Item 1 Business.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Factors that can cause price volatility for crude oil and natural gas include:
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availability and capacity of refineries;
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availability of gathering systems with sufficient capacity to handle local production;
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seasonal fluctuations in local demand for production;
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local and national gas storage capacity;
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interstate pipeline capacity; and
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availability and cost of gas transportation facilities.
Brundage Canyon crude oil production, which is approximately 40 degree API gravity, is sold under contract at WTI less a fixed differential approximating $2.00 per barrel. This contract expires on September 30, 2006. Any new contract will be negotiated based on market prices. We believe the differential has widened by several dollars per barrel. The majority of this crude oil, while light, is a “paraffinic” crude, and can be processed efficiently by only a limited number of stranded inland refineries. The production of this type crude is increasing regionally and beginning to strain the capacity of these refineries. Other new crude sources from the region are pressuring pricing. If these refineries limit the volumes of this parraffinic crude oil they are willing to process, it could impact the marketability of this type of crude which, for Berry, represents approximately 3,500 Bbl/D of production or approximately 15% of total current production. We are investigating the market opportunities for this crude oil. If market prices continue to deteriorate, we may allocate capital expenditures to projects which produce natural gas and crude oils with lower paraffinic content until the refinery constraint is resolved.
We may be subject to the risk of adding additional steam generation equipment if the electrical market deteriorates significantly. We may be subject to the risk of adding additional steam generation equipment if the electrical market deteriorates significantly. We are dependent on several cogeneration facilities that provide over half of our steam requirement. These facilities are dependent on reasonable electrical contracts. If, for any reason, we were unable to enter into an electrical contract or were to lose an existing contract, we may not be able to supply 100% of the steam requirements necessary to maximize production from our heavy oil assets. An additional investment in various steam sources may be necessary to replace such steam, and there may be risks and delays in being able to install conventional steam equipment due to permitting requirements. The financial cost and timing of such investment may adversely affect our production, capital outlays and cash provided by operating activities. We have electricity contracts covering most of our electricity generation which contracts expire in 2009.
A shortage of natural gas in California could adversely affect our business. We may be subject to the risks associated with a shortage of natural gas and/or the transportation of natural gas into and within California. We are highly dependent on sufficient volumes of natural gas that we use for fuel in generating steam in our heavy oil operations in California. If the required volume of natural gas for use in our operations were to be unavailable or too highly priced to produce heavy oil economically, our production could be adversely impacted. The Company has firm transportation to move 12,000 MMBtu/D on the Kern River Pipeline from the Rocky Mountains to Kern County, CA. This volume is approximately one-third of the Company’s current requirement.
Our use of oil and gas price hedging contracts involves credit risk and may limit future revenues from price increases and result in significant fluctuations in net income. We use hedging transactions with respect to a portion of our oil and gas production to achieve more predictable cash flow and to reduce our exposure to a significant decline in the price of crude oil. While the use of hedging transactions limits the downside risk of price declines, their use may also limit future revenues from price increases. Hedging transactions also involve the risk that the counterparty may be unable to satisfy its obligations. The Company utilizes several counterparties for its hedging contracts.
Our future success depends on our ability to find, develop and acquire oil and gas reserves. To maintain production levels, we must locate and develop or acquire new oil and gas reserves to replace those depleted by production. Without successful exploration, exploitation or acquisition activities, our reserves, production and revenues will decline. We may not be able to find and develop or acquire additional reserves at an acceptable cost. In addition, substantial capital is required to replace and grow reserves. If lower oil and gas prices or operating difficulties result in our cash flow from operations being less than expected or limit our ability to borrow under credit arrangements, we may be unable to expend the capital necessary to locate and develop or acquire new oil and gas reserves.
Actual quantities of recoverable oil and gas reserves and future cash flows from those reserves , future production, oil and gas prices, revenues, taxes, development expenditures and operating expenses most likely will vary from estimates. Estimating accumulations of oil and gas is complex. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds, some of which are mandated by the SEC. The accuracy of a reserve estimate is a function of:
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quality and quantity of available data;
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interpretation of that data; and
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accuracy of various mandated economic assumptions.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Any significant variance could materially affect the quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of development and exploration and prevailing oil and gas prices.
In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.
If oil or gas prices decrease, we may be required to take writedowns. We may be required to writedown the carrying value of our oil and gas properties when oil or gas prices are low, including basis differentials, or there are substantial downward adjustments to our estimated proved reserves, increases in estimates of development costs or deterioration in exploration or production results.
We capitalize costs to acquire, find and develop our oil and gas properties under the successful efforts accounting method. If net capitalized costs of our oil and gas properties exceed fair value, we must charge the amount of the excess to earnings. We review the carrying value of our properties annually and at any time when events or circumstances indicate a review is necessary, based on prices in effect as of the end of the reporting period. The carrying value of oil and gas properties is computed on a field-by-field basis. Once incurred, a writedown of oil and gas properties is not reversible at a later date even if oil or gas prices increase. See Item 7A Quantitative and Qualitative Disclosures About Market Risk for the Company’s hedge position on February 10, 2006.
Competitive industry conditions may negatively affect our ability to conduct operations. Competition in the oil and gas industry is intense, particularly with respect to the acquisition of producing properties and proved undeveloped acreage. Major and independent oil and gas companies actively bid for desirable oil and gas properties, as well as for the equipment and labor required to operate and develop their properties. Many of our competitors have financial resources that are substantially greater, which may adversely affect our ability to compete within the industry.
Drilling is a high-risk activity. Our future success will partly depend on the success of our drilling program. In addition to the numerous operating risks described in more detail below, these drilling activities involve the risk that no commercially productive oil or gas reservoirs will be discovered. In addition, we are often uncertain as to the future cost or timing of drilling, completing and producing wells. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
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obtaining government and tribal required permits;
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unexpected drilling conditions;
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pressure or irregularities in formations;
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equipment failures or accidents;
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adverse weather conditions;
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compliance with governmental or landowner requirements; and
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shortages or delays in the availability of drilling rigs and the delivery of equipment and/or services.
The oil and gas business involves many operating risks that can cause substantial losses; insurance may not protect us against all of these risks. These risks include:
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fires;
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explosions;
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blow-outs;
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uncontrollable flows of oil, gas, formation water or drilling fluids;
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natural disasters;
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pipe or cement failures;
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casing collapses;
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embedded oilfield drilling and service tools;
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abnormally pressured formations;
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major equipment failures, including cogeneration facilities; and
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environmental hazards such as oil spills, natural gas leaks, pipeline ruptures and discharges of toxic gases.
If any of these events occur, we could incur substantial losses as a result of:
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injury or loss of life;
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severe damage or destruction of property, natural resources and equipment;
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pollution and other environmental damage;
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investigatory and clean-up responsibilities;
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regulatory investigation and penalties;
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suspension of operations; and
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repairs to resume operations.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
If we experience any of these problems, our ability to conduct operations could be adversely affected. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect us. In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our Management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. While we intend to obtain and maintain appropriate insurance coverage for these risks, there can be no assurance that our operations will not expose us to liabilities exceeding such insurance coverage or to liabilities not covered by insurance.
We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business. Our development, exploration, production and marketing operations are regulated extensively at the federal, state and local levels. In addition, a portion of our leases in the Uinta Basin are, and some of our future leases may be, regulated by Native American tribes. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations oppose certain drilling projects and/or access to prospective lands.
Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to the regulation by oil and natural gas-producing states and one Native American tribe of conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state, local and Native American tribal authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a negative effect on our ability to explore on or develop its properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability.
Property acquisitions are a component of our growth strategy, and our failure to complete future acquisitions successfully could reduce our earnings and slow our growth. Our business strategy has emphasized growth through strategic acquisitions, but we may not be able to continue to identify properties for acquisition or we may not be able to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our strategy of completing acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. If we are unable to achieve strategic acquisitions, our growth may be impaired, thus impacting earnings, cash from operations and reserves.
Acquisitions are subject to the uncertainties of evaluating recoverable reserves and potential liabilities. Our recent growth is due in part to acquisitions of producing properties, and we expect acquisitions will continue to contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, exploration potential, future oil and natural gas prices, operating costs, production taxes and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties, which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not allow us to become sufficiently familiar with the properties, and we do not always discover structural, subsurface and environmental problems that may exist or arise. Our review prior to signing a definitive purchase agreement may be even more limited.
We generally are not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities, on acquisitions. Often, we acquire interests in properties on an "as is" basis with limited remedies for breaches of representations and warranties. If material breaches are discovered by us prior to closing, we could require adjustments to the purchase price or if the claims are significant, we or the seller may have a right to terminate the agreement. We could also fail to discover breaches or defects prior to closing and incur significant unknown liabilities, including environmental liabilities, or experience losses due to title defects, for which we would have limited or no contractual remedies or insurance coverage.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
There are risks in acquiring producing properties, including difficulties in integrating acquired properties into our business, additional liabilities and expenses associated with acquired properties, diversion of Management attention, and costs of increased scope, geographic diversity and complexity of our operations. Increasing our reserve base through acquisitions is an important part of our business strategy. Our failure to integrate acquired businesses successfully into our existing business, or the expense incurred in consummating future acquisitions, could result in our incurring unanticipated expenses and losses. In addition, we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.
In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant Management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations
Possible future acquisitions could result in our incurring additional debt, contingent liabilities and expenses, all of which could have a material adverse effect on our financial condition and operating results.
The loss of key personnel could adversely affect our business. We depend to a large extent on the efforts and continued employment of our executive Management team and other key personnel. The loss of the services of these or other key personnel could adversely affect our business, and we do not maintain key man insurance on the lives of any of these persons. Our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen and other professionals. Competition for many of these professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.
We have limited control over the activities on properties that we do not operate. Although we operate most of the properties in which we have an interest, other companies operate some of the properties. We have limited ability to influence or control the operation or future development of these nonoperated properties or the amount of capital expenditures that we are required to fund their operation. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could have a material adverse effect on the realization of our targeted returns or lead to unexpected future costs.
We may not adhere to our proposed drilling schedule. Our final determination of whether to drill any scheduled or budgeted wells will depend on a number of factors, including:
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results of our exploration efforts and the acquisition, review and analysis of our seismic data, if any;
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availability of sufficient capital resources to us and any other participants for the drilling of the prospects;
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approval of the prospects by other participants after additional data has been compiled;
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economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability and prices of drilling rigs and crews; and
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availability of leases, license options, farm-outs, other rights to explore and permits on reasonable terms for the prospects.
Although we have identified or budgeted for numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame, or at all. In addition, our drilling schedule may vary from our expectations because of future uncertainties and rig availability and access to our drilling locations utilizing available roads. As of December 31, 2005, the Company owns two drilling rigs and has additional one-year contract commitments on another two drilling rigs. See Note 10 to the financial statements.
We may incur losses as a result of title deficiencies. We purchase working and revenue interests in the oil and natural gas leasehold interests upon which we will perform our exploration activities from third parties or directly from the mineral fee owners. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. Title insurance covering mineral leaseholds is not generally available and, often, we forego the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease until the drilling block is assembled and ready to be drilled. As is customary in our industry, we rely upon the judgment of oil and natural gas lease brokers or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest. We, in some cases, perform curative work to correct deficiencies in the marketability of the title to us. The work might include obtaining affidavits of heirship or causing an estate to be administered. In cases involving more serious title problems, the amount paid for affected oil and natural gas leases can be generally lost, and the target area can become undrillable.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
The future of the electricity market in California is uncertain. We utilize cogeneration plants in California to generate lower cost steam compared to conventional steam generation methods. Electricity produced by our cogeneration plants is sold to utilities and the steam costs are allocated to our oil and gas operations. While we have electricity sales contracts in place with the utilities that are currently scheduled to terminate in 2009, legal and regulatory decisions, especially related to the pricing of electricity under the contracts, can adversely affect the economics of our cogeneration facilities and thereby, the cost of steam for use in our oil and gas operations.
Estimates may differ from actual. The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and related disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from these estimates and assumptions used in preparation of its financial statements. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities, the related present value of estimated future net cash flows therefrom, the costs to develop and abandon oil and gas properties, the valuation of derivative positions and stock-based compensation valuation.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Information required by Item 2 Properties is included under Item 1 Business.
Item 3. Legal Proceedings
While the Company is, from time to time, a party to certain lawsuits in the ordinary course of business, the Company does not believe any of such existing lawsuits will have a material adverse effect on the Company's operations, financial condition, or liquidity.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of security holders during the most recently ended fiscal quarter.
Executive Officers of the Registrant. Listed below are the names, ages (as of December 31, 2005) and positions of the executive officers of Berry and their business experience during at least the past five years. All officers of the Company are appointed in May of each year at an organizational meeting of the Board of Directors. There are no family relationships between any of the executive officers and members of the Board of Directors.
ROBERT F. HEINEMANN, 52, has been President and Chief Executive Officer since June 2004. Mr. Heinemann was Chairman of the Board and interim President and Chief Executive Officer from April 2004 to June 2004. From December 2003 to March 2004, Mr. Heinemann was the director designated to serve as the presiding director at executive sessions of the Board in the absences of the Chairman and to act as liaison between the independent directors and the CEO. Mr. Heinemann joined the Company’s Board in March of 2003. From 2000 until 2002, Mr. Heinemann served as the Senior Vice President and Chief Technology Officer of Halliburton Company and as the Chairman of the Halliburton Technology Advisory Committee. He was previously with Mobil Oil Corporation (Mobil) where he served in a variety of positions for Mobil and its various affiliate companies in the energy and technical fields from 1981 to 1999, with his last responsibilities as Vice President of Mobil Technology Company and General Manager of the Mobil Exploration and Producing Technical Center.
RALPH J. GOEHRING, 49, has been Executive Vice President and Chief Financial Officer since June 2004. Mr. Goehring was Senior Vice President from April 1997 to June 2004, and has been Chief Financial Officer since March 1992 and was Manager of Taxation from September 1987 until March 1992. Mr. Goehring is also an Assistant Secretary for the Company.
MICHAEL DUGINSKI, 39, has been Executive Vice President of Corporate Development and California since October 2005. Mr. Duginski was Senior Vice President of Corporate Development from June 2004 through October 2005 and was Vice President of Corporate Development from February 2002 through June 2004. Mr. Duginski, a mechanical engineer, was previously with Texaco, Inc. from 1988 to 2002 where his positions included Director of New Business Development, Production Manager and Gas and Power Operations Manager. Mr. Duginski is also an Assistant Secretary for the Company.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
LOGAN MAGRUDER, 49, has been Executive Vice President of the Rocky Mountains and Mid-Continent region since October 2005. Mr. Magruder was Senior Vice President of the Rocky Mountain and Mid-Continent region from June 2004 through October 2005 and was Vice President of the Rocky Mountain and Mid-Continent region from August 2003 through June 2004. Mr. Magruder, a petroleum engineer, was a consultant for the Company from February 2003 through August 2003. Mr. Magruder was previously Vice President of U.S. Operations for Calpine Natural Gas Company from 2001 to 2003. Prior to Calpine, Mr. Magruder was employed by Barrett Resources as Vice President of Engineering and Operations from 1996 to 2001.
DAN ANDERSON, 43, has been Vice President of Rocky Mountains and Mid-Continent Production since October 2005. Mr. Anderson was Rocky Mountain and Mid-Continent Manager of Engineering from August 2003 through October 2005. Mr. Anderson was previously a Senior Staff Petroleum Engineer with Williams Production RMT from August 2001 through August 2003. He previously was a Senior Staff Engineer with Barrett Resources from October 2000 through August 2001.
GEORGE T. CRAWFORD, 45, has been Vice President of California Production since October 2005. Mr. Crawford was Vice President of Production from December 2000 through October 2005 and was Manager of Production from January 1999 to December 2000. Mr. Crawford, a petroleum engineer, was previously the Production Engineering Supervisor for Atlantic Richfield Corp. (ARCO) from 1989 to 1998 in numerous engineering and operational assignments including Production Engineering Supervisor, Planning and Evaluation Consultant and Operations Superintendent.
BRUCE S. KELSO, 50, has been Vice President of Rocky Mountains and Mid-Continent Exploration since October 2005. Mr. Kelso was Rocky Mountain and Mid-Continent Exploration Manager from August 2003 through October 2005. Mr. Kelso, a petroleum geologist, was previously a Senior Staff Geologist assigned to Rocky Mountain assets with Williams Production RMT, from January 2002 through August 2003. He previously was the Vice President of Exploration and Development at Redstone Resources, Inc. from 2000 to 2001.
BRIAN L. REHKOPF, 58, has been Vice President of Technology since October 2005. Mr. Rehkopf was Vice President of Engineering from March 2000 through October and was Manager of Engineering from September 1997 to March 2000. Mr. Rehkopf, a registered petroleum engineer, joined the Company’s engineering department in June 1997 and was previously a Vice President and Asset Manager with ARCO since 1992 and an Operations Engineering Supervisor from 1988 to 1992. Mr. Rehkopf is also an Assistant Secretary for the Company.
SHAWN M. CANADAY, 30, has been Treasurer since December 2004 and was Senior Financial Analyst from November 2003 until December 2004. Mr. Canaday has worked in the oil and gas industry since 1998 in various finance functions at ChevronTexaco and in public accounting. Mr. Canaday is also an Assistant Secretary for the Company.
DONALD A. DALE, 59, has been Controller since December 1985.
KENNETH A. OLSON, 50, has been Corporate Secretary since December 1985 and was Treasurer from August 1988 until December 2004.
PART II
Item 5. Market for the Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
Shares of Class A Common Stock (Common Stock) and Class B Stock, referred to collectively as the "Capital Stock," are each entitled to one vote and 95% of one vote, respectively. Each share of Class B Stock is entitled to a $1.00 per share preference in the event of liquidation or dissolution. Further, each share of Class B Stock is convertible into one share of Common Stock at the option of the holder.
In November 1999, the Company adopted a Shareholder Rights Agreement and declared a dividend distribution of one such Right for each outstanding share of Capital Stock on December 8, 1999. Each share of Capital Stock issued after December 8, 1999 includes one Right. The Rights expire on December 8, 2009. See Note 7 to the financial statements.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Berry's Class A Common Stock is listed on the New York Stock Exchange (NYSE) under the symbol BRY. The Class B Stock is not publicly traded. The market data and dividends for 2005 and 2004 are shown below:
The number of holders of record of the Company's Common Stock was 605 as of February 10, 2006. There was one Class B Shareholder of record as of February 10, 2006.
Dividends. The Company paid a special dividend of $.10 per share on September 29, 2005 and increased its regular quarterly dividend by 8%, from $.12 to $.13 per share beginning with the September 29, 2005 dividend. The Company's regular annual dividend is currently $.52 per share, payable quarterly in March, June, September and December. The Company paid a special dividend of $.06 per share on September 29, 2004 and increased its regular quarterly dividend by 9%, from $.11 to $.12 per share beginning with the September 2004 dividend.
Since Berry Petroleum Company's formation in 1985 through December 31, 2005, the Company has paid dividends on its Common Stock for 65 consecutive quarters and previous to that for eight consecutive semi-annual periods. The Company intends to continue the payment of dividends, although future dividend payments will depend upon the Company's level of earnings, operating cash flow, capital commitments, financial covenants and other relevant factors. Dividend payments are limited by covenants in the Company's credit facility to the greater of $20 million or 75% of net income.
As of December 31, 2005, dividends declared on 3,984,080 shares of certain Common Stock are restricted, whereby 37.5% of the dividends declared on these shares are paid by the Company to the surviving member of a group of individuals, the B group, for as long as this remaining member shall live.
Equity Compensation Plan Information
In June 2005, the Company announced that its Board of Directors authorized a share repurchase program for up to an aggregate of $50 million of the Company's outstanding Class A Common Stock. Through December 31, 2005, the Company repurchased 108,900 shares for approximately $6.3 million, which increased diluted earnings by $.01 per share.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
In December 2005, the Company adopted a plan under Rule 10b5-1 of the Securities Exchange Act of 1934 to facilitate the repurchase of its shares of common stock. Rule 10b5-1 allows a company to purchase its shares at times when it would not normally be in the market due to possession of nonpublic information, such as the time immediately preceding its quarterly earnings releases. In addition to share repurchases by the Rule 10b5-1 plan, Berry expects to continue repurchases in the open market from time to time during its normal trading windows. This 10b5-1 plan is authorized under, and is administered consistent with, the Company's $50 million share repurchase program. All repurchases of common stock are made in compliance with regulations set forth by the SEC and are subject to market conditions, applicable legal requirements and other factors.
This program does not obligate the Company to acquire any particular amount of common stock and the plan may be suspended at any time at the Company's discretion.
Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
The following table sets forth certain financial information with respect to the Company and is qualified in its entirety by reference to the historical financial statements and notes thereto of the Company included in Item 8 Financial Statements and Supplementary Data. The statement of income and balance sheet data included in this table for each of the five years in the period ended December 31, 2005 were derived from the audited financial statements and the accompanying notes to those financial statements (in thousands, except per share, per BOE and % data).
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
(1) Information has been revised to reflect the Company's change in allocation of cogeneration costs to oil and gas operations. See Item 7 Management’s Discussion and Analysis.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
(2) See Supplemental Information About Oil & Gas Producing Activities.
(3) Information has been revised to reflect the Company's change in allocation of technical labor and production taxes. See Note 2 to the financial statements.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Corporate Strategy. Berry’s mission is to increase shareholder value, primarily through increasing the net asset value and maximizing the cash flow and earnings of its assets. The strategies to accomplish these goals include:
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Growing production and reserves from existing assets while managing expenses
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Acquiring more light oil and natural gas assets with significant growth potential in the Rocky Mountain and Mid-Continent region
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Appraising our exploitation and exploration projects in an expedient manner
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Investing our capital in an efficient, disciplined manner to increase production and reserves
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Utilizing joint ventures with respected partners to enter new basins
Notable Items in 2005.
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Achieved record production which averaged 23,015 BOE/D, up 12% from
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Achieved record cash from operating activities of $188 million, up 50% from
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Achieved record net income of $112 million, up 62% from
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developmental capital expenditures were $131 million, up 82% from
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Acquired and integrated the eastern Colorado Niobrara natural gas producing assets - acquisition cost of $105 million
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Added 24.9 million BOE of reserves before production ending 2005 at 126.3 million BOE
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Achieved reserve replacement rate of 296%
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Negotiated new four-year crude oil sales contract for California heavy oil production
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Observed positive results on Diatomite play and expanded pilot
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Placed price collars on 10,000 barrels per day of future production from through 2009
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Added approximately 186,000 gross (46,000 net) acres in the North Dakota Bakken play
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Added approximately 624,000 gross (315,000 net) acres to Tri-State area inventory
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Increased quarterly dividend to $.13 per share and paid special dividend of $.10 per share for total payout of $.60 per share
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Began drilling to assess several prospects including Lake Canyon, Coyote Flats and Tri-State area
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Increased financial capacity by establishing a $500 million unsecured credit facility
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Initiated a $50 million share buyback program
Acquisitions. On January 27, 2005, we acquired certain interests in the Niobrara fields in northeastern Colorado for approximately $105 million. At December 31, 2005 the properties consist of approximately 127,000 gross (100,000 net) acres. Production at acquisition was approximately 9 MMcf of natural gas per day, with estimated proved reserves of 87 Bcf. For the month of December 2005, production averaged approximately 13,800 MMcf per day and reserves were 105 Bcf. The acquisition included approximately 200 miles of a pipeline gathering system and gas compression facilities for delivery into interstate gas lines.
In January 2005, we acquired a working interest in eastern Colorado, western Kansas and southwestern Nebraska, from an industry partner. Berry and its partner, will jointly explore and develop shallow Niobrara natural gas, Sharon Springs shale gas and deeper Pennsylvanian formation oil assets on the acreage. We paid approximately $5 million for our working interest in the acreage and believe the potential of the Tri-State area can be exploited by using new drilling techniques, with 3-D seismic technology, to assess structural complexity, estimate potentially recoverable oil and gas and determine drilling locations.
In 2005, we completed several transactions whereby we now have working interests in 186,000 gross acres (46,000 net) located in the Williston Basin in North Dakota. These lease acquisitions, totaling approximately $11 million, provide us an entry into the emerging Bakken oil play in the Williston Basin. The acreage covers several contiguous blocks located primarily on the eastern flank of the Nesson Anticline. Development activity in the Middle Bakken play is generally expanding to the area surrounding the Nesson Anticline.
In October 2005, we purchased a 50% working interest in approximately 69,000 gross undeveloped acres (24,000 net) in Colorado’s Phillips and Sedgwick Counties. This additional Niobrara leasehold position is adjacent to and immediately north of Berry’s producing natural gas assets in Yuma County. We expect to begin shooting a 3-D seismic survey and drilling the first delineation wells in 2006.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
On January 27, 2006, we announced an agreement with a private seller to acquire a 50% working interest in natural gas assets in the Piceance Basin of western Colorado for approximately $150 million in cash. Berry internally estimates there are 26 billion cubic feet (Bcf) of proved reserves and has identified over 600 drilling locations based on 10-acre development. We will be the operator in the 6,314 gross acres targeting gas in the Williams Fork section of the Mesaverde formation. We increased the 2006 capital budget by an additional $48 million to $208 million to develop this resource. There are two drilling rigs dedicated to this project, and we will ramp up our drilling activity to four rigs by the end of the year along with complementary services and goods to accelerate the development of this acquisition. Based on the productivity of this acreage and surrounding producing operations, we are seeking to add additional drilling rigs to accelerate development. The transaction closed on February 28, 2006.
Capital Expenditures. Excluding any future acquisitions, in 2006 we plan to spend approximately $208 million. These expenditures will be directed toward developing reserves, increasing oil and gas production and exploration opportunities. For 2006, Berry plans to invest approximately $146 million, or 70%, in our Rocky Mountain and Mid-Continent region assets, and $61 million, or 30%, in our California assets. Approximately half the capital budget is focused on converting probable and possible reserves into proved reserves and on our appraisal and exploratory projects.
This robust capital program allows Berry to continue its record activity levels by planning to drill 476 net wells and perform 55 well workover activities in versus approximately 188 wells and 140 well workovers in 2005. As a result, we are targeting production growth of 12% to average approximately 25,800 BOE per day, which includes the Piceance Basin acquisition, but before any other acquisitions, and we plan to continue to actively appraise significant acreage positions held for hydrocarbon potential. In 2006, we expect production to be approximately 70% heavy oil, 15% light oil and 15% natural gas and anticipate funding our capital program from internally generated cash flow. Successes may also encourage the initiation of additional discretionary projects. We have currently secured the necessary equipment and are meeting permit requirements to achieve the 2006 program.
Appraisal, Evaluation and Exploitation Activity. Since 2003, we have been active in assembling significant acreage positions which we believe are highly prospective for finding and developing commercial quantities of hydrocarbons. This chart depicts our prospective acreage by basin, all of which is in the Rocky Mountain and Mid-Continent region:
Rocky Mountain and Mid-Continent
We plan to appraise five project areas in this region in 2006 for an estimated $23 million budgeted. These five projects are Lake Canyon, Coyote Flats, Big Wash Unit, Tri-State Area and the Bakken Play. We have interests in over one million gross acres, including both productive and prospective, in the Rocky Mountain and Mid-Continent region and the acreage in the five appraisal projects accounts for about 80% of that total.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Uinta Basin Projects
Lake Canyon - Shallow: On January 13, 2006, we announced commercial success from our first two wells on this acreage. The Nielsen Marsing and Taylor Herrick wells have tested production rates of 98 and 163 BOE/D, respectively, from the same Green River formation that is productive immediately east (approximately miles) in our Brundage Canyon field. Initial performance from these discovery wells suggests that expected reserves per well are on par with the Brundage Canyon field (approximately 80,000 BOE gross) that is currently being developed on 40-acre spacing. Current production from the Taylor Herrick well is not at full capacity as additional facilities are in the process of being installed. Production from the Nielsen Marsing well is selectively limited to two of five completion intervals within the well and will be further optimized by March when natural gas facilities are completed. We are proceeding with another four wells on the eastern edge of this 169,000 acre block. If the results of these wells are deemed satisfactory, Berry will expand the drilling program and attempt to drill up to another 30 wells over approximately 20,000 acres. The focus will be to begin the methodical appraisal of a sizeable portion of this acreage block. Berry’s working interest in these wells will be either 75% or 56.25% depending on the participation of the land owner. The shallow zones are those above the Wasatch which is at approximately 6,500 feet.
Lake Canyon - Deep: Berry’s industry partner recently reached total depth of 14,325 feet on its Mesaverde test and set casing to a depth of 11,539 feet. Testing will focus on several Upper Price River and shallower Wasatch intervals where analysis indicates gas potential; the deeper Mesaverde and Blackhawk intervals did not warrant further evaluation. Berry will participate with its industry partner to complete the testing and evaluation of the first deep well on the acreage once pipeline construction into the area is completed, which is currently targeted by May 1, 2006. The second well is scheduled to begin drilling in the fourth quarter of 2006.
Coyote Flats: We will continue to test the viability of the Ferron gas development and Emery CBM pilot with additional drilling.
Big Wash Unit: We will test the shallow oil and deeper gas potential located about two miles southeast of Brundage Canyon.
Denver-Julesburg Basin Projects
Tri-State Area: We will be very active in testing the Niobrara gas potential located in the Tri-State area of Colorado, Kansas and Nebraska. We will participate in 16 exploratory gas wells, drill 11 development wells and acquire additional 3D seismic. Immediately to the north of our producing assets in Yuma County, Colorado, we may drill up to 17 wells based on the acquisition of new seismic data covering the northern acreage.
Williston Basin Projects
Bakken Play: In North Dakota, we intend to participate with up to a 15% working interest in at least four horizontal oil wells to appraise the prospective oil formation.
California-Diatomite
In 2005, oil production from the initial 14 well pilot (6 producers) averaged approximately 135 Bbl/D. Based on promising results from the pilot project, we began an expansion of the pilot with a 25 well program (15 producers) in the third quarter of 2005, and completed it in the fourth quarter. We continue to assess the long-term economic and operating viability of the project as the early wells are an indication of future large-scale development. Results are in accordance with expectations. We are judiciously monitoring the steam to oil ratio (SOR) because we believe achieving an SOR of 6 or less is the threshold for commerciality. SOR measures how much steam is required for injection into the reservoir to produce one barrel of oil. Estimated original oil in place ranges between 200 million to 250 million barrels with targets of a minimum 25% recovery of original oil in place. In 2005, we booked 2.5 million BOE of reserves based on asset performance. We believe that the project continues to remain on track towards commerciality.
In 2006, we are expanding the commercial test of our diatomite resource by investing approximately $25 million in a program that will add another 50 wells (31 producers, 16 steam injectors, and 3 service wells). Since completing our expansion of the initial pilot in December 2005, we now have a total of 39 wells (21 producers, 15 steam injectors, and 3 service wells) that we will be using to monitor reservoir performance. In addition to the drilling program, we will add significant facilities including steam generation equipment and will be optimizing the pattern configuration and layout for the eventual full-field development if commerciality is determined.
Development Activity
Rocky Mountain and Mid-Continent
Approximately $93 million will be invested in this region, with $58 million targeting the continued development drilling of the Green River formation at Brundage Canyon to assist full development and will include a 20-acre spacing pilot. In northeastern Colorado, $17 million will be invested to acquire additional seismic data and drill 150 wells to further develop the Niobrara natural gas production from our producing assets.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
California
Berry will invest $37 million in its heavy oil properties, utilizing horizontal well and new steam-optimization technologies to maximize recovery from our legacy assets. Development activity at our Poso Creek, Ethel D and Midway-Sunset assets will utilize improved application of steam flood technology to provide production growth.
See Item 1 Business for more information on Development Activity.
Obstacles and Risks to Accomplishment of Strategies and Goals. See Item 1A
Item 7A Quantitative and Qualitative Disclosures about Market Risk and Note 15 to the financial statements.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Credit Facility. See Note 6 to the financial statements for more information. We have a $500 million unsecured credit facility, which has a current borrowing base of $350 million and is an integral part of our financing structure that provides improved access to capital and the flexibility to support growth plans.
Contractual Obligations. Refer to Note 10 to the financial statements.
Application of Critical Accounting Policies. The preparation of financial statements in conformity with generally accepted accounting principles requires Management to make estimates and assumptions for the reporting period and as of the financial statement date. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent liabilities and the reported amounts of revenues and expenses. Actual results could differ from those amounts.
A critical accounting policy is one that is important to the portrayal of the Company's financial condition and results, and requires Management to make difficult subjective and/or complex judgments. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. The Company believes the following accounting policies are critical policies.
Successful Efforts Method of Accounting. The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion. Exploratory wells that discover potentially economic reserves that are in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized as long as the additional exploratory work is under way or firmly planned.
Oil and Gas Reserves. Oil and gas reserves include proved reserves that represent estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The Company's oil and gas reserves are based on estimates prepared by independent engineering consultants. Reserve engineering is a subjective process that requires judgment in the evaluation of all available geological, geophysical, engineering and economic data. Projected future production rates, the timing of future capital expenditures as well as changes in commodity prices may significantly impact estimated reserve quantities. Depreciation, depletion and amortization (DD&A) expense and impairment of proved properties are impacted by the Company's estimation of proved reserves. These estimates are subject to change as additional information and technologies become available. Accordingly, oil and natural gas quantities ultimately recovered and the timing of production may be substantially different than projected. Reduction in reserve estimates may result in increased DD&A expense, increased impairment of proved properties and a lower standardized measure of discounted future net cash flows.
Carrying Value of Long-lived Assets. Downward revisions in the Company’s estimated reserve quantities, increases in future cost estimates or depressed crude oil or natural gas prices could cause the Company to reduce the carrying amounts of its properties. The Company performs an impairment analysis of its proved properties annually by comparing the future undiscounted net revenue per the annual reserve valuation prepared by the Company’s independent reserve engineers to the net book carrying value of the assets. An analysis of the proved properties will also be performed whenever events or changes in circumstances indicate an asset’s carrying value may not be recoverable from future net revenue. Assets are grouped at the field level and if it is determined that the net book carrying value cannot be recovered by the estimated future undiscounted cash flow, they are written down to fair value. Cash flows used in the impairment analysis are determined based on Management’s estimates of crude oil and natural gas reserves, future crude oil and natural gas prices in effect at the end of the period and costs to extract these reserves. For its unproved properties, the Company performs an impairment analysis annually or whenever events or changes in circumstances indicate an asset’s net book carrying value may not be recoverable.
Derivatives and Hedging. The Company follows the provisions of Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS 133 requires the accounting recognition of all derivative instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income. Under the provisions of SFAS 133, the Company may designate a derivative instrument as hedging the exposure to change in fair value of an asset or liability that is attributable to a particular risk (a fair value hedge) or as hedging the exposure to variability in expected future cash flows that are attributable to a particular risk (a cash flow hedge). Both at the inception of a hedge and on an ongoing basis, a fair value hedge must be expected to be highly effective in achieving offsetting changes in fair value attributable to the hedged risk during the periods that a hedge is designated. Similarly, a cash flow hedge must be expected to be highly effective in achieving offsetting cash flows attributable to the hedged risk during the term of the hedge. The expectation of hedge effectiveness must be supported by matching the essential terms of the hedged asset, liability or forecasted transaction to the
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
derivative contract or by effectiveness assessments using statistical measurements. The Company's policy is to assess hedge effectiveness at the end of each calendar quarter.
Income Taxes. The Company computes income taxes in accordance with SFAS No. 109, Accounting for Income Taxes. SFAS No. 109 requires an asset and liability approach which results in the recognition of deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the Company's financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Additionally, the Company's federal and state income tax returns are generally not filed before the financial statements are prepared, therefore the Company estimates the tax basis of its assets and liabilities at the end of each calendar year as well as the effects of tax rate changes, tax credits, and tax credit carryforwards. A valuation allowance is recognized if it is determined that deferred tax assets may not be fully utilized in future periods. Adjustments related to differences between the estimates used and actual amounts reported are recorded in the period in which income tax returns are filed. These adjustments and changes in estimates of asset recovery could have an impact on results of operations. The Company may generate enhanced oil recovery tax credits from the production of its heavy crude oil in California which results in a deferred tax asset and believes that these credits will be fully utilized in future years and consequently has not recorded any valuation allowance related to these credits. Due to uncertainties involved with tax matters, the future effective tax rate may vary significantly from the estimated current year effective tax rate.
Asset Retirement Obligations. The Company has significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and gas production operations. The computation of the Company's asset retirement obligations (ARO) was prepared in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations, which requires the Company to record the fair value of liabilities for retirement obligations of long-lived assets. The adoption of SFAS No. 143 in 2002 resulted in an immaterial difference in the liability that had been previously recorded by the Company. Estimating the future ARO requires Management to make estimates and judgments regarding timing, current estimates of plugging and abandonment costs, as well as what constitutes adequate remediation. The Company obtained estimates from third parties and used the present value of estimated cash flows related to its ARO to determine the fair value. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. Changes in any of these assumptions can result in significant revisions to the estimated ARO. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment will be made to the related asset. Due to the subjectivity of assumptions and the relatively long life of the Company's assets, the costs to ultimately retire the Company's wells may vary significantly from previous estimates.
Environmental Remediation Liability. The Company reviews, on a quarterly basis, its estimates of costs of the cleanup of various sites including sites in which governmental agencies have designated the Company as a potentially responsible party. In accordance with SFAS No. 5, Accounting for Contingencies, when it is probable that obligations have been incurred and where a minimum cost or a reasonable estimate of the cost of remediation can be determined, the applicable amount is accrued. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is an estimation process that includes the subjective judgment of Management. In many cases, Management's judgment is based on the advice and opinions of legal counsel and other advisers, the interpretation of laws and regulations, which can be interpreted differently by regulators or courts of law, the experience of the Company and other companies in dealing with similar matters and the decision of Management on how it intends to respond to a particular matter. A change in estimate could impact the Company's oil and gas operating costs and the liability, if applicable, recorded on the Company's balance sheet.
Accounting for Business Combinations. The Company has grown substantially through acquisitions and our business strategy is to continue to pursue acquisitions as opportunities arise. We have accounted for all of our business combinations using the purchase method, which is the only method permitted under SFAS 141. The accounting for business combinations is complicated and involves the use of significant judgment. Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, stock or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets.
Determining the fair values of the assets and liabilities acquired involves the use of judgment, since some of the assets and liabilities acquired do not have fair values that are readily determinable. Different techniques may be used to determine fair values, including market prices, where available, appraisals, comparisons to transactions for similar assets and liabilities and present value of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Each of the business combinations completed were of interests in oil and gas assets. We believe the consideration we paid to acquire these assets represents the fair value of the assets and liabilities acquired at the time of acquisition. Consequently, we have not recognized any goodwill from any of our business combinations, nor do we expect to recognize any goodwill from similar business combinations that we may complete in the future.
Stock-Based Compensation. Effective January 1, 2004, the Company voluntarily adopted the fair value method of accounting for its stock option plan as prescribed by SFAS 123, Accounting for Stock-Based Compensation. The modified prospective method was selected as described in SFAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure. Under this method, the Company recognizes stock option compensation expense as if it had applied the fair value method to account for unvested stock options from its original effective date. Stock option compensation expense is recognized from the date of grant to the vesting date. The fair value of each option award is estimated on the date of grant using the Black-Scholes option pricing model that uses the following assumptions. Expected volatilities are based on the historical volatility of the Company's stock. The Company uses historical data to estimate option exercises and employee terminations within the valuation model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of options granted is based on historical exercise behavior and represents the period of time that options granted are expected to be outstanding; the range results from certain groups of employees exhibiting different exercise behavior. The risk free rate for periods within the contractual life of the option is based on U.S. Treasury rates in effect at the time of grant.
Electricity Cost Allocation. The Company’s investment in its cogeneration facilities has been for the express purpose of lowering steam costs in its California heavy oil operations and securing operating control of the respective steam generation. Such cogeneration operations produce electricity and steam and use natural gas as fuel. The Company allocates steam costs to its oil and gas operating costs based on the conversion efficiency (of fuel to electricity and steam) of the cogeneration facilities plus certain direct costs in producing steam. Electricity revenue represents sales to the utilities. Electricity used in oil and gas operations is allocated at cost. A portion of the DD&A expenses associated with capital is allocated to DD&A - oil and gas production.
Recent Accounting Pronouncements. In December 2004, SFAS No. 123(R), Share-Based Payment, was issued which establishes standards for transactions in which an entity exchanges its equity instruments for goods or services. This standard requires an issuer to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. This eliminates the exception to account for such awards using the intrinsic method previously allowable under Accounting Principles Board (APB) Opinion No. 25. In April 2005 the SEC issued a rule that SFAS No. 123(R) will be effective for annual reporting periods beginning on or after June 15, 2005. As a result, the Company expects to adopt this statement on January 1, 2006. The Company previously adopted the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation. Accordingly the Company believes SFAS No. 123(R) will not have a material impact on its financial statements; however, it continues to assess the potential impact that the adoption of SFAS No. 123(R) will have on the classification of tax deductions for stock-based compensation in the statements of cash flows.
In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”). FIN 47 clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, Accounting for Asset Retirement Obligations. A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. FIN 47 is intended to provide more information about long-lived assets and future cash outflows for these obligations and more consistent recognition of these liabilities and is effective for the fiscal year end December 31, 2005. The adoption of FIN 47 by the Company did not have an immediate affect on the financial statements.
On April 4, 2005 the FASB adopted FASB Staff Position (FSP) FSP 19-1 Accounting for Suspended Well Costs that amends SFAS 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, to permit the continued capitalization of exploratory well costs beyond one year if the well found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. In accordance with the guidance in the FSP, the Company applied the requirements prospectively in its second quarter of 2005. The adoption of FSP 19-1 by the Company did not have an immediate effect on the financial statements. However, it could impact the timing of the recognition of expenses for exploratory well costs in future periods.
In May 2005, SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3 was issued. SFAS No. 154 requires retrospective application to prior period financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS No. 154 will become effective for the Company’s fiscal year beginning January 1, 2006. The impact of SFAS No. 154 will depend on
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
the nature and extent of any voluntary accounting changes and correction of errors after the effective date.
In February 2006, SFAS No. 155, Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140 was issued. This Statement resolves issues addressed in Statement 133 Implementation Issue No. D1, Application of Statement 133 to Beneficial Interests in Securitized Financial Assets. SFAS No. 155 will become effective for the Company’s fiscal year after September 15, 2006. The impact of SFAS No. 155 will depend on the nature and extent of any new derivative instruments entered into after the effective date.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
As discussed in Note 15 to the financial statements, to minimize the effect of a downturn in oil and gas prices and protect the profitability of the Company and the economics of the Company’s development plans, from time to time the Company enters into crude oil and natural gas hedge contracts. The terms of contracts depend on various factors, including Management’s view of future crude oil and natural gas prices and the Company’s future financial commitments. This price hedging program is designed to moderate the effects of a severe crude oil and natural gas price downturn while allowing Berry to participate in the upside. In California, Berry benefits from lower natural gas pricing and elsewhere, Berry benefits from higher natural gas pricing. The Company has, and may hedge both natural gas purchases and sales as determined appropriate by Management. Management regularly monitors the crude oil and natural gas markets and the Company’s financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging or other price protection is appropriate in accordance with Board established policy.
Currently, the Company’s hedges are in the form of swaps and collars. However, the Company may use a variety of hedge instruments in the future to hedge WTI or the index gas price. The Company has crude oil sales contracts in place, which are priced based on a correlation to WTI. Natural gas (for cogeneration and conventional steaming operations) is purchased at the SoCal border price and the Company sells its produced gas in Colorado and Utah at the Colorado Interstate Gas (CIG) and Questar index prices, respectively.
The following table summarizes the hedge position of the Company as of December 31, 2005:
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
On March 1, 2006, the Company entered into the following derivative instruments:
Payments to the Company's counterparties are triggered when the monthly average prices are above the swap price in the case of the Company's crude oil and natural gas sales hedges and below the swap price for the Company's natural gas purchase hedge positions. Conversely, payments from our counterparties are received when the monthly average prices are below the swap price for the Company's crude oil and natural gas sales hedges and above the swap price for the Company's natural gas purchase hedge positions.
The collar strike prices will allow the Company to protect a significant portion of its future cash flow if 1) oil prices decline below $47.50 per barrel while still participating in any oil price increase up to $70 per barrel on these volumes and 2) if gas prices decline below approximately $8 per MMBtu. These hedges improve the Company’s financial flexibility by locking in significant revenues and cash flow upon a substantial decline in crude oil or natural gas prices. It also allows the Company to develop its long-lived assets and pursue exploitation opportunities with greater confidence in the projected economic outcomes and allows the Company to borrow a higher amount under the credit facility.
While the Company has designated its hedges as cash flow hedges in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, it is possible that a portion of the hedge related to the movement in the WTI to California heavy crude oil price differential may be determined to be ineffective. Likewise, the Company may have some ineffectiveness in its natural gas hedges put into place on March 1, 2006, due to the movement of HH pricing as compared to actual sales points. If this occurs, the ineffective portion will directly impact net income rather than being reported as Other Comprehensive Income. While Management believes that the differential will narrow and move closer toward its historical level over time, there are no assurances as to the movement in the differential. If the differential were to change significantly, it is possible that the Company’s hedges, when marked-to-market, could have a material impact on earnings in any given quarter and, thus, add increased volatility to the Company’s net income. The marked-to-market values reflect the liquidation values of such hedges and not necessarily the values of the hedges if they are held to maturity. Irrespective of the unrealized gains reflected in Other Comprehensive Income, the ultimate impact to net income over the life of the hedges will reflect the actual settlement values. All of these hedges have historically been deemed to be cash flow hedges with the marked-to-market valuations provided by external sources, based on prices that are actually quoted.
At December 31, 2005, Accumulated Other Comprehensive Loss, net of income taxes, consisted of $24.4 million of unrealized losses from the Company's crude oil and natural gas hedges. Deferred net losses recorded in Accumulated Other Comprehensive Loss at December 31, 2005 are expected to be reclassified to earnings through 2006 for the Company’s swaps and at current prices the Company’s collars are not expected to impact earnings.
The use of hedging transactions may involve basis risk. The Company's oil hedges are based on reported settlement prices on the NYMEX. The basis risk between NYMEX and the Company's California heavy crude oil is mitigated by the Company's crude oil
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
sales contracts. On November 21, 2005, the Company entered into a new crude oil sales contract for its California production for deliveries beginning February 1, 2006. The per barrel price, calculated on a monthly basis and blended across the various producing locations, is the higher of 1) the WTI NYMEX crude oil price less a fixed differential approximating $8.15, or 2) heavy oil field postings plus a premium of approximately $1.35. The initial term of the contract is for four years with a one-year renewal at the Company’s option. The Company has redesignated its existing crude oil collars as cash flow hedges related to California crude oil production, and there was no related effect to Other Comprehensive Income with regard to this redesignation.
Pricing in the existing crude oil sales agreement at Brundage Canyon is based upon average weekly WTI minus a fixed differential of approximately $2 per barrel through September 30, 2006. Any new contract will be negotiated based on market prices. Upon the expiration of these crude oil contracts, and absent any new contracts, the Company will be exposed to fluctuations in the basis differentials between WTI and the posted price for its crude oil at its various producing locations until new contracts which lock in such differential can be obtained.
The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. With respect to the Company’s hedging activities, the Company utilizes multiple counterparties on its hedges and monitors each counterparty’s credit rating. The Company also attempts to minimize credit exposure to counterparties through diversification.
Based on NYMEX futures prices as of December 31, 2005, (WTI $62.71; HH $10.83) and due to the backwardated nature of the futures prices as of that date, the Company would expect to make pre-tax future cash payments or to receive payments over the remaining term of its crude oil and natural gas hedges in place as follows:
Interest Rates. The Company’s exposure to changes in interest rates results primarily from long-term debt. Total long-term debt outstanding at December 31, 2005 and 2004 was $75 million and $28 million, respectively. Interest on amounts borrowed is charged at LIBOR plus 1.0% to 1.75%. Based on year-end 2005 borrowings, a 1% change in interest rates would not have a material impact on the Company’s financial statements.
Item 8.
Item 8. Financial Statements and Supplementary Data
Financial statement schedules have been omitted since they are either not required, are not applicable, or the required information is shown in the financial statements and related notes.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Berry Petroleum Company:
We have completed integrated audits of Berry Petroleum Company’s December 31, 2005 and 2004 financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its December 31, 2003 financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Financial statements
In our opinion, the financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Berry Petroleum Company at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Los Angeles, California
March 1,
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Balance Sheets
December 31, 2005 and 2004
(In Thousands, Except Share Information)
The accompanying notes are an integral part of these financial statements.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Statements of Income
Years ended December 31, 2005, 2004 and 2003
(In Thousands, Except Per Share Data)
The accompanying notes are an integral part of these financial statements.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Statements of Shareholders’ Equity
Years Ended December 31, 2005, 2004 and 2003
(In Thousands, Except Per Share Data)
The accompanying notes are an integral part of these financial statements.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Statements of Cash Flows
Years Ended December 31, 2005, 2004 and 2003
(In Thousands)
The accompanying notes are an integral part of these financial statements.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
1. General
The Company is an independent energy company engaged in the production, development, acquisition, exploitation and exploration of crude oil and natural gas. The Company has 74% of its oil and gas reserves in California and 26% in the Rocky Mountain and Mid-Continent region. Approximately 70% of the Company's production is in California, most of which is heavy crude oil and is sold to a Bakersfield, California refinery. The Company has invested in cogeneration facilities which provide steam required for the extraction of heavy oil and which generates electricity for sale. Production of light crude oil and natural gas in the Rocky Mountain and Mid-Continent region accounts for approximately 30% of the Company’s production.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
2. Summary of Significant Accounting Policies
Cash and cash equivalents - The Company considers all highly liquid investments purchased with a remaining maturity of three months or less to be cash equivalents. The Company’s cash management process provides for the daily funding of checks as they are presented to the bank. Included in accounts payable at December 31, 2005 is $1.9 million representing outstanding checks in excess of the bank balance (book overdraft).
Short-term investments - All short-term investments are classified as available for sale. Short-term investments consist principally of United States treasury notes and corporate notes with remaining maturities of more than three months at date of acquisition and are carried at fair value. The Company utilizes specific identification in computing realized gains and losses on investments sold.
Accounts receivable - Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company does not have any off-balance-sheet credit exposure related to its customers. The Company assesses credit risk and allowance for doubtful accounts on a customer specific basis. As of December 31, 2005 and 2004, the Company does not have an allowance for doubtful accounts.
Income taxes - Income taxes are provided based on the liability method of accounting. The provision for income taxes is based on reported pre-tax financial statement income. Deferred tax assets and liabilities are recognized for the future expected tax consequences of temporary differences between income tax and financial reporting, and principally relate to differences in the tax bases of assets and liabilities and their reported amounts using enacted tax rates in effect for the year in which differences are expected to reverse. If it is more likely than not that some portion or all of a deferred tax asset will not be realized, a valuation allowance is recognized.
Hedging - SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, requires that all derivative instruments subject to the requirements of the statement be measured at fair value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS No. 133, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. The hedging relationship between the hedging instruments and hedged items, such as oil and gas, must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk, both at the inception of the hedge and on an ongoing basis. The Company measures hedge effectiveness at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time, or in the case of options based on the change in intrinsic value. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss, such as time value for option contracts, is recognized immediately in the statements of income. Gains and losses on hedging instruments and adjustments of the carrying amounts of hedged items are included in revenues for hedges related to the Company's crude oil and natural gas sales and in operating expenses for hedges related to the Company's natural gas consumption. The resulting cash flows are reported as cash flows from operating activities. See Note 15 - Hedging.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
2. Summary of Significant Accounting Policies (Cont'd)
Oil and gas properties, buildings and equipment - The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves that are in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized if the well found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The costs of development wells are capitalized whether productive or nonproductive.
Depletion of oil and gas producing properties is computed using the units-of-production method. Depreciation of lease and well equipment, including cogeneration facilities and other steam generation equipment and facilities, is computed using the units-of-production method or on a straight-line basis over estimated useful lives ranging from 10 to 20 years. Buildings and equipment are recorded at cost. Depreciation is provided on a straight-line basis over estimated useful lives ranging from 5 to 30 years for buildings and improvements and 3 to years for machinery and equipment. Estimated residual salvage value is considered when determining depreciation, depletion and amortization (DD&A) rates.
Assets are grouped at the field level and if it is determined that the book value of long-lived assets cannot be recovered by estimated future undiscounted cash flows, they are written down to fair value. When assets are sold, the applicable costs and accumulated depreciation and depletion are removed from the accounts and any gain or loss is included in income. Expenditures for maintenance and repairs are expensed as incurred.
Asset retirement obligations - The Company has significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and gas production operations. The computation of the Company's asset retirement obligations (ARO) is prepared in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations. Under this standard, the Company records the fair value of the future abandonment as capitalized abandonment costs in Oil and Gas Properties with an offsetting abandonment liability. The Company obtains estimates from third parties and uses the present value of estimated cash flows related to its ARO to determine the fair value. The capitalized abandonment costs are amortized with other property costs using the units-of-production method. The Company increases the liability monthly by recording accretion expense using the Company’s credit adjusted interest rate. Accretion expense is included in DD&A in the Company’s financial statements.
Revenue recognition - Revenues associated with sales of crude oil, natural gas, and electricity are recognized when title passes to the customer, net of royalties, discounts and allowances, as applicable. Electricity and natural gas produced by the Company and used in the Company’s operations are not included in revenues. Revenues from crude oil and natural gas production from properties in which the Company has an interest with other producers are recognized on the basis of the Company's net working interest (entitlement method).
Conventional steam costs - The costs of producing conventional steam are included in “Operating costs - oil and gas production.”
Cogeneration operations - The Company’s investment in its cogeneration facilities has been for the express purpose of lowering steam costs in its heavy oil operations and securing operating control of the respective steam generation. Such cogeneration operations produce electricity and steam. The Company allocates steam costs to its oil and gas operating costs based on the conversion efficiency of the cogeneration facilities plus certain direct costs in producing steam. Electricity revenue represents sales to the utilities. Electricity used in oil and gas operations is allocated at cost. Electricity consumption included in oil and gas operating costs for the years ended December 31, 2005, 2004 and 2003 was $5.7 million, $5 million and $4.2 million, respectively.
Shipping and handling costs - Shipping and handling costs, which consist primarily of natural gas transportation costs, are included in both "Operating costs - oil and gas production" or "Operating costs - electricity generation,” as applicable. Natural gas transportation costs included in these categories were $5.8 million, $5.4 million and $4 million, for 2005, 2004 and 2003, respectively.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
2. Summary of Significant Accounting Policies (Cont'd)
Production taxes - Consist primarily of severance and ad valorem taxes.
Stock-based compensation - Effective January 1, 2004, the Company voluntarily adopted the fair value method of accounting for its stock option plan as prescribed by SFAS 123, Accounting for Stock-Based Compensation. The modified prospective method was selected as described in SFAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure. Under this method, the Company recognizes stock option compensation expense as if it had applied the fair value method to account for unvested stock options from its original effective date. Stock option compensation expense is recognized from the date of grant to the vesting date.
From January 1, 2004 to July 29, 2004 a portion of the Company's stock option compensation was calculated under variable accounting; however, the majority of stock option compensation was accounted for under the fair value method. In accordance with variable plan accounting, the Company recognized a corresponding liability determined by a marked-to-market valuation of the Company's stock at each financial reporting date. The Company revised certain stock option exercise provisions of the plan and, subsequent to July 29, 2004, variable plan accounting was no longer required.
Had compensation cost for the Company’s stock-based compensation plan (see Note 12) been based upon the fair value at the grant dates for awards under the plan consistent with SFAS No. 123, the Company’s compensation cost, net of related tax effects, net income and earnings per share would have been recorded as the pro forma amounts indicated below (in thousands, except per share data):
Under SFAS No. 123, compensation cost would be recognized for the fair value of the employee's option rights. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions:
Comprehensive income (loss) - Comprehensive income (loss) includes net earnings (loss) as well as unrealized gains and losses on derivative instruments, recorded net of tax.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
2. Summary of Significant Accounting Policies (Cont'd)
Net income per share - Basic net income per share is computed by dividing income available to shareholders (the numerator) by the weighted average number of shares of capital stock outstanding (the denominator). The Company’s Class B Stock is included in the denominator of basic and diluted net income. The computation of diluted net income per share is similar to the computation of basic net income per share except that the denominator is increased to include the dilutive effect of the additional common shares that would have been outstanding if all convertible securities had been converted to common shares during the period.
Environmental expenditures - The Company reviews, on a quarterly basis, its estimates of costs of the cleanup of various sites, including sites in which governmental agencies have designated the Company as a potentially responsible party. When it is probable that obligations have been incurred and where a minimum cost or a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments. Any liabilities arising hereunder are not discounted.
Accounting for business combinations - The Company has accounted for all of its business combinations using the purchase method, which is the only method permitted under SFAS 141, Accounting for Business Combinations. Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, stock or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets. The Company has not recognized any goodwill from any business combinations.
Recent accounting developments - In December 2004, SFAS No. 123(R), Share-Based Payment, was issued which establishes standards for transactions in which an entity exchanges its equity instruments for goods or services. This standard requires an issuer to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. This eliminates the exception to account for such awards using the intrinsic method previously allowable under Accounting Principles Board (APB) Opinion No. 25. In April 2005 the SEC issued a rule that SFAS No. 123(R) will be effective for annual reporting periods beginning on or after June 15, 2005. As a result, the Company expects to adopt this statement on January 1, 2006. The Company previously adopted the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation. Accordingly the Company believes SFAS No. 123(R) will not have a material impact on its financial statements; however, it continues to assess the potential impact that the adoption of SFAS No. 123(R) will have on the classification of tax deductions for stock-based compensation in the statements of cash flows.
In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”). FIN 47 clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, Accounting for Asset Retirement Obligations. A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. FIN 47 is intended to provide more information about long-lived assets and future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for the fiscal year end December 31, 2005. The adoption of FIN 47 by the Company did not have an impact on the financial statements.
On April 4, 2005 the FASB adopted FASB Staff Position (FSP) FSP 19-1 Accounting for Suspended Well Costs that amends SFAS 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, to permit the continued capitalization of exploratory well costs beyond one year if the well found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. In accordance with the guidance in the FSP, the Company applied the requirements prospectively in its second quarter of fiscal 2005. The adoption of FSP 19-1 by the Company did not have an effect on the financial statements. However, it could impact the timing of the recognition of expenses for exploratory well costs in future periods.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
2. Summary of Significant Accounting Policies (Cont'd)
In May 2005, SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3 was issued. SFAS No. 154 requires retrospective application to prior period financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS No. 154 will become effective for the Company’s fiscal year beginning January 1, 2006. The impact of SFAS No. 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date.
In February 2006, SFAS No. 155, Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140 was issued. This Statement resolves issues addressed in Statement 133 Implementation Issue No. D1, Application of Statement 133 to Beneficial Interests in Securitized Financial Assets. SFAS No. 155 will become effective for the Company’s fiscal year after September 15, 2006. The impact of SFAS No. 155 will depend on the nature and extent of any new derivative instruments entered into after the effective date.
Revisions to the classification of technical labor costs and production taxes - In connection with the preparation of the 2005 financial statements the Company is reclassifying technical labor between general and administrative expenses and operating costs-oil and gas and reclassifying production taxes out of operating costs-oil and gas into a separate line. These reclassifications had no impact on net income or net cash provided by operating activities and did not effect previously reported total revenues, total operating expenses, net income or net cash provided by operating activities. Accordingly, the Company has revised prior classifications for the year ended December 31, 2004 as follows (in thousands):
3. Fair Value of Financial Instruments
Cash equivalents consist principally of commercial paper investments. Cash equivalents of $2 million and $16.7 million at December 31, 2005 and 2004, respectively, are stated at cost, which approximates market.
The Company’s short-term investments available for sale at December 31, 2005 and 2004 consist of United States treasury notes that mature in less than one year and are carried at fair value. For the three years ended December 31, 2005, realized and unrealized gains and losses were insignificant to the financial statements. A United States treasury note with a market value of $.7 million is pledged as collateral to the California State Lands Commission as a performance bond on the Company’s Montalvo properties. The carrying value of the Company’s long-term debt approximates its fair value since the interest rate is variable.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
4. Concentration of Credit Risks
The Company sells oil, gas and natural gas liquids to pipelines, refineries and oil companies and electricity to utility companies. Credit is extended based on an evaluation of the customer’s financial condition and historical payment record.
Because of the Company’s ability to deliver significant volumes of crude oil over a multi-year period, the Company secured a thirty-nine month sales agreement, beginning in late 2002, with a major California refiner whereby the Company sold over 90% of its California production under a negotiated pricing mechanism. This contract ended on January 31, 2006. Pricing in this agreement was based upon the higher of the average of the local field posted prices plus a fixed premium, or WTI minus a fixed differential near $6.00 per barrel. Both methods were calculated using a monthly determination. In addition to providing a premium above field postings, the agreement effectively eliminated the Company’s exposure to the risk of widening WTI to California heavy crude price differentials and allowed the Company to effectively hedge its production based on WTI pricing.
On November 21, 2005, the Company entered into a new crude oil sales contract for its California production for deliveries beginning February 1, 2006. The per barrel price, calculated on a monthly basis and blended across the various producing locations, is the higher of 1) the WTI NYMEX crude oil price less a fixed differential approximating $8.15, or 2) heavy oil field postings plus a premium of approximately $1.35. The initial term of the contract is for four years with a one-year renewal at the Company’s option.
For the three years ended December 31, 2005, the Company has experienced no credit losses on the sale of oil, gas and natural gas liquids.
The Company places its temporary cash investments with high quality financial institutions and limits the amount of credit exposure to any one financial institution. For the three years ended December 31, 2005, the Company has not incurred losses related to these investments. With respect to the Company’s hedging activities, the Company utilizes more than one counterparty on its hedges and monitors each counterparty’s credit rating.
The following summarizes the accounts receivable balances at December 31, 2005 and 2004 and sales activity with significant customers for each of the years ended December 31, 2005, 2004 and 2003 (in thousands). The Company does not believe that the loss of any one customer would impact the marketability of its California crude oil, gas, natural gas liquids or electricity sold. Due to the possibility of refinery constraints in the Utah region, it is possible that the loss of the current crude oil sales customer could impact the marketability of a portion of the Company’s Utah crude oil volumes. The Company is investigating its market opportunities for this Utah crude oil.
Sales amounts will not agree to the Statements of Income due primarily to the effects of hedging and price sensitive royalties paid on a portion of the Company’s crude oil sales, which are netted in “Sales of oil and gas” on the Statements of Income.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
5. Oil and Gas Properties, Buildings and Equipment
Oil and gas properties, buildings and equipment consist of the following at December (in thousands):
The following sets forth costs incurred for oil and gas property acquisition, development and exploration activities, whether capitalized or expensed (in thousands):
(1) Costs incurred for proved and unproved property acquisitions in 2005 include the reclassification of 2004 deposits of $5,505 and $4,716, respectively..
(2) Development costs include $.6 million, $.7 million and $.9 million that were charged to expense during 2005, 2004 and 2003, respectively.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
5. Oil and Gas Properties, Buildings and Equipment (Cont'd)
In 2005, the Tri-State area is comprised of the following three acquisitions totaling approximately 315,000 net acres:
·
Niobrara gas producing assets in Yuma County in northeastern Colorado in which the Company has approximately 52% working interest were purchased for approximately $105 million.
·
Eastern Colorado, western Kansas and southwestern Nebraska assets in which the Company has approximately 50% working interest were purchased for approximately $5 million.
·
Colorado’s Phillips and Sedgwick Counties in which the Company has approximately 50% working interest were purchased for approximately $.9 million. This Niobrara leasehold position is adjacent to and immediately north of Berry’s producing natural gas assets in Yuma County.
In 2005, the Company completed several transactions whereby it now has working interests in 186,000 gross acres (46,000 net) located in the Williston Basin in North Dakota. These lease acquisitions, totaling approximately $11 million, cover several contiguous blocks located primarily on the eastern flank of the Nesson Anticline.
In July 2004, the Company purchased approximately 169,000 gross acres with an industry partner in the Lake Canyon prospect in Utah, of which 124,500 gross (62,250 net) acres are leased from the Ute Tribe and 44,500 gross (22,250 net) acres are fee lands. Total cost to Berry was approximately $2 million. The Company will drill and operate shallow wells which target light oil in the Green River formation and retain a 75% working interest. The Company’s partner will drill and operate deeper wells and the Company will retain a 25% working interest. The Ute Tribe has the option to participate in all wells and retain up to a 25% working interest. As of December 31, 2005, the Company's minimum obligation under its agreement is $9.6 million through 2009.
In 2003, the Company purchased leases totaling 45,380 acres in the Brundage Canyon field in Utah for approximately $45 million and the McVan property totaling 560 acres in the Poso Creek field in Kern County, California for approximately $2.6 million. The Company capitalized approximately $2.6 million in future abandonment obligations related to the 2003 acquisitions.
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of wells for which exploratory well costs have been capitalized for a period of greater than one year since the completion of drilling (in thousands, except number of projects):
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
5. Oil and Gas Properties, Buildings and Equipment (Cont'd)
The following table reflects the net changes in capitalized exploratory well costs during the years ended 2005, 2004 and 2003 (in thousands):
In 2004, included in the amount of exploratory well costs that have been capitalized for a period of greater than one year since completion of drilling are costs of $.5 million that have been capitalized since 2003. These costs are related to the Company's diatomite project in the Midway-Sunset field and have been reclassified from exploratory well costs in 2005.
Dry hole, abandonment and impairment.
The $5.7 million reflected on the Company’s income statement under dry hole, abandonment and impairment is made up of the following three items:
·
At December 31, 2004, the Company was in the process of drilling one exploratory well on its Midway-Sunset property and one exploratory well on its Coyote Flats prospect. These two wells were determined non-commercial in February 2005 and $2.2 million was incurred and expensed in 2005.
·
Two exploratory wells at northern Brundage Canyon were expensed for $.6 million.
·
Finally, the Company impaired the remaining carrying value of its Illinois and eastern Kansas prospective CBM acreage acquired in 2002 by $2.9 million.
Costs of $.7 million which were incurred on the Midway-Sunset property and the exploratory well on the Coyote Flats prospect as of December 31, 2004 were charged to expense. During 2003, the Company recorded a pre-tax write down of $4.2 million related to two CBM pilot projects.
6. Long-term and Short-term Debt Obligations
Long-term debt
In June 2005, the Company completed a new unsecured five year bank credit agreement (the Agreement) with a banking syndicate. The Agreement is a revolving credit facility for up to $500 million with nine banks and replaces the previous $200 million facility which was due to mature in 2006. Initial borrowings were $125 million which represented an amount equal to the borrowings outstanding under the previous credit facility and the initial borrowing base was established as $350 million. This transaction is considered a modification of a debt instrument due to modification of terms in accordance with Emerging Issues Task Force, (EITF) 98-14, Debtor’s Accounting forChanges in Line of Credit or Revolving Debt Arrangements.
The credit available under the Agreement is $264 million at December 31, 2005 without any increase to the borrowing base. The maximum amount available is subject to an annual redetermination of the borrowing base in accordance with the lender's customary procedures and practices. Both the Company and the banks have bilateral rights to one additional redetermination each year.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
6. Long-term and Short-term Debt Obligations (Cont’d)
The Agreement matures on July 1, 2010. Interest on amounts borrowed is charged at LIBOR plus a margin of 1.00% to 1.75%, or the higher of the lead bank’s prime rate or the federal funds rate plus .50% plus a margin of 0% to .50% at the Company’s option, with margins on the various rate options based on the ratio of credit outstanding to the borrowing base. The Company is required under the Agreement to pay an annual commitment fee of .25% to .38% on the unused portion of the credit facility.
The weighted average interest rate on outstanding borrowings at December 31, and 2004 was 4.9% and 3.37%, respectively. The Agreement contains restrictive covenants which, among other things, require the Company to maintain a certain debt to EBITDA ratio and a minimum current ratio, as defined. The Company was in compliance with all such covenants as of December 31, 2005.
Short-term debt
In November 2005, the Company completed a new unsecured uncommitted money market line of credit (Line of Credit). Borrowings under the Line of Credit may be up to $30 million for a maximum of 30 days. The Line of Credit may be terminated at any time upon written notice by either the Company or the lender. At December 31, 2005 the outstanding balance under this Line of Credit was $11.5 million. Interest on amounts borrowed is charged at LIBOR plus a margin of approximately 1%. The weighted average interest rate on outstanding borrowings at December 31, 2005 was 5.4%.
7. Shareholders’ Equity
Shares of Class A Common Stock (Common Stock) and Class B Stock, referred to collectively as the "Capital Stock," are each entitled to one vote and 95% of one vote, respectively. Each share of Class B Stock is entitled to a $1.00 per share preference in the event of liquidation or dissolution. Further, each share of Class B Stock is convertible into one share of Common Stock at the option of the holder.
The Company's Capital Stock activity follows (in number of shares):
In June 2005, the Company announced that its Board of Directors authorized a share repurchase program for up to an aggregate of $50 million of the Company's outstanding Class A Common Stock. Through December 31, 2005, the Company repurchased 108,900 shares for approximately $6.3 million.
In December 2005, the Company adopted a plan under Rule 10b5-1 of the Securities Exchange Act of 1934 to facilitate the repurchase of its shares of common stock. Rule 10b5-1 allows a company to purchase its shares at times when it would not normally be in the market due to possession of nonpublic information, such as the time immediately preceding its quarterly earnings releases. This 10b5-1 plan is authorized under, and is administered consistent with, the Company's $50 million share repurchase program. All repurchases of common stock are made in compliance with regulations set forth by the SEC and are subject to market conditions, applicable legal requirements and other factors.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
7. Shareholders’ Equity (Cont'd)
This program does not obligate the Company to acquire any particular amount of common stock and the plan may be suspended at any time at the Company's discretion.
Dividends
In 2005, the Company paid a special dividend of $.10 per share on September 29, 2005 and increased its regular quarterly dividend by 8%, from $.12 to $.13 per share beginning with the September 29, 2005 dividend. The Company's annual dividend is currently $.52 per share, paid quarterly in March, June, September and December.
In 2004, the Company paid a special dividend of $.06 per share on September 29, 2004 and increased its regular quarterly dividend by 9%, from $.11 to $.12 per share beginning with the September 2004 dividend. In 2003, the Company paid a special dividend of $.04 per share on May 2, 2003 and increased its regular quarterly dividend by 10%, from $.10 to $.11 per share beginning with the June 2003 dividend.
As of December 31, 2005, dividends declared on 3,984,080 shares of certain Common Stock are restricted, whereby 37.5% of the dividends declared on these shares are paid by the Company to the surviving member of a group of individuals, the B Group, as long as this remaining member shall live.
Dividend payments are limited by a covenant in the Company's credit facility to the greater of $20 million or 75% of net income.
Shareholder Rights Plan
In November 1999, the Company adopted a Shareholder Rights Agreement and declared a dividend distribution of one Right for each outstanding share of Capital Stock on December 8, 1999. Each Right, when exercisable, entitles the holder to purchase one one-hundredth of a share of a Series B Junior Participating Preferred Stock, or in certain cases other securities, for $38.00. The exercise price and number of shares issuable are subject to adjustment to prevent dilution. The Rights would become exercisable, unless earlier redeemed by the Company, 10 days following a public announcement that a person or group has acquired, or obtained the right to acquire, 20% or more of the outstanding shares of Common Stock or 10 business days following the commencement of a tender or exchange offer for such outstanding shares which would result in such person or group acquiring 20% or more of the outstanding shares of Common Stock, either event occurring without the prior consent of the Company.
The Rights will expire on December 8, 2009 or may be redeemed by the Company at $.01 per Right prior to that date unless they have theretofore become exercisable. The Rights do not have voting or dividend rights, and until they become exercisable, have no diluting effect on the earnings of the Company. A total of 250,000 shares of the Company’s Preferred Stock has been designated Series B Junior Participating Preferred Stock and reserved for issuance upon exercise of the Rights.
8. Asset Retirement Obligations
Under SFAS 143, the following table summarizes the change in abandonment obligation for the years ended December 31 (in thousands):
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
9. Income Taxes
The provision for income taxes consists of the following (in thousands):
The current deferred tax assets and liabilities are offset and presented as a single amount in the financial statements. Similarly, the non-current deferred tax assets and liabilities are presented in the same manner. The following table summarizes the components of the total deferred tax assets and liabilities before such financial statement offsets. The components of the net deferred tax liability consist of the following at December 31 (in thousands):
At December 31, 2005, the Company's net deferred tax assets and liabilities were recorded as a current asset of $4.5 million and a net long-term liability of $54.2 million. At December 31, 2004, the Company's net deferred tax assets and liabilities were recorded as a current asset of $3.6 million and a long-term liability of $48 million.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
9. Income Taxes (Cont’d)
Reconciliation of the statutory federal income tax rate to the effective income tax rate follows:
The Company has approximately $23 million of federal and $17 million of state (California) EOR tax credit carryforwards available to reduce future income taxes. The EOR credits will begin to expire, if unused, in 2024 and 2015 for federal and California, respectively.
10. Commitments
The Company's contractual obligations as of December 31, 2005 are as follows (in thousands):
Long-term debt and interest - Long-term debt and related interest of approximately 6% on the long-term debt borrowings can be paid before its maturity date without significant penalty.
Operating leases - The Company leases corporate and field offices in California and in Denver. Rent expense with respect to the Company's lease commitments for the years ended December 31, 2005, 2004 and 2003 was $.6 million, $.6 million, and $.5 million, respectively.
Drilling obligation - The Company intends to participate in the drilling of over 16 gross wells on its Lake Canyon prospect over the next four years. The Company's minimum obligation under its exploration and development agreement is $9.6 million.
Drilling rig obligation - The Company is obligated in operating lease agreements for two drilling rigs, each for one year ending in 2006.
Firm natural gas transportation - The Company entered into several firm transportation contracts which provide the Company additional flexibility in securing its natural gas supply and allows the Company to potentially benefit from lower natural gas prices in the Rocky Mountains compared to natural gas prices in California.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
11. Contingencies
The Company has accrued environmental liabilities for all sites, including sites in which governmental agencies have designated the Company as a potentially responsible party, where it is probable that a loss will be incurred and the minimum cost or amount of loss can be reasonably estimated. However, because of the uncertainties associated with environmental assessment and remediation activities, future expense to remediate the currently identified sites, and sites identified in the future, if any, could be higher than the liability currently accrued. Amounts currently accrued are not significant to the financial position of the Company and Management believes, based upon current site assessments, that the ultimate resolution of these matters will not require substantial additional accruals. The Company is involved in various other lawsuits, claims and inquiries, most of which are routine to the nature of its business. In the opinion of Management, the resolution of these matters will not have a material effect on the Company’s financial position, results of operations or liquidity.
12. Equity Compensation Plans
On December 2, 1994, the Board of Directors of the Company adopted the Berry Petroleum Company 1994 Stock Option Plan which was restated and amended in December 1997 and December 2001 (the 1994 Plan or Plan) and approved by the shareholders in May 1998 and May 2002, respectively. The 1994 Plan provided for the granting of stock options to purchase up to an aggregate of 3,000,000 shares of Common Stock. All options, with the exception of the formula grants to non-employee Directors, were granted at the discretion of the Compensation Committee of the Board of Directors. The term of each option did not exceed ten years from the date the options were granted. The 1994 Plan expired on December 2, 2004, and the shareholders approved a new equity incentive plan in May 2005.
The Equity Incentive Plan (the 2005 Plan) provides for granting of equity compensation to purchase up to an aggregate of 1,450,000 shares of Common Stock. All equity grants are at market value on the date of grant and at the discretion of the Compensation Committee or the Board of Directors. The term of each employee grant did not exceed ten years from the grant date and vest 25% per year for 4 years. The 2005 Plan also allows for grants to non-employee Directors. During 2005, each of the non-employee Directors received 5,000 options at the market value on the date of grant. The options granted to the non-employee Directors vest immediately.
Stock Options
Effective January 1, 2004, the Company voluntarily adopted the fair value method of accounting for its stock option plans as prescribed by SFAS 123, Accounting for Stock-Based Compensation. The modified prospective method was selected as described in SFAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure. Under this method, the Company recognized stock option compensation expense as if it had applied the fair value method to account for unvested stock options from its original effective date. Compensation expense under the fair value method for the years ended December 31, 2005 and 2004 was $2.9 million and $1.5 million, respectively. Additionally, the Company recorded $4.4 million and $3.9 million for the years ended December 31, 2004 and 2003, respectively, in compensation expense under the variable method of accounting prior to the modification of certain exercise provisions of the Company's 1994 Plan on July 29, 2004.
The fair value of each option award is estimated on the date of grant using the Black-Scholes option pricing model that uses the assumptions noted in the following table. Expected volatilities are based on the historical volatility of the Company's stock. The Company uses historical data to estimate option exercises and employee terminations within the valuation model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of options granted is based on historical exercise behavior and represents the period of time that options granted are expected to be outstanding; the range given below results from certain groups of employees exhibiting different exercise behavior. The risk free rate for periods within the contractual life of the option is based on U.S. Treasury rates in effect at the time of grant.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
12. Equity Compensation Plans (Cont'd)
The following table summarizes information related to stock options outstanding and exercisable as of December 31, 2005:
Weighted average option exercise price information for the years ended December 31 is as follows:
The following is a summary of stock option activity for the years ended December is as follows:
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
12. Equity Compensation Plans (Cont'd)
The total intrinsic value of options exercised during the years ended December 31, 2005, 2004 and 2003, was $12.6 million, $7.2 million and $1.6 million, respectively. At December 31, 2005, the intrinsic value of options outstanding was $36.8 million and the intrinsic value of exercisable options was $26.2 million.
As of December 31, 2005, there was $8.2 million of total unrecognized compensation cost related to stock options granted under the Plan. This cost is expected to be recognized over a weighted-average period over 4 years.
Restricted Stock Units
Under the 2005 Equity Incentive Plan, the Company began a long-term incentive program whereby restricted stock units (RSUs) are available for grant to certain employees and vest 25% per year over 4 years. In 2005, 70,950 RSUs were granted with a weighted average fair value per unit granted during the year of $61.29. As of December 31, 2005, there was $3.7 million of total unrecognized compensation cost related to RSUs granted under the Plan. This cost is expected to be recognized over a weighted-average period of 4 years, which is also the weighted average remaining contractual life. Unearned compensation under the restricted stock award plan is amortized over the vesting period. The Company will pay cash compensation on the RSUs in an equivalent amount of actual dividends paid on a per share basis of the Company’s outstanding common stock.
13. 401(k) Plan
The Company sponsors a defined contribution thrift plan under section 401(k) of the Internal Revenue Code to assist all eligible employees in providing for retirement or other future financial needs. Employee contributions (up to 6% of earnings) were matched by the Company at a range of $1 for $1 up to a maximum of $1.50 for $1 based on monthly profit levels for the Company. Effective November 1, 1992, the 401(k) Plan was modified to provide for increased Company matching of employee contributions whereby the monthly Company matching contributions will range from 6% to 9% of eligible participating employee earnings, if certain financial targets are achieved. The Company's contributions to the 401(k) Plan were $1.1 million, $.8 million and $.5 million in 2005, 2004 and 2003, respectively. Approximately 99% of full-time employees participate in the Plan. In December 2005, the 401(k) Plan was amended whereby effective January 1, 2006, the Company’s matching contribution will be $1 for $1 up to a maximum of 8% of an employee’s eligible compensation.
14. Director Deferred Compensation Plan
The Company established a non-employee director deferred stock and compensation plan to permit eligible directors, in recognition of their contributions to the Company, to receive fees as compensation and defer recognition of their compensation in whole or in part to a Stock Unit Account or an Interest Account. When the eligible director ceases to be a director, the distribution from the Stock Unit Account shall be made in shares using an established market value date and the distribution from the Interest Account shall be made in cash. The aggregate number of shares which may be issued to eligible directors under the plan shall not exceed 250,000, subject to adjustment for corporate transactions that change the amount of outstanding stock. The plan may be amended at any time, not more than once every six months, by the Compensation Committee or the Board of Directors and shall terminate, unless extended, on May 31, 2008.
Amounts allocated to the Stock Unit Account have the right to receive an amount equal to the dividends per share declared by the Company on the applicable dividend payment date and this “dividend equivalent” shall be treated as reinvested in an additional number of units and credited to their account using an established market value date. Amounts allocated to the Interest Account are credited with interest at an established interest rate.
Shares earned and deferred in accordance with the plan as of December 31, 2005, and 2003 were 6,885, 7,481 and 11,037, respectively.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
15. Hedging
From time to time, the Company enters into crude oil and natural gas hedge contracts, the terms of which depend on various factors, including Management’s view of future crude oil and natural gas prices and the Company’s future financial commitments. This hedging program is designed to moderate the effects of a severe crude oil price downturn and protect certain operating margins in the Company's California operations. Currently, the hedges are in the form of swaps and collars, however, the Company may use a variety of hedge instruments in the future. Management regularly monitors the crude oil and natural gas markets and the Company’s financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging or other price protection is appropriate. All of these hedges have historically been deemed to be cash flow hedges with the marked-to-market valuations provided by external sources, based on prices that are actually quoted.
In June 2005, the Company entered into derivative instruments (zero-cost collars) for approximately 10,000 Bbl/D for the period January 1, 2006 through December 31, 2009. Based on WTI pricing, the floor is $47.50 and the ceiling is $70 per barrel. Upon entering into the new crude oil sales contract for California production in November 2005, the Company redesignated its existing crude oil collars as cash flow hedges related to California crude oil production, and there was no related effect to Other Comprehensive Income with regard to this redesignation. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. With respect to the Company’s hedging activities, the Company utilizes multiple counterparties on its hedges and monitors each counterparty’s credit rating. After the June hedge transaction, a significant credit risk concentration existed in one broker. In July 2005, the Company reduced the concentration as the hedges were transferred to multiple counterparties. The Company is not required to issue collateral on these hedging transactions.
At December 31, 2005 and 2004, Accumulated Other Comprehensive Loss consisted of $24.4 million and $1 million, respectively, net of tax of unrealized losses from the Company's crude oil and natural gas swaps and collars. Deferred net losses recorded in Accumulated Other Comprehensive Loss at December 31, 2005 are expected to be reclassified to earnings over the life of the underlying hedging contracts.
16.
Pro Forma Results (unaudited)
On January 27, 2005, the Company acquired certain interests in the Niobrara field in northeastern Colorado for approximately $105 million (J-W Acquisition) to increase natural gas reserves and production. Assets purchased include $93 million of gas properties, $6 million of pipeline, and $ 5 million of compression equipment. Liabilities assumed included $1 million of asset retirement obligations.
The unaudited pro forma results presented below for the year ended December 31, and 2004 have been prepared to give effect to the J-W Acquisition on the Company’s results of operations under the purchase method of accounting as if it had been consummated on January 1, 2004. The unaudited pro forma results do not purport to represent the results of operations that actually would have occurred on such date or to project the Company’s results of operations for any future date or period. (in thousands, except per share data):
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
17.
Lease Receivable
Canyon Drilling LLC (“Canyon”), a 100% owned Colorado entity, was dissolved in the third quarter of 2005. Canyon owned a drilling rig which was leased to a third party. After the dissolution, the drilling rig is 100% owned by the Company. Concurrent with the dissolution of Canyon, the original lease was terminated and a revised three-year lease agreement was executed which has similar terms to the original lease. The revised lease includes a three year purchase option. The total net investment in the revised lease is approximately $3.4 million and is accounted for as a direct financing lease as defined by SFAS No. 13, Accounting for Leases. Net investment in this lease as of December 31, 2005 is as follows (in thousands):
Estimated future minimum lease payments, including the purchase option, to be received as of December 31, 2005 are as follows (in thousands):
Drilling Rigs
During 2005, the Company purchased two drilling rigs. The first rig is leased to a drilling company under a three-year contract (see above), while the second rig is currently being refurbished in preparation for leasing under a similar drilling contract. Both rigs carry purchase options available to the drilling company.
18. Quarterly Financial Data (unaudited)
The following is a tabulation of unaudited quarterly operating results for 2005 and 2004 (in thousands, except per share data).
(1) During the fourth quarter of 2004, the Company recorded a net tax benefit of approximately $2.3 million, primarily due to the recognition of deferred tax assets related to certain properties and other tax items.
(2) Information has been revised in 2004 to reflect the Company's change in allocation of technical labor as disclosed in Note 2.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
19. Subsequent Events
On January 27, 2006 the Company announced that it had entered into an agreement with a private seller to acquire a 50% working interest in natural gas assets in the Piceance Basin of western Colorado for approximately $159 million to increase natural gas reserves and production. The acquisition was funded under the Company's existing credit facility. The effective date of the transaction is October 1, 2005. The Company purchased 100% interests in Piceance Operating Company (which owns a 50% working interest in the acquired assets). The Company will finalize its purchase price allocation after determining the post-closing adjustments. The transaction closed on February 28, 2006.
In February 2006, the Company purchased a third drilling rig for approximately $5 million for use in its Piceance Basin development program.
On March 1, 2006, the Board of Directors of the Company approved a two-for-one split of the Company's Class A Common Stock (Common Stock) and Class B Stock, subject to shareholder approval of an increase in authorized shares.The stock split will require that shareholders authorize the issuance of new shares at the Company’s May 17, 2006 annual meeting. Berry's shareholders will be asked to approve an increase in the Company's authorized shares of Common Stock to 100 million from the current 50 million shares and the Class B Stock to 3.0 million shares from 1.5 million shares. If approved, Berry’s transfer agent will distribute to each holder of record as of the close of business on May 17, 2006, one additional share for every share of stock held. The split will be in the form of a stock dividend, which will be distributed on June 2, 2006. Berry’s Common Stock should begin trading on a post-split basis June 5, 2006. Based on shares outstanding on March 1, 2006, Berry would have approximately 42.2 million shares of Common Stock and 1.8 million shares of Class B Stock outstanding following the proposed stock split.
Supplemental Information About Oil & Gas Producing Activities (Unaudited)
The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interests owned by the Company located solely within the United States. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion.
Disclosures of oil and gas reserves which follow are based on estimates prepared by independent engineering consultants as of December 31, 2005, 2004 and 2003. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves. The information provided does not represent Management's estimate of the Company's expected future cash flows or value of proved oil and gas reserves.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Supplemental Information About Oil & Gas Producing Activities (Unaudited)(Cont'd)
Changes in estimated reserve quantities
The net interest in estimated quantities of proved developed and undeveloped reserves of crude oil and natural gas at December 31, 2005, 2004 and 2003, and changes in such quantities during each of the years then ended were as follows (in thousands):
(1) Refer to Note 16 to the financial statements.
The standardized measure has been prepared assuming year end sales prices adjusted for fixed and determinable contractual price changes, current costs and statutory tax rates (adjusted for tax credits and other items), and a ten percent annual discount rate. No deduction has been made for depletion, depreciation or any indirect costs such as general corporate overhead or interest expense. Cash outflows for future production and development costs include cash flows associated with the ultimate settlement of the asset retirement obligation.
Standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves (in thousands):
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
BERRY PETROLEUM COMPANY
Supplemental Information About Oil & Gas Producing Activities (Unaudited)(Cont'd)
Changes in standardized measure of discounted future net cash flows from proved oil and gas reserves (in thousands):
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of December 31, 2005, the Company has carried out an evaluation under the supervision of, and with the participation of, the Company's Management, including the Company's Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1034, as amended.
Based on their evaluation as of December 31, 2005, the Chief Executive Officer and Chief Financial Officer of the Company have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Management’s Report on Internal Control Over Financial Reporting
Internal control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the supervision of, the Company's principal executive and principal financial officers, or persons performing similar functions, and effected by the Company's Board of Directors, Management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles and includes those policies and procedures that:
· pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the Company's assets;
· provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of the Company's Management and Directors; and
· provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of Management, including the principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control - Integrated Framework, Management concluded that its internal control over financial reporting was effective as of December 31, 2005.
Management’s assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
Changes in Internal Control Over Financial Reporting
There were no changes in the Company's internal control over financial reporting that occurred during the three months ended December 31, 2005 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. The Company may make changes in its internal control procedures from time to time in the future.
Item 9B.
Item 9B. Other Information
On March 1, 2006, the Board of Directors of the Company approved a two-for-one split of the Company's Class A Common Stock (Common Stock) and Class B Stock, subject to shareholder approval of an increase in authorized shares.The stock split will require that shareholders authorize the issuance of new shares at the Company’s May 17, 2006 annual meeting. Berry's shareholders will be asked to approve an increase in the Company's authorized shares of Common Stock to 100 million from the current 50 million shares and the Class B Stock to 3.0 million shares from 1.5 million shares. If approved, Berry’s transfer agent will distribute to each holder of record as of the close of business on May 17, 2006, one additional share for every share of stock held. The split will be in the form of a stock dividend, which will be distributed on June 2, 2006. Berry’s Common Stock should begin trading on a post-split basis June 5, 2006. Based on shares outstanding on March 1, 2006, Berry would have approximately 42.2 million shares of Common Stock and 1.8 million shares of Class B Stock outstanding following the proposed stock split.
On February 28, 2006 the Company completed the acquisition of a 50% working interest in natural gas assets in the Grand Valley field in the Piceance Basin of western Colorado for approximately $159 million. The purchase was funded under the Company's existing credit facility. Berry is the operator and owns a 50% working interest in 6,314 gross acres targeting gas in the Williams Fork section of the Mesaverde formation. Estimated daily production, net to Berry's interest, is approximately 1 million cubic feet of natural gas per day (MMcf/D) from three producing wells. The Company internally estimates 330 billion cubic feet of proved and probable
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
reserves, none of which are included in Berry's 2005 year-end proved reserves of 126 million barrels of oil equivalent (BOE). With this acquisition, the Company's current estimate of its total proved reserves is over 130 million BOE. Berry is increasing its 2006 capital budget by an additional $18 million to $208 million for 2006 to accelerate the development of this resource. Seven wells are currently awaiting completion which is expected by April 1, 2006.
On January 31, 2006 the Company paid cash bonuses to employees related to the Company's and each individual's performance in 2005. Mr Heinemann was paid $500,000, Mr. Goehring $185,500, Mr. Duginski $212,000, Mr. Magruder $212,000 and Mr. Crawford $96,300. Effective January 1, 2006 Mr. Heinemann's salary was increased to $500,000, Mr. Goehring's to $250,000, Mr. Duginski's to $250,000, Mr. Magruder's to $250,000 and Mr. Crawford's to $200,000.
Effective in January 2006 the compensation of the Chairman of the Board, Mr. Martin H. Young, Jr., was increased by providing that he be paid the same meeting fees as all other directors in addition to the annual retainer of $125,000 and a special award of $40,000 was made to Mr. Young in recognition of extraordinary commitment of time and resources by him on behalf of the Company in 2005. Mr. Young has elected to receive all compensation paid for his service to the Company in the form of Company stock under the terms of the Non-Employee Director Deferred Compensation Plan.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
The information called for by Item 10 is incorporated by reference from information under the captions “Corporate Governance and Board Matters” and “Compliance with Section 16(a) of the Securities Exchange Act of 1934” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of its fiscal year. Information regarding Executive Officers is contained in this report in Part I, Item 1 Business.
Item 11.
Item 11. Executive Compensation
The information called for by Item 11 is incorporated by reference from information under the caption "Executive Compensation" in the Company's definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of its fiscal year.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information called for by Item 12 is incorporated by reference from information under the captions "Security Ownership of Directors and Management" and "Principal Shareholders" in the Company's definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of its fiscal year.
Item 13.
Item 13. Certain Relationships and Related Transactions
The information called for by Item 13 is incorporated by reference from information under the caption "Certain Relationships and Related Transactions" in the Company's definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of its fiscal year.
Item 14.
Item 14. Principal Accounting Fees and Services
The information called for by Item 14 is incorporated by reference from the information under the caption “Fees to Independent Accountants for 2005 and 2004” in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of its fiscal year.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules
A. Financial Statements and Schedules
See Index to Financial Statements and Supplementary Data in Item 8.
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
B. Exhibits
Berry Petroleum Company - Dec. 31, 2005 Form 10-K
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereto duly authorized on March 1, 2006.
BERRY PETROLEUM COMPANY
/s/ Robert F. Heinemann
/s/ Ralph J. Goehring
/s/ Donald A. Dale
ROBERT F. HEINEMANN
RALPH J. GOEHRING
DONALD A. DALE
President, Chief Executive Officer
Executive Vice President and
Controller
and Director
Chief Financial Officer
(Principal Accounting Officer)
(Principal Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the dates so indicated.
Name
Office
Date
/s/ Martin H. Young, Jr.
Chairman of the Board,
March 1, 2006
Martin H. Young, Jr.
Director
/s/ Robert F. Heinemann
President, Chief Executive Officer
March 1, 2006
Robert F. Heinemann
and Director
/s/ William F. Berry
Director
March 1, 2006
William F. Berry
/s/ Joseph H. Bryant
Director
March 1, 2006
Joseph H. Bryant
/s/ Ralph B. Busch, III
Director
March 1, 2006
Ralph B. Busch, III
/s/ William E. Bush, Jr.
Director
March 1, 2006
William E. Bush, Jr.
/s/ Stephen L. Cropper
Director
March 1, 2006
Stephen L. Cropper
/s/ J. Herbert Gaul, Jr.
Director
March 1, 2006
J. Herbert Gaul, Jr.
/s/ Thomas J. Jamieson
Director
March 1, 2006
Thomas J. Jamieson
/s/ J. Frank Keller
Director
March 1, 2006
J. Frank Keller