Berry Petroleum Announces Results For First Quarter Of 2012

Berry Petroleum Company (NYSE: BRY) reported net earnings of $34 million, or $0.61 per diluted share, for the first quarter of 2012. Net earnings for the quarter were affected by a non-core asset sale, a gain on sale of derivatives, non-cash changes in the mark to market of derivatives, and other items. Excluding these items, adjusted net earnings was $50.3 million, or $0.91 per diluted share. Sales of oil and natural gas were $234 million during the quarter. Discretionary cash flow for the quarter totaled $131.5 million and net cash provided by operating activities totaled $155 million.

Operating margins for the quarter were $54 per BOE, up from $48 per BOE in the fourth quarter of 2011. Total production in the first quarter of 2012 averaged 34,447 BOE/D, down 4% from the fourth quarter of 2011. Natural gas production declined 8% during the quarter, while oil production declined 2%. Total production for the first quarter of 2012 and fourth quarter of 2011 were as follows:
          First Quarter 2012         Fourth Quarter 2011
Oil (Bbls/D) 25,096         73 % 25,663         72 %
Natural gas (BOE/D) 9,351   27 % 10,127   28 %
Total (BOE/D) 34,447 100 % 35,790 100 %

Robert Heinemann, president and chief executive officer stated, "Berry's first quarter production was impacted by our Diatomite and Permian assets. Diatomite production averaged 2,685 BOE/D, down 300 BOE/D from the fourth quarter of 2011. As we have previously discussed, we have begun implementing a redesign of our development of the Diatomite. The redesign includes bringing a larger number of wells into production simultaneously, utilizing smaller injection cycles, and monitoring real-time asset performance. Each of these changes was designed to minimize subsurface wellbore stress. We have drilled approximately 90 wells since the beginning of the fourth quarter of last year and have commenced steam injection in these wells. These changes impacted ongoing operations throughout the quarter as we had to temporarily take more producing wells off-line to accommodate the drilling and simultaneous start-up of our new wells. These wells have since returned to production, and this drilling process is included in our plan going forward."

Mr. Heinemann continued, “We were pleased to receive revisions to our project approval letter from the California Department of Oil and Gas and Geothermal Resources (DOGGR) in February, which, among other modifications, removed the requirement to cease cyclic steaming operations on wells located within 150 feet of a failed well bore until that well was either repaired or abandoned. Additionally, revisions in the administration of current regulations from DOGGR should reduce operational issues we had experienced. For example, shutting in production in proximity to a failed well bore exacerbated the stress on the surrounding wells and locally increased the incidence of additional failures. The requirement to shut in the surrounding wells reduced the number completions that we were able to bring back online. We are pleased that we now have a sufficient set of active completions in our cyclic operations going forward, although we do expect 2012 Diatomite production to be approximately 400 BOE/D behind schedule as a result of all these issues. We continue to expect total production to be within our guidance range of 38,000 - 39,000 BOE/D for 2012."

Production from the Company's next generation heavy oil projects, which include our McKittrick asset, averaged 1,510 BOE/D, a 19% increase from the fourth quarter of 2011. Drilling began at the Main Camp and Pan properties and the Company expects to drill approximately 40 wells here during the remainder of the year.

Mr. Heinemann added, “Production from the Permian was flat during the first quarter at 5,600 BOE/D. The Company entered the year with 800 BOE/D of production shut-in due to gas curtailment. We completed work during the quarter to install secondary outlets in our key operating areas, which should reduce curtailments going forward. We drilled 15 gross wells during the first quarter and expect to drill an additional 75 gross wells during the remainder of 2012. The Company acquired an additional 16,000 prospective acres in the Permian, bringing our total Permian acreage to 58,000 net acres. Plans are to drill four wells on the Company's prospective acreage outside the Wolfberry fairway during 2012 and evaluate those results by year-end. Production from the Company's Uinta properties was flat during the quarter, averaging 5,430 BOE/D. In the first quarter, the Company drilled 15 gross Uinta wells, all of which targeted higher oil potential areas, with a focus on drilling commingled Green River / Wasatch wells. The Green River / Wasatch wells we have recently completed are encouraging, with oil comprising approximately 80% of the production."

David Wolf, executive vice president and chief financial officer, stated, “Berry's financial position remains strong. We successfully completed a $600 million 6.375% senior note offering during the first quarter using the proceeds to reduce borrowings under our credit facility, retire $200 million of our 8.25% senior subordinated notes and tender for $150 million of our 10.25% senior notes. These transactions allowed us to increase the weighted average maturity of our debt by three years while keeping our cash run rate of interest expense flat. Our liquidity was also improved by these transactions and is over $800 million today. On April 13, 2012, we completed a credit facility redetermination increasing our borrowing base to $1.4 billion with commitments from our lenders remaining at $1.2 billion."

2012 Guidance                  
For 2012 the Company is issuing the following per BOE guidance:
Anticipated range in 2012 Three Months 3/31/2012
Operating costs — oil and natural gas production $ 17.00 - 19.50 17.31
Production taxes 2.75 - 3.50 3.40
DD&A — oil and natural gas production 15.00 - 18.00 15.30
General and administrative 4.25 - 5.50 5.66
Interest expense 5.50   - 6.25 6.41
Total $ 44.50   - 52.75 $ 48.08

Teleconference Call

An earnings conference call will be held Thursday, April 26, 2012 at 10:00 a.m. Eastern Time (8:00 a.m. Mountain Time). Dial 866-788-0544 to participate, using passcode 32492644. International callers may dial 857-350-1682. For a digital replay available until May 3, 2012 dial 888-286-8010 passcode 79131579. 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 believes that 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 are 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 BOE sold 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 our 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 $ 155.4
Net increase in current assets 10.5
Net increase in current liabilities including book overdraft (19.7 )
Cash settlements from early termination of natural gas derivatives (14.7 )
Discretionary cash flow $ 131.5  
Adjusted Net Earnings ($ millions):      
Three Months Ended
Adjusted net earnings $ 50.3
After tax adjustments:
Non-cash derivative loss (26.6 )
Early termination of natural gas derivatives 9.1
Gain on sale of assets 1.1  
Net earnings, as reported $ 33.9  
Operating Margin Per BOE:                
Three Months Ended Three Months Ended
3/31/2012 12/31/2011
Average sales price including cash derivative settlements $ 74.44 $ 68.80
Operating cost - oil and natural gas production 17.31 18.11
Production taxes 3.40   2.64
Operating margin $ 53.73   $ 48.05

About Berry Petroleum Company

Berry Petroleum Company is a publicly traded independent oil and natural 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 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
3/31/2012 12/31/2011
Sales of oil and natural gas $ 233,653 $ 227,298
Sales of electricity 5,980 10,750
Natural gas marketing 1,859 2,550
Gain on sale of assets 1,763
Interest and other income, net 747   391  
244,002 240,989
Operating costs - oil and natural gas production 54,252 59,634
Operating costs - electricity generation 5,017 5,720
Production taxes 10,658 8,691
Depreciation, depletion & amortization - oil and natural gas production 47,956 55,202
Depreciation, depletion & amortization - electricity generation 466 484
Natural gas marketing 1,777 2,563
General and administrative 17,741 14,604
Interest 20,104 19,512
Dry hole, abandonment, impairment and exploration 3,036 4,685
Extinguishment of debt 1,152
Realized and unrealized loss on derivatives, net 28,481 112,529
Impairment of oil and natural gas properties   625,564  
189,488   910,340  
Earnings (loss) before income taxes 54,514 (669,351 )
Income tax provision (benefit) 20,616   (254,618 )
Net earnings (loss) $ 33,898   $ (414,733 )
Basic net earnings (loss) per share $ 0.62   $ (7.62 )
Diluted net earnings (loss) per share $ 0.61   $ (7.62 )
Dividends per share $ 0.080   $ 0.080  
(In thousands)
          3/31/2012           12/31/2011
Current assets 206,189 167,634
Oil and natural gas properties, (successful efforts basis) buildings and equipment, net 2,650,904 2,531,393
Derivative instruments 276 7,027
Other assets 36,831   28,898
$ 2,894,200   $ 2,734,952
Current liabilities 252,210 231,173
Deferred income taxes 207,992 185,450
Long-term debt 1,449,290 1,380,192
Derivative instruments 19,338 15,505
Other long-term liabilities 86,833 81,903
Shareholders’ equity 878,537   840,729
$ 2,894,200   $ 2,734,952
(In thousands)
          Three Months Ended
3/31/2012           12/31/2011
Cash flows from operating activities:
Net earnings (loss) $ 33,898 $ (414,733 )
Depreciation, depletion and amortization 48,422 55,686
Gain on sale of assets (1,763 )
Extinguishment of debt 695
Amortization of debt issuance costs and net discount 2,037 1,982
Impairment of oil and natural gas properties 625,564
Dry hole and impairment 28 4,300
Derivatives 42,837 110,589
Stock-based compensation expense 3,104 2,185
Deferred income taxes 16,567 (254,375 )
Other, net 683 1,695
Allowance for bad debt 315
Change in book overdraft (509 ) (5,515 )
Net changes in operating assets and liabilities 9,787   (44,064 )
Net cash provided by operating activities 155,406   84,009  
Cash flows from investing activities:
Exploration and development of oil and natural gas properties (167,758 ) (102,968 )
Property acquisitions (8,529 ) (2,647 )
Capitalized interest (5,190 ) (4,881 )
Proceeds from sale of assets 15,700
Deposits on asset sales (3,300 ) 3,300  
Net cash used in investing activities (169,077 ) (107,196 )
Net cash provided by financing activities 57,369   23,391  
Net increase (decrease) in cash and cash equivalents 43,698 204
Cash and cash equivalents at beginning of period 298   94  
Cash and cash equivalents at end of period $ 43,996   $ 298  
          Three Months Ended
3/31/2012           12/31/2011         Change
Oil and natural gas:
Heavy oil production (BOE/D) 17,005 17,497
Light oil production (BOE/D) 8,091   8,166  
Total oil production (BOE/D) 25,096 25,663
Natural gas production (Mcf/D) 56,105   60,759  
Total (BOE/D) 34,447 35,790
Oil and natural gas, per BOE:
Average realized sales price $ 74.33 $ 69.29 7 %
Average sales price including cash derivative settlements 74.44 68.80 8 %
Oil, per BOE:
Average WTI price $ 103.03 $ 94.06 10 %
Price sensitive royalties (4.24 ) (3.63 )
Quality differential and other (1.48 ) 4.75
Oil derivatives non-cash amortization (1.14 ) (6.76 )
Oil revenue per BOE $ 96.17   $ 88.42   9 %
Add: Oil derivatives non-cash amortization 1.14 6.76
Oil derivative cash settlements (3.08 ) (8.89 )
Average realized oil price $ 94.23   $ 86.29   9 %
Natural gas price:
Average Henry Hub price per MMBtu $ 2.72 $ 3.54 (23 )%
Conversion to Mcf 0.18 0.21
Natural gas derivatives non-cash amortization (0.01 )
Location, quality differentials and other (0.30 ) (0.24 )
Natural gas revenue per Mcf $ 2.59   $ 3.51   (26 )%
Natural gas derivatives non-cash amortization 0.01
Natural gas derivative cash settlements 0.92   0.61  
Average realized natural gas price per Mcf $ 3.52   $ 4.12   (15 )%
Operating cost - oil and natural gas production per BOE $ 17.31 $ 18.11 (4 )%
Production taxes per BOE 3.40   2.64  
Total operating costs per BOE $ 20.71 $ 20.75 %
DD&A - oil and natural gas production per BOE 15.30 16.77 (9 )%
General & administrative per BOE 5.66 4.44 27 %
Interest expense per BOE $ 6.41 $ 5.93 8 %

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