon completions and the completion of the Ashley Forest Environmental Impact Study (EIS) which we anticipate in the first half of 2009.

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DJ - In 2005, we made three acquisitions for approximately $111 million establishing a core area in the Niobrara gas producing assets in eastern Colorado, western Kansas, and southwestern Nebraska.  In 2007, we divested of our Kansas and Nebraska positions and focused our development in Yuma County where we have approximately 110,000 net acres and over 1,100 producing wells.  Our Yuma County Niobrara projects provide sustainable and steady cash flow resulting from low capital development costs, modest production declines and long-life reserves.

2008 — Production averaged 19,700 net Mcf/D in 2008 compared to 18,700 Mcf/D in 2007.  In 2008 we drilled 107 Niobrara development wells (71 net) in Yuma County with a 100% success rate and expanded our gathering and compression infrastructure to facilitate our drilling program.  Early in the year we acquired an additional 75 square miles of 3-D seismic data.  Interpretation of the 2008 seismic program and re-evaluation of previous year’s acquisitions continue to replenish our low risk repeatable drilling inventory and provide additions to our proved reserves.

2009 — The primary focus in 2009 will be to maximize production from our existing wells, increase operational efficiencies, and reduce lease operating expense.  Our capital program will be directed toward lease acquisition and facility infrastructure upgrades.

E. Texas — On July 15, 2008, we acquired a 100% working interest in natural gas producing properties on 4,500 net acres in Limestone and Harrison counties in East Texas for approximately $650 million.  In Limestone County, we are targeting seven productive sands including the Cotton Valley and Bossier sands at depths between 8,000 and 13,000 feet. In Harrison County, we are targeting five productive sands with average depths between 6,500 and 13,000 feet and have upside potential in the Haynesville and Bossier Shales. We assumed operations from the seller on November 1, 2008.

2008 - We executed a five rig program in 2008 and 19 wells have been drilled and put on production since closing (4 in Harrison and 15 in Limestone).  We also drilled three wells which are awaiting completion during 2009.

2009 - We plan to run one rig during 2009 and will drill approximately five vertical wells in the Oakes field during  the year and plan to begin drilling horizontal wells in the Haynesville Shale Darco field in the third quarter of 2009.

Obstacles and Risks to Accomplishment of Strategies and Goals. See Item 1A Risk Factors for a detailed discussion of factors that affect our business, financial condition and results of operations.

Revenues. Approximately 87% of our revenues are generated through the sale of oil and natural gas production under either negotiated contracts or spot gas purchase contracts at market prices. Approximately 8% of our revenues are derived from electricity sales from cogeneration facilities which supply approximately 32% of our steam requirement for use in our California thermal heavy oil operations.  We have invested in these facilities for the purpose of lowering our steam costs which are significant in the production of heavy crude oil. The remaining 5% of our revenues are primarily derived from gas marketing sales which represent excess capacity on the Rockies Express pipeline which we used to market natural gas for our working interest partners.

Sales of oil and gas were up 50% in 2008 compared to 2007 and up 64% from 2006. This improvement was due to an overall increase in both oil and gas production levels and increased oil prices. Improvements in production volume reflect the successful results of capital investments. Oil and natural gas prices contributed roughly 71% of the revenue increase and the increase in production volumes contributed the other 29%. Approximately 64% of our oil and gas sales volumes in 2008 were crude oil, with 82% of the crude oil being heavy oil produced in California which was sold under a contract based on the higher of WTI minus a fixed differential or the average posted price plus a premium.  

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The following results are in millions (except per share data) for the years ended December 31:

(1)          Includes 2007 sale of Montalvo, California assets

The following results are in millions (except per share data) for the three months ended:

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Oil Contracts. See Item 1 Business.

Hedging. See Item 7A Quantitative and Qualitative Disclosures about Market Risk and Note 18 to the financial statements.

Operating data. The following table is for the years ended December 31:

Production from continuing operations increased 21% or 4,894 BOE/D for the year ended December 31, 2008 when compared to the year ended December 31, 2007. Our E. Texas acquisition which closed on July 15, 2008, contributed 2,384 BOE/D on an annualized basis.  Our development activities during the year resulted in increases in the Piceance, Poso and diatomite of 1,796 BOE/D, 1,133 BOE/D and 851 BOE/D, respectively.

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The following table is for the three months ended:

Electricity. We consume natural gas as fuel to operate our three cogeneration facilities which are intended to provide an efficient and secure long-term supply of steam necessary for the cost-effective production of heavy oil. We sell our electricity to utilities under standard offer contracts based on “avoided cost” or SRAC pricing approved by the CPUC and under which our revenues are currently linked to the cost of natural gas. Natural gas index prices are the primary determinant of our electricity sales price based on the current pricing formula under these contracts. The correlation between electricity sales and natural gas prices allows us to manage our cost of producing steam more effectively.  Revenues were up and operating costs were up in the year ended 2008 from the year ended 2007 due to 18% higher electricity prices and 27% higher natural gas prices, respectively.   Revenues were up and operating costs were down in the year ended 2007 from the year ended 2006 due to 2% higher electricity prices and 6% lower natural gas prices, respectively. We purchased approximately 27 MMBtu/D as fuel for use in our cogeneration facilities in both the year ended December 31, 2008 and the year ended December 31, 2007.  In 2007 and 2008, our electricity operations improved partially from the lower cost of our firm transportation natural gas we purchased. We purchase and transport 12,000 average MMBtu/D on the Kern River Pipeline under our firm transportation contract and use this gas to produce conventional and cogeneration steam in the Midway-Sunset field. The differential between Rocky Mountain gas prices and Southern California Border prices increased during 2007 and 2008 compared to 2006 allowing us to purchase a portion of our gas at prices less than the Southern California Border price. As our electricity revenue is linked to Southern California Border prices, the fuel we purchased at lower Rocky Mountain prices was the primary contributor to the increase in our electricity margins in 2007 and 2008 compared to 2006.

On September 20, 2007, the CPUC issued a decision (SRAC Decision) that changes the way SRAC energy prices will be determined for existing and new SO contracts and revises the capacity prices paid under current SO1 contracts. The effective date of the SRAC Decision has not been determined nor has every element of the formula under the SRAC Decision been finalized.  As such it is not possible to predict the economic impact on us of the SRAC Decision nor whether its terms will be applied retroactively and if so, for what period.

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The following table is for the years ended December 31:

Royalties. A price-sensitive royalty burdens certain of our S. Midway properties which produced approximately 2,300 BOE/D in 2008. This royalty was 75% of the amount of the heavy oil posted price above a base price which was $16.11 in 2008. This royalty rate was reduced to 53% effective January 1, 2008 as long as we maintain a minimum steam injection level.  We met the steam injection level in 2008 and expect to meet the requirement going forward.  This base price escalates at 2% annually, thus the threshold price is $16.43 per barrel in 2009.  Liabilities payable for these royalties were $22 million, $36 million and $36 million in the years ended December 31, 2008, 2007 and 2006, respectively.

In the first quarter of 2008, we determined there was an error in computing royalties payable in prior years, accumulating to $10.5 million as of December 31, 2007. We concluded the error was not material to any individual prior interim or annual period (or to the projected earnings for 2008) and, therefore, the error was corrected during the first quarter of 2008, with the effect of increasing our sales of oil and gas by $10.5 million and reducing our royalties payable.

Oil and Gas Operating, Production Taxes, G&A and Interest Expenses. We believe that the most informative way to analyze changes in recurring operating expenses from one period to another is on a per unit-of-production, or BOE, basis. The following table presents information about our continuing operations expenses for each of the years ended December 31:

Our total operating costs, production taxes, G&A and interest expenses for 2008, stated on a unit-of-production basis, increased 22% over 2007. The changes were primarily related to the following items:

·      Operating costs: Our operating costs increased primarily due to higher contract services and labor costs, higher compression, gathering, and dehydration costs and higher steam costs resulting from higher volumes of injected steam. Of the $58 million increase in operating expense compared to 2007, approximately $31 million was due to higher steam costs and approximately $4 million was due to the addition of our E. Texas assets.  On a per barrel basis, E. Texas operating costs approximate $1.00/Mcf and reduces our overall cost per barrel.  The following table presents steam information:

Based on current plans, we are targeting average steam injection in 2009 of approximately 120,000 BSPD or a 20% increase compared to 2008.

·      Production taxes: Our production taxes have increased over the last year as the value of our oil and natural gas has increased. Severance taxes, which are prevalent in Utah and Colorado, are directly related to the field sales price of the commodity. In California, our production is burdened with ad valorem taxes on our total proved reserves. We expect production taxes to track oil and gas prices generally.

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·      Depreciation, depletion and amortization: DD&A increased per BOE in 2008 by 25% from 2007. Over the past year this increase has resulted from an increase in capital spending in fields with higher drilling and leasehold acquisition costs, which is in line with our expectations. Additionally, DD&A may continue to trend higher as a certain portion of our interest cost related to our Piceance acquisitions is capitalized into the basis of the assets. We anticipate a portion will continue to be capitalized over the next several years until our probable reserves have been recategorized to proved reserves.

·      General and administrative: Approximately 65% of our G&A is related to compensation. The primary reason for the increase in G&A during 2008 was a 15% increase in employee headcount associated with our E. Texas acquisition and the development of our assets.  In 2008 we moved our corporate headquarters from Bakersfield, California to Denver, Colorado and approximately $1.7 million was related to relocation of our employees and related expenses. Also included in G&A is $2.3 million in rig termination penalties that we incurred during the fourth quarter of 2008 and $0.6 million for costs we incurred to evaluate the formation of a master limited partnership.

·      Interest expense: Our outstanding borrowings, including our senior unsecured money market line of credit and senior subordinated notes, was $1.16 billion at December 31, 2008 compared to $459 million at December 31, 2007. Average borrowings in 2008 increased primarily due to our E. Texas acquisition. For the year ended December 31, 2008, $23 million of interest cost has been capitalized.

The following table presents information about our operating expenses for continuing operations for each of the years ended December 31: