Berry Petroleum Announces Results for Second Quarter of 2012

Berry Petroleum Company (NYSE: BRY) reported net earnings of $81 million, or $1.46 per diluted share, for the second quarter of 2012. The reported earnings include a non-cash gain on derivatives of $68 million, a loss on extinguishment of debt of $26 million and a legal matter of $2 million. Excluding these items, adjusted net earnings was $41 million, or $0.73 per diluted share. Oil and natural gas sales were $222 million during the quarter. Discretionary cash flow for the quarter totaled $119 million, and net cash provided by operating activities totaled $93 million.

Total production in the second quarter of 2012 averaged 35,341 BOE/D. The Company's production mix was 74% oil during the quarter, with a 5% increase in oil production and an expected 3% decline in the Company's natural gas production as compared to the first quarter of 2012. Total production for the second quarter of 2012 and first quarter of 2012 were as follows:

Second Quarter 2012First Quarter 2012
Oil (BOE/D) 26,296 74 % 25,096 73 %
Natural gas (BOE/D) 9,045 26 % 9,351 27 %
Total (BOE/D) 35,341 100 % 34,447 100 %

Robert Heinemann, President and Chief Executive Officer stated, “All of our oil assets grew production in the second quarter, led by 16% growth in the Permian and our New Steam Floods, 11% in the Diatomite and 4% in the Uinta. Our operating margins were approximately $48 per BOE, supported by sales of our California oil at a $9 average premium to WTI.”

Mr. Heinemann continued, “Our Diatomite wells which were completed in the first quarter of 2012 all received their first steam injection in the second quarter, and they have begun contributing to production. Diatomite production has grown consistently since March, averaging 2,970 BOE/D in the second quarter. Our revised development approach, which includes modified injection methods and real-time performance monitoring, has started successfully, with our new wells performing on the type curve. We are encouraged that we have not experienced any wellbore failures in our 2012 Diatomite development areas over the last four months, although we are continuously monitoring the integrity of our wells. Implementing this strategy of maximizing the number of active completions by optimizing injection will enhance the long-term value of the Diatomite and support the ultimate recovery of our resource.”

Second quarter production from the Company's next generation heavy oil projects averaged 1,745 BOE/D. The Company drilled 38 wells in the second quarter, including 15 at McKittrick and 13 at Main Camp. While production grew approximately 16% from first quarter levels, the Company experienced some timing delays related to bringing wells online and the commissioning of steam generators, which has delayed the asset's growth rate this year. The Company's legacy South Midway properties continue to perform as expected, averaging 12,675 BOE/D in the second quarter.

Mr. Heinemann added, “Production from our Permian properties was higher during the second quarter, at approximately 6,500 BOE/D. We drilled 25 wells with six rigs in the second quarter. Appraisal of our prospective acreage outside the Wolfberry fairway began in the second quarter, and we expect to determine its development potential by year-end. While our secondary outlets in our key operating areas reduced our natural gas curtailments from first quarter levels, we continue to experience processing issues along with drilling delays across our asset base, which has impacted the Permian's full-year production goal.”

In the second quarter, production from the Company's Uinta properties averaged 5,650 BOE/D. The Company utilized a three-rig program and drilled 22 gross Uinta wells, a majority of which commingled the Wasatch and Green River formations, targeting higher oil potential areas. In June 2012, Berry received approval of its US Forest Service EIS that enables the Company's development of approximately 25,000 net acres in the Ashley Forest. In the second quarter, the Company purchased an additional 10,000 net acres in the Lake Canyon area targeting the Wasatch formation, increasing the Company's total net Uinta acreage by approximately 10% to 106,000 net acres.

Mr. Heinemann continued, "While we were pleased to see all three oil basins grow production in the second quarter, several issues have contributed to a slightly slower start to 2012. These include logistical delays in California, processing constraints in the Permian, and drilling delays. Because of the impact of these issues, we now expect 2012 production to average 37,000 BOE/D. We will continue focusing on development of our oil assets and plan to grow them by approximately 14% in 2012.”

David Wolf, executive vice president and chief financial officer, stated, “Our financial position remains strong, with approximately $730 million of liquidity today. We continue to believe that our strong oil hedge positions of approximately 70% of production in 2012 and 45% in 2013 will help moderate the effects of a volatile commodity environment. In the second quarter, we maintained minimal exposure to natural gas liquids, with approximately 3% of our revenues coming from NGLs.”

2012 Guidance
For 2012 the Company is issuing the following per BOE guidance:
Anticipated rangeThree Months Ended
in 201206/30/2012
Operating costs—oil and natural gas production $ 17.00 - 19.50 19.42
Production taxes 2.75 - 3.50 3.01
DD&A—oil and natural gas production 15.00 - 18.00 16.18
General and administrative 4.25 - 5.50 5.59
Interest expense 5.50 - 6.25 6.46
Total $ 44.50 - 52.75 $ 50.66

Teleconference Call

An earnings conference call will be held Thursday, August 2, 2012 at 10:00 a.m. Eastern Time (8:00 a.m. Mountain Time). Dial 877-261-8992 to participate, using passcode 32934561. International callers may dial 847-619-6548, using passcode 32934561. For a digital replay available until August 10, 2012, dial 888-843-7419, passcode 32934561. Listen live or via replay on the web at

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 Regulation G of the Securities Exchange Act of 1934, as amended. Discretionary cash flow consists of cash provided by operating activities before changes in working capital items. The Company uses discretionary cash flow as a measure of liquidity and believes it provides useful information to investors because it assesses cash flow from operations for each period before changes in working capital, which fluctuates due to the timing of collections of receivables and the settlements of liabilities. Adjusted net earnings consists of net earnings before non-cash derivatives gains (losses), oil and natural gas property impairments and charges related to the extinguishment of debt. The Company believes that adjusted net earnings is useful for evaluating the Company's operational performance from oil and natural gas properties. Operating margin per BOE consists of oil and natural gas revenues less oil and natural gas operating expenses and production taxes divided by the total BOEs produced during the period. The Company uses operating margin per barrel as a measure of profitability and believes it provides useful information to investors because it relates the Company's oil and natural gas revenue and oil and natural gas operating expenses to its total units of production providing a gross margin per unit of production, allowing investors to evaluate how the Company's profitability varies on a per unit basis each period. These measures should not be considered in isolation or as a substitute for their most directly comparable GAAP measures. Other companies calculate non-GAAP measures differently and, therefore, the non-GAAP measures presented in this release may not be comparable to similarly titled measures used by other companies.

Explanation and Reconciliation of Non-GAAP Financial Measures
Discretionary Cash Flow ($ millions):
Three Months Ended
Net cash provided by operating activities $ 92.7 $ 155.4
Net increase (decrease) current assets (14.9 ) 10.5
Net decrease (increase) in current liabilities including book overdraft 6.2 (19.7 )
Cash premiums for repurchases of notes 34.7
Cash settlements from early termination of natural gas derivatives (14.7 )
Discretionary cash flow $ 118.7 $ 131.5
Adjusted Net Earnings ($ millions):
Three Months Ended
Adjusted net earnings $ 40.5
After tax adjustments:
Non-cash derivative gain 68.1
Extinguishment of debt (25.8 )
Legal matter (1.8 )
Net earnings, as reported $ 81.0
Operating Margin Per BOE:
Three Months Ended
Average sales price including cash derivative settlements $ 70.40 $ 74.44
Operating cost—oil and natural gas production 19.42 17.31
Production taxes 3.01 3.40
Operating margin $ 47.97 $ 53.73

About Berry Petroleum Company

Berry Petroleum Company is a publicly traded independent oil and natural gas production and exploitation company with operations in California, Texas, Utah, and Colorado. 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 the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including the Company’s drilling program, production, 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.”

(In thousands, except per share data)
Three Months Ended
Oil and natural gas sales $ 221,781 $ 233,653
Electricity sales 5,860 5,980
Natural gas marketing 1,580 1,859
(Loss) gain on sale of assets (163 ) 1,763
Interest and other income, net 645 747
229,703 244,002
Operating costs—oil and natural gas production 62,461 54,252
Operating costs—electricity generation 4,256 5,017
Production taxes 9,690 10,658
Depreciation, depletion & amortization—oil and natural gas production 52,026 47,956
Depreciation, depletion & amortization—electricity generation 455 466
Natural gas marketing 1,387 1,777
General and administrative 17,965 17,741
Interest 20,789 20,104
Dry hole, abandonment, impairment and exploration 1,547 3,008
Extinguishment of debt 41,526
Realized and unrealized (gain) loss on derivatives, net (113,082 ) 28,481
Impairment of oil and natural gas properties 38 28
99,058 189,488
Earnings before income taxes 130,645 54,514
Income tax provision 49,629 20,616
Net earnings $ 81,016 $ 33,898
Basic net earnings per share $ 1.47 $ 0.62
Diluted net earnings per share $ 1.46 $ 0.61
Dividends per share $ 0.080 $ 0.080
(In thousands)
Current assets 152,964 167,634
Oil and natural gas properties, (successful efforts basis) buildings and equipment, net 2,810,963 2,531,393
Derivative instruments 20,092 7,027
Other assets 32,035 28,898
$ 3,016,054 $ 2,734,952
Current liabilities 225,296 231,173
Deferred income taxes 230,736 185,450
Long-term debt 1,502,674 1,380,192
Derivative instruments 15,505
Other long-term liabilities 98,542 81,903
Shareholders’ equity 958,806 840,729
$ 3,016,054 $ 2,734,952
(In thousands)
Three Months Ended
Cash flows from operating activities:
Net earnings $ 81,016 $ 33,898
Depreciation, depletion and amortization 52,481 48,422
Loss (gain) on sale of assets 163 (1,763 )
Extinguishment of debt 6,842
Amortization of debt issuance costs and net discount 1,651 2,037
Impairment of oil and natural gas properties 38 28
Dry hole and impairment 211
Derivatives (109,738 ) 42,837
Stock-based compensation expense 2,322 3,104
Deferred income taxes 50,215 16,567
Other, net (1,207 ) 683
Allowance for bad debt 315
Change in book overdraft (2,119 ) (509 )
Net changes in operating assets and liabilities 10,786 9,787
Net cash provided by operating activities 92,661 155,406
Cash flows from investing activities:
Exploration and development of oil and natural gas properties (161,210 ) (167,758 )
Property acquisitions (16,322 ) (8,529 )
Capitalized interest (4,533 ) (5,190 )
Proceeds from sale of assets 22 15,700
Deposits on asset sales (3,300 )
Net cash used in investing activities (182,043 ) (169,077 )
Net cash provided by financing activities 45,467 57,369
Net (decrease) increase in cash and cash equivalents (43,915 ) 43,698
Cash and cash equivalents at beginning of period 43,996 298
Cash and cash equivalents at end of period $ 81 $ 43,996
Three Months Ended
Oil and natural gas:
Heavy oil production (BOE/D) 17,395 17,005
Light oil production (BOE/D) 8,901 8,091
Total oil production (BOE/D) 26,296 25,096
Natural gas production (Mcf/D) 54,271 56,105
Total (BOE/D) 35,341 34,447
Oil and natural gas, per BOE:
Average realized sales price $ 69.07 $ 74.33 (7 )%
Average sales price including cash derivative settlements 70.40 74.44 (5 )%
Oil, per BOE:
Average WTI price $ 93.35 $ 103.03 (9 )%
Price sensitive royalties (3.55 ) (4.24 )
Quality differential and other (0.51 ) (1.48 )
Oil derivatives non-cash amortization (1.12 ) (1.14 )
Oil revenue per BOE $ 88.17 $ 96.17 (8 )%
Add: Oil derivatives non-cash amortization 1.12 1.14
Oil derivative cash settlements 0.79 (3.08 )
Average realized oil price $ 90.08 $ 94.23 (4 )%
Natural gas price:
Average Henry Hub price per MMBtu $ 2.21 $ 2.72 (19 )%
Conversion to Mcf 0.15 0.18
Natural gas derivatives non-cash amortization 0.03 (0.01 )
Location, quality differentials and other (0.11 ) (0.30 )
Natural gas revenue per Mcf $ 2.28 $ 2.59 (12 )%
Natural gas derivatives non-cash amortization (0.03 ) 0.01
Natural gas derivative cash settlements (0.03 ) 0.92
Average realized natural gas price per Mcf $ 2.22 $ 3.52 (37 )%
Operating cost - oil and natural gas production per BOE $ 19.42 $ 17.31 12 %
Production taxes per BOE 3.01 3.40
Total operating costs per BOE $ 22.43 $ 20.71 8 %
DD&A - oil and natural gas production per BOE 16.18 15.30 6 %
General & administrative per BOE 5.59 5.66 (1 )%
Interest expense per BOE $ 6.46 $ 6.41 1 %


Berry Petroleum Company
Investors and Media
Zach Dailey, 1-303-999-4071
Shawn Canaday, 1-303-999-4000
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