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Press release from Business Wire

Berry Petroleum Announces Results for Second Quarter of 2011

<p> <i><b>Provides Uinta Basin Update; Generates $46/BOE Operating Margin</b></i> </p> <p> </p>

Thursday, August 04, 2011

Berry Petroleum Announces Results for Second Quarter of 201108:00 EDT Thursday, August 04, 2011 DENVER (Business Wire) -- Berry Petroleum Company (NYSE:BRY) reported net income of $105 million, or $1.90 per diluted share, for the second quarter of 2011. Oil and gas revenues were $231 million during the quarter. Discretionary cash flow for the quarter totaled $121 million and cash provided by operating activities totaled $106 million. Net income for the quarter was impacted by a net non-cash gain on hedges which increased net income by approximately $64.5 million, or $1.17 per diluted share for an adjusted second quarter net income of $40.7 million, or $0.73 per diluted share. For the second quarter of 2011 and the first quarter of 2011, average net production in BOE per day was as follows:         Second Quarter Ended June 30         First Quarter Ended March 312011 Production         2011 Production Oil (Bbls) 24,629         69 %         22,648         66 % Natural Gas (BOE) 10,97731%11,75734% Total BOE per day 35,606 100 % 34,405 100 % Robert F. Heinemann, president and chief executive officer said, “Performance from Berry's portfolio of assets was strong in the second quarter. Production for the second quarter of 2011 was 35,606 BOE/D. Our oil production grew nine percent during the quarter driven by solid increases in the Diatomite and Permian. Our capital investment for the remainder of 2011 will be 100% directed towards crude oil which should increase our oil weighting above the current 69%. Our price sensitive capital budget in 2011 has been a range of $400 to $450 million and at current prices we would expect to be at the high end of that range. Our increased oil mix and continued favorable pricing in California of a $5 premium over WTI allowed us to generate an operating margin of $46 per BOE during the quarter. We recently received full project approval to develop our diatomite asset in California and will be commencing additional pad and facility construction in the last half of 2011 along with drilling 50 wells to complete our 2011 drilling program. As we have been stating for past few months, we are becoming more encouraged about returning our Uinta assets to growth. We participated in two non-operated horizontal wells that were successfully completed in the Uteland Butte member of the Green River during the quarter. Although the horizontal Uteland Butte play is just starting, the results from these wells coupled with our success in the Green River and Wasatch have excited us about the contribution our Uinta assets can make to our oil portfolio.” Operational Update Michael Duginski, executive vice president and chief operating officer, stated, “In the diatomite, average production increased by 59% during the quarter and averaged 3,550 BOE/D as the wells we drilled during the first quarter began to respond to steam injection. We plan to bring on additional diatomite completions during the third quarter and our drilling program will resume in October as expected. Additionally, as we prepare for full field development in the diatomite, we have purchased approximately $20 million of emission reduction credits and other steam generation equipment which should allow us to meet our steam injection needs in the diatomite over the next three years.We executed a five rig program in the Permian during the second quarter and production was up 29%, averaging 3,850 BOE/D. Well costs in the Permian have increased as a result of pressure pumping cost pressures due to current commodity prices and activity levels in the basin but we also expect increased ultimate recoveries from the addition of deeper horizons including the Strawn, Atoka and Mississippian. We expect to complete approximately 50 wells in the Permian throughout the balance of 2011 which should allow us to have strong production growth as we exit the year.” Uinta Basin Update Berry began drilling its Uinta assets in 2003 and has concentrated on co-mingled, vertical production from several Green River members including the Uteland Butte. During Berry's development, over 400 vertical wells have been completed in the Uteland Butte across Brundage Canyon, Lake Canyon and the Ashley Forest. Of the Uteland Butte completions, the Company has tested 30 wells in the Uteland Butte on an isolated basis with 30 day production rates in the 10 to 80 BOE/D range. During the second quarter, Berry participated in two non-operated Uteland Butte horizontal wells in Lake Canyon. The first well had a 30-day initial production rate average of 717 BOE/D and the second well recently came on production with encouraging initial production. The Uteland Butte is well correlated in a cross-section of wire line logs from these two horizontals wells to a series of vertical wells across Lake Canyon to Brundage Canyon and Ashley Forest over to Monument Butte. Berry plans to drill three operated Uteland Butte horizontals and participate in three non-operated horizontal wells during the remainder of 2011. In addition to Berry's traditional vertical Green River development in Brundage Canyon, over the past two years, the Company has also drilled a total of 13 vertical Wasatch and commingled Green River/Wasatch wells in Lake Canyon with average 30-day initial production rates of between 100 BOE/D and 175 BOE/D. Berry plans to drill a total of 30 vertical Green River wells and 13 comingled Green River/Wasatch wells in addition to the three operated Uteland Butte horizontal wells in 2011. Berry estimates that its risked resource potential in the Uinta basin is approximately 65 MMBOE not including its proved developed reserves in the basin of 11 MMBOE. Mr. Heinemann commented, “In addition to our Green River position, Berry has over 60,000 net prospective acres in the Uteland Butte and over 100,000 acres in the Wasatch. The extension of our Uinta resource brings more scale and balance to the Company's oil strategy. Capturing full value of this resource depends on several factors such as de-risking the asset through the drill bit, controlling costs, securing drilling permits, increased refining capacity in the region and expanding the existing infrastructure.” 2011 Guidance For 2011 the Company is issuing the following per BOE guidance:         Anticipated range                       Three Months   in 20116/30/2011 Operating costs — oil and gas production $ 16.50-18.50 $ 18.14 Production taxes 2.00-3.00 2.58 DD&A — oil and gas production 16.00-18.00 16.04 General and administrative 4.00-5.00 4.91 Interest expense   5.25-6.25   5.47 Total $ 43.75-50.75 $ 47.14 Explanation and Reconciliation of Non-GAAP Financial MeasuresDiscretionary Cash Flow ($ millions)           Three Months Ended6/30/2011             3/31/2011   Net cash provided by operating activities $ 106.1 $ 100.4 Add back: Net increase (decrease) in current assets   5.7   14.7 Add back: Net decrease (increase) in current liabilities including book overdraft   8.8   (30.2 ) Discretionary cash flow $ 120.6 $ 84.9   Reconciliation of Second Quarter Net Earnings ($ millions)               Three Months Ended 6/30/2011 Adjusted net earnings $ 40.7 After tax adjustments: Non-cash hedge gains   64.5 Net earnings, as reported $ 105.2 Reconciliation of Operating Margin Per BOE             Three Months Ended 6/30/2011               3/31/2011 Average sales price including cash derivative settlements $ 66.90 $ 59.01 Operating cost - oil and gas production   18.14   18.44 Production Taxes   2.58   2.39 Operating margin $ 46.18 $ 38.18 Teleconference Call An earnings conference call will be held Thursday, August 4, 2011 at 1:00 p.m. Eastern Time (11:00 a.m. Mountain Time). Dial 800-901-5241 to participate, using passcode 88955265. International callers may dial 617-786-2963. For a digital replay available until August 11, 2011 dial 888-286-8010 passcode 22370438. Listen live or via replay on the web at About Berry Petroleum Company Berry Petroleum Company is a publicly traded independent oil and gas production and exploitation company with operations in California, Colorado, Texas and Utah. The Company uses its web site as a channel of distribution of material company information. Financial and other material information regarding the Company is routinely posted on and accessible at Safe harbor under the “Private Securities Litigation Reform Act of 1995” Any statements in this news release that are not historical facts are forward-looking statements that involve risks and uncertainties. Words such as “estimate,” “expect,” “would,” “will,” “target,” “goal,” “potential,” and forms of those words and others indicate forward-looking statements. These statements include but are not limited to forward-looking statements about acquisitions and the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including the Company's drilling program, production, resources, hedging activities, capital expenditure levels and other guidance included in this press release. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. Important factors which could affect actual results are discussed in the Company's filings with the Securities and Exchange Commission, including its Annual Report on Form 10-K under the headings “Risk Factors” and “Management's Discussion and Analysis of Financial Condition and Results of Operations.” Cautionary Note to Investors The Securities and Exchange Commission prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than “reserves,” as that term is defined by the SEC. We use certain terms in this news release, such as “risked resource potential,” that describe quantities of oil and gas that may not meet the SEC's definitions of proved, probable and possible reserves, and which the SEC's guidelines strictly prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by us. Investors are urged to consider closely the disclosures and risk factors in our Forms 10-K and 10-Q, File No. 1-07964, available from our offices or website, These forms can also be obtained from the SEC at its website, Non-GAAP Financial Measures This press release includes discussion of “discretionary cash flow,” “adjusted net earnings” and operating margin per BOE, each of which are “non-GAAP financial measures” as defined in Item 10 of Regulation S-K of the Securities Exchange Act of 1934, as amended. We believe that discretionary cash flow provides additional information to investors about our ability to meet future requirements for debt service, capital expenditures and working capital. Adjusted net earnings is useful for evaluating our operational performance from oil and natural gas properties, prior to non-cash gains or losses on hedges. Operating margin for BOE provides information about our per BOE operating profit based on operating expenses and taxes directly attributable to production. These measures should not be considered in isolation or as a substitute for cash flows from operating activities, net income, operating income or any other measure of financial performance presented in accordance with GAAP or as a measure of a company's profitability or liquidity, and may not be comparable to similarly titled measures used by other companies. CONDENSED INCOME STATEMENTS(In thousands, except per share data)(unaudited)                     Three months   6/30/2011     3/31/2011     REVENUES Sales of oil and gas $ 230,761   $ 187,389 Sales of electricity 7,964 6,412 Gas marketing 3,986 3,685 Interest and other income, net   803     128   243,514 197,614 EXPENSES Operating costs - oil and gas production 58,780 57,083 Operating costs - electricity generation 6,891 6,113 Production taxes 8,350 7,391 Depreciation, depletion & amortization - oil and gas production 51,967 52,109 Depreciation, depletion & amortization - electricity generation 491 501 Gas marketing 3,675 3,516 General and administrative 15,910 16,291 Interest 17,712 15,655 Realized and unrealized (gain) loss on derivatives, net (91,808 ) 127,516 Gain on purchase - (1,046 ) Transaction costs on acquisitions - - Dry hole, abandonment, impairment and exploration 311 113 Bad debt recovery   -       -     72,279     285,242   Earnings (loss) before income taxes 171,235 (87,628 ) Income tax provision (benefit)   66,069     (35,131 ) Net earnings (loss) $ 105,166     $ (52,497 )   Basic net earnings (loss) per share $ 1.93     $ (0.98 ) Diluted net earnings (loss) per share $ 1.90     $ (0.98 )   Dividends per share $ 0.075     $ 0.075     CONDENSED BALANCE SHEETS(In thousands)(unaudited)               6/30/2011                         12/31/2010 ASSETS Current assets 164,564 142,866 Oil and gas properties, buildings and equipment, net 2,959,386 2,655,792 Derivative instruments 1,418 2,054 Other assets   34,939   37,904 $ 3,160,307   $ 2,838,616 LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities 241,405 270,651 Deferred income taxes 362,939 329,207 Long-term debt 1,335,298 1,108,965 Derivative instruments 46,470 33,526 Other long-term liabilities 75,021 71,714 Shareholders' equity   1,099,174   1,024,553 $ 3,160,307   $ 2,838,616   CONDENSED STATEMENTS OF CASH FLOWS(In thousands)(unaudited)         Three months   6/30/2011                           3/31/2011     Cash flows from operating activities: Net (loss) earnings $ 105,166   $ (52,497 ) Depreciation, depletion and amortization 52,458 52,610 Gain on purchase - (1,046 ) Debt issuance costs 2,106 2,099 Dry hole and impairment 298 - Derivatives (104,963 ) 124,459 Stock-based compensation expense 2,387 3,052 Deferred income taxes 63,893 (44,321 ) Other, net (5 ) 679 Cash paid for abandonment (761 ) (103 ) Change in book overdraft (714 ) 4,736 Net changes in operating assets and liabilities   (13,777 )   10,766   Net cash provided by operating activities   106,088     100,434     Cash flows from investing activities: Exploration and development of oil and gas properties (140,761 ) (130,672 ) Property acquisitions (143,048 ) (2,413 ) Capitalized interest   (8,272 )   (10,392 ) Net cash used in investing activities   (292,081 )   (143,477 )   Net cash provided by financing activities   186,161     42,845     Net increase (decrease) in cash and cash equivalents 168   (198 ) Cash and cash equivalents at beginning of period   80       278   $ 248     $ 80     COMPARATIVE OPERATING STATISTICS (unaudited)                               Three months   6/30/2011     3/31/2011   Change Oil and gas: Heavy oil production (BOE/D) 17,670 16,226 Light oil production (BOE/D)   6,959     6,422   Total oil production (BOE/D) 24,629 22,648 Natural gas production (Mcf/D)   65,859     70,542   Total (BOE/D) 35,606 34,405   Oil and gas, per BOE: Average realized sales price $ 71.07   $ 60.26   18 % Average sales price including cash derivative settlements 66.90 59.01 13 %   Oil, per Bbl: Average WTI price $ 102.34   $ 94.60   8 % Price sensitive royalties (3.85 ) (3.56 ) Quality differential and other (0.83 ) (5.68 ) Crude oil derivatives non-cash amortization   (6.72 )   (7.07 ) Oil revenue $ 90.94     $ 78.29     16 % Add: Crude oil derivatives non cash amortization 6.72 7.07 Crude oil derivative cash settlements   (13.71 )   (10.24 ) Average realized oil price $ 83.95     $ 75.12     12 %   Natural gas price: Average Henry Hub price per MMBtu $ 4.32   $ 4.11   5 % Conversion to Mcf 0.21 0.21 Natural gas derivatives non cash amortization 0.03 (0.01 ) Location, quality differentials and other   (0.17 )   (0.09 ) Natural gas revenue per Mcf $ 4.39     $ 4.22     4 % Add: Natural gas derivatives non cash amortization (0.03 ) 0.01 Natural gas derivative cash settlements   0.39     0.41   Average realized natural gas price per Mcf $ 4.75     $ 4.64     2 %   Operating cost - oil and gas production $ 18.14   $ 18.44   -2 % Production Taxes   2.58     2.39   Total operating costs $ 20.72     $ 20.83     -1 %   DD&A - oil and gas production 16.04 16.83 -5 % General & administrative 4.91 5.26 -7 %   Interest Expenses $ 5.47   $ 5.06   8 % Berry Petroleum CompanyInvestors and MediaDavid Wolf, 1-303-999-4400Shawn Canaday,