Berry Petroleum Company (NYSE:BRY) reported net earnings of $134 million, or $2.42 per diluted share, for the third quarter of 2011. Oil and gas revenues were $225 million during the quarter. Discretionary cash flow for the quarter totaled $123 million and cash provided by operating activities totaled $165 million.

Net earnings for the quarter were affected by a net non-cash gain on hedges and a non-cash loss on extinguishment of debt which in total increased net earnings by approximately $90 million, or $1.63 per diluted share for a third quarter adjusted net earnings of $44 million, or $0.79 per diluted share.

For the third quarter of 2011 and the second quarter of 2011, Berry’s average net production in BOE per day was as follows:

 
     

Third Quarter Ended September 30
     

Second Quarter Ended June 30
2011 Production 2011 Production
Oil (Bbls) 26,091       71 % 24,629       69 %
Natural Gas (BOE) 10,825 29 % 10,977 31 %
Total BOE per day 36,916 100 % 35,606 100 %

Robert Heinemann, president and chief executive officer said, “Berry’s development program delivered a six percent increase in oil production during the third quarter. Production for the third quarter of 2011 was 36,916 BOE/D, representing growth of four percent over the second quarter of 2011 driven by increases in the Permian and California. Our quarterly operating margin of $47 per barrel was driven by our oil production, which increased to 71% of total production, and by sustained favorable pricing in California that averaged $12 over WTI. In addition, we continue to be encouraged by the Company’s potential in the Uinta Basin where we have drilled five Uteland Butte horizontal wells with strong initial production results. We have also made progress on the evaluation of our Wasatch potential.”

Mr. Heinemann continued, “Like other California producers, we are being impacted by today’s regulatory environment in California. While Berry received approval for our full diatomite development in the third quarter, the pace of drilling and steam injection is being slowed by the new, more stringent operating requirements of the state regulatory agencies. While this will impact our development pace in the near term, our estimates of well performance and ultimate recovery for the asset remain unchanged.”

“We are investing additional capital in our other assets to compensate for the slower pace of development in the diatomite. We were not able to shift our capital soon enough to make up for this impact and are lowering our production forecast to approximately 10% growth for 2011 with full-year capital expenditures of over $500 million. Looking forward to 2012, we plan to maintain our strategic focus on oil development, expect to deliver double-digit growth in production and cash flow, and invest capital within cash flow.”

Operational Update

Michael Duginski, executive vice president and chief operating officer, stated, “In the Permian, we executed a five rig program and drilled 20 wells during the quarter. Production in the Permian increased by 35% over the second quarter of 2011 to average 5,200 BOE/D. We have been actively leasing in the Permian to increase our long-term inventory, and through the end of the third quarter, we accumulated about 11,000 additional net acres at approximately $900 per acre. With these acquisitions, our total net acreage in the Permian is now approximately 38,000 acres. During the second half of 2011 we have drilled and completed a majority of our Permian wells below the Wolfcamp in the deeper zones including the Strawn, Atoka and Mississippian. While the deeper drilling comes at an additional cost, well results to date have demonstrated increased expected EURs that justify this additional investment with development costs of between $10 and $15 per BOE. Additionally, we have continued to experience capital cost pressures, primarily related to pressure pumping services in the Permian.”

“In Utah, we have a total of four Uteland Butte horizontal wells. The average initial production rates of these wells are in line with our expectations. We will add five more Uteland horizontals in the fourth quarter including our first operated well which recently came online. The Company also completed six Wasatch vertical wells in the quarter with initial production averaging 100 BOE/D. We will add 12 additional Wasatch wells in the fourth quarter including two delineation wells which will improve our understanding of the productivity and the extent of the Wasatch potential on our approximate 200,000 gross acre position.”

“In the diatomite, average production increased by 8% during the quarter to 3,820 BOE/D. As we have described previously, the N. Midway-Sunset diatomite reservoir is very shallow and produces oil, in part, by compaction. Utilizing cyclic steam injection in this unique reservoir requires closely monitored steam volumes to minimize steam to surface as well as wellbore failures. Berry is adjusting its development plans to meet these requirements and will be compelled to proceed at a slower pace. We now expect full-year 2011 production in the range of 36,000 BOE/D.”

Financial Update

David Wolf, executive vice president and chief financial officer, stated, “We completed two notable financial transactions in recent months. In the third quarter of 2011, we repurchased $95 million aggregate principal amount of our 10.25% Senior Notes due 2014 in the open market at a total cost of $106 million using availability under our credit facility. We realized a cash charge of $11 million and a non-cash charge of $3 million during the third quarter as a result of the retirement of these notes. These repurchases allow us to reduce our annual interest costs in the near-term and reduce the size of the 2014 maturity. We may make additional repurchases of our notes depending on market conditions, liquidity and other factors. Additionally, we completed our semi-annual credit facility redetermination on October 26, 2011. Total commitments increased to $1.2 billion from $875 million at our last redetermination and our borrowing base remains unchanged at $1.4 billion. The increased commitments were provided by existing lenders. Our liquidity after completing the redetermination and open market notes repurchases is approximately $750 million.”
 

2011 Guidance

For 2011 the Company is issuing the following per BOE guidance:
 
     

Anticipated range in 2011
     

Three Months 9/30/2011
Operating costs — oil and gas production $ 16.50       -       18.50

 

 

$
18.25
Production taxes

 

2.00
- 3.00

 

2.70
DD&A — oil and gas production

 

16.00
- 18.00

 

16.07
General and administrative

 

4.00
- 5.00

 

4.39
Interest expense

 

5.25
      -       6.25

 
   

5.87
Total $ 43.75       -       50.75

 
 

$
47.28
 

Explanation and Reconciliation of Non-GAAP Financial Measures
 

Discretionary Cash Flow ($ millions):
 
      Three Months Ended
9/30/2011       6/30/2011
Net cash provided by operating activities $ 165.4 $ 106.1
Add back: Net increase (decrease) in current assets

 

6.5

 

5.7
Add back: Net decrease (increase) in current liabilities including book overdraft

 

(49.1

)

 

8.8
Discretionary cash flow $ 122.8   $ 120.6
 

Third Quarter Adjusted Net Earnings ($ millions):
      Three Months Ended
9/30/2011
Adjusted net earnings $ 44.0
After tax adjustments:
Non-cash hedge gain

 

99.0
Extinguishment of debt   (9.0 )
Net earnings, as reported $ 134.0  

Operating Margin Per BOE:
      Three Months Ended
9/30/2011       6/30/2011
Average sales price including cash derivative settlements $ 67.62 $ 66.90
Operating cost - oil and gas production

 

18.25

 

18.14
Production Taxes

 

2.70

 

2.58
Operating margin $ 46.67 $ 46.18

Teleconference Call

An earnings conference call will be held Thursday, October 27, 2011 at 11:00 a.m. Eastern Time (9:00 a.m. Mountain Time). Dial 866-804-6922 to participate, using passcode 53519032. International callers may dial 857-350-1668. For a digital replay available until November 3, 2011 dial 888-286-8010 passcode 82827891. Listen live or via replay on the web at www.bry.com.

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 http://www.bry.com/index.php?page=investor.

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.”

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 Ended
9/30/2011         6/30/2011
 
REVENUES
Sales of oil and gas $ 225,325 $ 230,760
Sales of electricity

 

9,826

 

7,964
Gas marketing

 

3,612

 

3,985
Interest and other income, net

 

463
 

 

803
 

 

239,226

 

243,512
EXPENSES
Operating costs - oil and gas production

 

61,979

 

58,780
Operating costs - electricity generation

 

6,965

 

6,891
Production taxes

 

9,185

 

8,350
Depreciation, depletion & amortization - oil and gas production

 

54,581

 

51,967
Depreciation, depletion & amortization - electricity generation

 

487

 

491
Gas marketing

 

3,285

 

3,674
General and administrative

 

14,922

 

15,910
Interest

 

19,928

 

17,712
Dry hole, abandonment, impairment and exploration

 

196

 

310
Extinguishment of Debt

 

14,391
-
Realized and unrealized (gain) loss on derivatives, net

 

(162,145

)

 

(91,808

)

 

23,774
 

 

72,277
 
Earnings (loss) before income taxes

 

215,452

 

171,235
Income tax provision (benefit)

 

81,451
 

 

66,069
 
Net earnings (loss) $ 134,001   $ 105,166  
 
Basic net earnings (loss) per share $ 2.45   $ 1.93  
Diluted net earnings (loss) per share $ 2.42   $ 1.90  
 
Dividends per share $ 0.080   $ 0.075  
 
CONDENSED BALANCE SHEETS
(In thousands)
(unaudited)
       

9/30/2011
        12/31/2010
ASSETS
Current assets

 

176,153

 

142,866
Oil and gas properties, buildings and equipment, net

 

3,076,894

 

2,655,792
Derivative instruments

 

34,703

 

2,054
Other assets

 

31,461

 

37,904
$ 3,319,211 $ 2,838,616
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities

 

237,022

 

270,651
Deferred income taxes

 

421,396

 

329,207
Long-term debt

 

1,336,729

 

1,108,965
Derivative instruments

 

-

 

33,526
Other long-term liabilities

 

79,691

 

71,714
Shareholders' equity

 

1,244,373

 

1,024,553
$ 3,319,211 $ 2,838,616
 
CONDENSED STATEMENTS OF CASH FLOWS
(In thousands)
(unaudited)
          Three Months Ended
  9/30/2011           6/30/2011
 
Cash flows from operating activities:
Net (loss) earnings

$

134,001

$

105,166
Depreciation, depletion and amortization 55,068 52,458
Extinguishment of debt

3,377
-
Amortization of debt issuance costs and net discount 2,056 2,106
Dry hole and impairment 18 298
Derivatives (159,179 ) (104,963 )
Stock-based compensation expense 2,012 2,387
Deferred income taxes 85,524 63,893
Other, net 972 (5 )
Cash paid for abandonment (1,057 ) (761 )
Change in book overdraft 1,337 (714 )
Net changes in operating assets and liabilities   41,239     (13,777 )
Net cash provided by operating activities   165,368     106,088  
 
Cash flows from investing activities:
Exploration and development of oil and gas properties (152,711 ) (140,761 )
Property acquisitions (9,982 ) (143,048 )
Capitalized interest   (5,572 )   (8,272 )
Net cash used in investing activities   (168,265 )   (292,081 )
 
Net cash provided by financing activities   2,743     186,161  
 
Net increase (decrease) in cash and cash equivalents

(154

)

168
Cash and cash equivalents at beginning of period  

248
   

80
 

$

94
 

$

248
 
 
COMPARATIVE OPERATING STATISTICS
(unaudited)
 
        Three Months Ended
  9/30/2011         6/30/2011       Change
Oil and gas:
Heavy oil production (BOE/D) 18,173 17,670
Light oil production (BOE/D)   7,918     6,959  
Total oil production (BOE/D) 26,091 24,629
Natural gas production (Mcf/D)   64,950     65,859  
Total (BOE/D) 36,916 35,606
 
Oil and gas, per BOE:
Average realized sales price

$

66.74

$

71.07
-6%
Average sales price including cash derivative settlements 67.62 66.90 1%
 
Oil, per Bbl:
Average WTI price

$

89.48

$

102.34
-13%
Price sensitive royalties (3.37 ) (3.85 )
Quality differential and other 4.45 (0.83 )
Crude oil derivatives non-cash amortization   (6.56 )   (6.72 )
Oil revenue

$

84.00
 

$

90.94
  -8%
Add: Crude oil derivatives non cash amortization 6.56 6.72
Crude oil derivative cash settlements   (6.32 )   (13.71 )
Average realized oil price

$

84.24
 

$

83.95
  0%
 
Natural gas price:
Average Henry Hub price per MMBtu

$

4.20

$

4.32
-3%
Conversion to Mcf 0.21 0.21
Natural gas derivatives non cash amortization 0.02 0.03
Location, quality differentials and other   (0.18 )   (0.17 )
Natural gas revenue per Mcf

$

4.25
 

$

4.39
  -3%
Add: Natural gas derivatives non cash amortization (0.02 ) (0.03 )
Natural gas derivative cash settlements   0.42     0.39  
Average realized natural gas price per Mcf

$

4.65
 

$

4.75
  -2%
 
Operating cost - oil and gas production

$

18.25

$

18.14
1%
Production Taxes   2.70     2.58  
Total operating costs

$

20.95
 

$

20.72
  1%
 
DD&A - oil and gas production 16.07 16.04 0%
General & administrative 4.39 4.91 -11%
 
Interest Expenses

$

5.87

$

5.47
7%

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