Item 1A. Risk Factors

Other Factors Affecting the Company's Business and Financial Results

Oil and gas prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business, results of operations and financial condition. Our revenues, profitability and future growth and reserve calculations depend substantially on the price received for our oil and gas production. These prices also affect the amount of our cash flow available for capital expenditures, working capital and payments on our debt, dividends paid on our capital stock and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and gas that we can produce economically. The oil and natural gas markets fluctuate widely, and we cannot predict future oil and natural gas prices. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

• regional, domestic and foreign supply and perceptions of supply of and demand for oil and natural gas;
• level of consumer demand;
• weather conditions;
• overall domestic and global political and economic conditions;
• technological advances affecting energy consumption and supply;
• domestic and foreign governmental regulations and taxation;
• the impact of energy conservation efforts;
• the capacity, cost and availability of oil and natural gas pipelines and other transportation facilities; and
• the price and availability of alternative fuels.

      Our revenue, profitability and cash flow depend upon the prices and demand for oil and natural gas, and a drop in prices can significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:

• reduce the amount of cash flow available to make capital expenditures or make acquisitions;
• reduce the number of our drilling locations;
• increase the likelihood of refinery defaults;
• negatively impact the value of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can produce economically; and
• limit our ability to borrow money or raise additional capital.

We have a substantial amount of debt and the cost of servicing that debt could limit our financial flexibility and adversely affect our business. We have a substantial amount of indebtedness. At December 31, 2009, we had total long-term outstanding debt of approximately $1.02 billion and no short-term debt. Our borrowing base under our senior secured revolving credit facility is currently approximately $938 million and, as of December 31, 2009, we had approximately $372 million (excluding $4 million of outstanding letters of credit) outstanding under our senior secured revolving credit facility, with additional borrowing availability of approximately $562 million.

      We have demands on our cash resources, including, among others, operating expenses and interest and principal payments under our senior secured revolving credit facility, our senior secured money market line of credit, our 10.25¼% senior notes and our 8.25% senior subordinated notes. Our level of indebtedness relative to our proved reserves and these significant demands on our cash resources could have adverse effects on our business. For example, they could:

• make it more difficult for us to satisfy our obligations with respect to our debt;
• require us to dedicate a substantial portion of our cash flow from operations to payments on our debt, thereby reducing the amount of our cash flow available for working capital, capital expenditures, acquisitions and other general corporate purposes;
• require us to make principal payments under our senior secured revolving credit facility if the quantities of proved reserves attributable to our crude oil and natural gas properties are insufficient to support our level of borrowings under that credit facility;
• limit our flexibility in planning for, or reacting to, changes in the oil and gas industry;
• place us at a competitive disadvantage compared to our competitors that have lower debt service obligations and significantly greater operating and financing flexibility than we do;
• limit our financial flexibility, including our ability to borrow additional funds, pay dividends, make certain investments and issue equity on favorable terms or at all;
• increase our interest expense if interest rates increase, because borrowings under our senior secured revolving credit facility are at a variable rate of interest, and borrowings under our senior secured money market line of credit are generally at a variable rate of interest;
• increase our vulnerability to general adverse economic and industry conditions; and
• result in an event of default upon a failure to comply with financial covenants contained in our senior secured revolving credit facility, senior secured money market line of credit, senior subordinated notes or senior notes which, if not cured or waived, could have a material adverse effect on our business, financial condition or results of operations.

      A higher level of indebtedness increases the risk that we may default on our obligations. Our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon our future performance and our ability to refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital markets conditions, oil and natural gas prices, our financial condition, results of operations and prospects and other factors, many of which are beyond our control.

The borrowing base under our credit facility may be reduced below the amount of our outstanding borrowings under that facility. The amount we are able to borrow under our senior secured revolving credit facility is determined based on the value of our proved oil and natural gas reserves and is based on oil and natural gas price assumptions which vary by individual lender. Our borrowing base is subject to redetermination twice each year in April and October with the option for one additional redetermination each year and additional redeterminations contemporaneously with any issuance of permitted second lien debt and after any issuance of permitted unsecured debt. Each dollar of permitted senior unsecured debt automatically reduces the borrowing base under our senior secured revolving credit facility by 25 cents. Should there be a deficiency in the amount of our borrowing base in comparison to our outstanding debt under the senior secured revolving credit facility, we would be required to repay any such deficiency in two equal installments, 90 and 180 days after the redetermination. If we were unable to make those repayments, we would be in default under our senior secured revolving credit facility, which could have a material adverse effect on our business and financial condition.

Our heavy crude oil in California may be less economic than lighter crude oil and natural gas. As of December 31, 2009, approximately 48% of our proved reserves, or 112 million barrels, consisted of heavy oil. Light crude oil represented 8% and natural gas represented 44% of our oil and natural gas reserves. Heavy crude oil sells for a discount to light crude oil, as more complex refining equipment is required to convert heavy oil into high value products. Additionally, most of our crude oil in California is produced using the EOR process of steam injection. This process is generally more costly than primary and secondary recovery methods.

Purchasers of our crude oil and natural gas may become insolvent. We have significant concentrations of credit risk with the purchasers of our crude oil and natural gas. We had a long-term contract to sell all of our heavy crude oil in California for approximately $8.10 below WTI with Big West of California (BWOC). On December 22, 2008, Flying J, Inc. and its wholly owned subsidiary Big West Oil and its wholly owned subsidiary BWOC each filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Also in December 2008, BWOC informed us that it was unable to receive our production. On March 17, 2009, we entered into a stipulation with BWOC, terminating the contract effective as of March 16, 2009. We recorded $38.5 million of bad debt expense in 2008 for the bankruptcy of BWOC. Of that $38.5 million due from BWOC, $11.8 million represents 20 days of our December 2008 crude oil sales and an administrative claim under the bankruptcy proceedings and $26.7 million represents November 2008 and the balance of December 2008 crude oil sales which would have the same priority as other general unsecured claims. BWOC will also be liable to us for damages under this contract. While we also have guarantees from Big West Oil and from Flying J, Inc. in the amount of $75 million each, the information received from the bankruptcy proceedings to date has not provided us with adequate data from which to make a conclusion that any amounts will be collected.

       Additionally, all of our crude oil in Utah is sold under a long-term contract to a single refiner. Under the standard credit terms with our refiners, we may not know that a refiner will be unable to make payment to us until 50 days of our production has been delivered to them. If our purchasers become insolvent, we may not be able to collect any of the amounts owed to us.

We may be unable to meet our drilling obligations. We have contractual obligations on our Piceance assets in Colorado. We must spud 120 wells by February 2011 to avoid penalties of $0.2 million per well. Our ability to meet this commitment depends on the capital resources available to us to fund our activities to develop these assets on the schedule required to avoid penalties or loss of related leases. There is no assurance that our operating cash flow or alternative sources of capital investment from partnerships, joint ventures or other investment opportunities with third parties will be available to us in sufficient amount to develop these assets on the schedule required to avoid penalties.

Our financial counterparties may be unable to satisfy their obligations. We rely on financial institutions to fund their obligations under our senior secured credit facility and make payments to us under our hedging agreements. If one or more of our financial counterparties becomes insolvent, they may not be able to meet their commitment to fund future borrowings under our credit facility which would reduce our liquidity. Additionally, at current commodity prices, a portion of our cash flow over the next two years will come from payments from our counterparties on our commodity hedging contracts. If our counterparties are not able to make these payments, our cash flow will be reduced.

A widening of commodity differentials may adversely impact our revenues and our economics. Our crude oil and natural gas are priced in the local markets where the production occurs based on local or regional supply and demand factors. The prices that we receive for our crude oil and natural gas production are generally lower than the relevant benchmark prices, such as NYMEX, that are used for calculating commodity derivative positions. The difference between the benchmark price and the price we receive is called a differential. We may not be able to accurately predict natural gas and crude oil differentials.

       Price differentials may widen in the future. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the mid-stream or downstream sectors of the industry, trade restrictions and governmental regulations. We may be adversely impacted by a widening differential on the products we sell. Our oil and natural gas hedges are based on WTI or natural gas index prices, so we may be subject to basis risk if the differential on the products we sell widens from those benchmarks and we do not have a contract tied to those benchmarks. Additionally, insufficient pipeline capacity or trucking capability and the lack of demand in any given operating area may cause the differential to widen in that area compared to other oil and natural gas producing areas. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our financial condition.

Market conditions or operational impediments may hinder our access to crude oil and natural gas markets or delay our production. Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities, trucking capability and refineries owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for a lack of a market or because of inadequacy or unavailability of natural gas pipelines, gathering system capacity, processing facilities or refineries. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver the production to market.

We may not be able to deliver minimum crude oil volumes required by our sales contract. Production volumes from our Uinta properties over the next five years are uncertain and there is no assurance that we will be able to consistently meet the minimum required volume under our refining contract relating to our production from these properties. During the term of the contract, the minimum number of delivered barrels is 5,000 Bbl/D. In the event that we cannot produce the necessary volume, we may need to purchase crude to meet our contract requirements. Gross oil production from our Uinta properties averaged approximately 2,700 Bbl/D in 2009.

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, combined, provide approximately 28% of our steam capacity as of December 31, 2009. These facilities are dependent on reasonable power contracts for the sale of electricity. If, for any reason, including if utilities that purchase electricity from us are no longer required by regulation to enter into power contracts with us, we were unable to enter into new or replacement contracts or were to lose any 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 and availability of equipment. The financial cost and timing of such new investment may adversely affect our production, capital outlays and cash provided by operating activities. Our power contracts have been extended until December 31, 2010, but are subject to earlier termination by the utility counterparty in certain circumstances.

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 natural gas operations. All of our power contracts in place with the utilities are expected to terminate in 2010, and while we intend to enter into future contracts with the utilities, all of the terms of such contracts are currently the subject of contested proceedings before the California Public Utilities Commission (CPUC). Additionally, legal and regulatory decisions (especially related to the pricing of electricity under the contracts such as the SRAC Decision and the pending issues as to effective dates on retroactivity), can by reducing our electricity revenues adversely affect the economics of our cogeneration facilities and as a result the cost of steam for use in our oil and natural gas operations. In addition, any final determination by the CPUC to apply the new SRAC pricing formula retroactively, if applied so as to require payment on a one-time basis, could have a material adverse effect on our financial condition and results of operations. During the California energy crisis in 2000 and 2001, we had electricity sales contracts with various utilities and a portion of the electricity prices paid to us under such contracts from December 2000 to March 27, 2001 has been under a degree of legal challenge since that time. There are ongoing proceedings before the CPUC in which Edison and PG&E are seeking credit against future payments they are to make for electricity purchases based on retroactive adjustments to pricing under contracts with us. It is possible that we may have a liability pending the final outcome of the CPUC proceedings on the matter. Whether or not retroactive adjustments will be ordered, how such adjustments would be calculated and what period they would cover are too uncertain to estimate at this time. See “Item 1. Business - Electricity" for more information about our electricity contracts.

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 necessary to 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. We have firm transportation to move 12,000 MMBtu/D on the Kern River Pipeline from the Rocky Mountains to Kern County, CA, which accounts for approximately one-quarter of our current requirement.

Our use of oil and gas price and interest rate hedging contracts involves credit risk and may limit future revenues from price increases or reduced expenses from lower interest rates, as well as result in significant fluctuations in net income and shareholders' equity. We use hedging transactions with respect to a portion of our oil and gas production with the objective of achieving a more predictable cash flow, and reducing our exposure to a significant decline in the price of crude oil and natural gas. We also utilize interest rate hedges to fix the rate on a portion of our variable rate indebtedness, as only a portion of our total indebtedness has a fixed rate and we are therefore exposed to fluctuations in interest rates. While the use of hedging transactions limits the downside risk of price declines or rising interest rates, as applicable, their use may also limit future revenues from price increases or reduced expenses from lower interest rates, as applicable. Hedging transactions also involve the risk that the counterparty may be unable to satisfy its obligations.

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, develop or to 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 to 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. It is not possible to measure underground accumulations of oil or natural gas in an exact way. Estimating accumulations of oil and gas is a complex process that 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:

• quality and quantity of available data;
• interpretation of that data; and
• accuracy of various mandated economic assumptions.

      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 both our estimated quantities of reserves and our estimated discounted future net cash flows from our proved reserves on an un-weighted arithmetic average of the first-day-of-the month price for each month during the calendar year and on year-end costs. Actual future prices and costs may be materially higher or lower than the prices and costs used in the estimate.

Future commodity price declines and/or increased capital costs may result in a write-down of our asset carrying values which could adversely affect our results of operations and limit our ability to borrow funds. Declines in oil and natural gas prices may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments.

      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 estimated prices 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 write-down of oil and gas properties is not reversible at a later date even if oil or gas prices increase. It is possible that declining commodity prices could prompt an impairment in the future, which could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our credit facility.

Approximately 47% of our total estimated proved reserves at December 31, 2009 were proved undeveloped reserves and may be reclassified as unproved or may not ultimately be produced or developed. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve engineer reports assumes that substantial capital expenditures are required to develop such reserves. Although cost and reserve estimates attributable to our crude oil and natural gas reserves have been prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate, that development will occur as scheduled or that the results of such development will be as estimated. The SEC generally requires that reserves classified as proved undeveloped be capable of conversion into proved developed within five years of classification unless specific circumstances justify a longer time. Proved undeveloped reserves that are not timely developed are subject to possible reclassification as non-proved reserves. Substantial downward adjustments to our estimated proved reserves could have a material adverse effect on our financial condition and results of operations. In addition, our undeveloped reserves may not ultimately be developed or produced during the time periods we have planned, at the costs we have budgeted, or at all, which in turn may have a material adverse effect on our results of operations.

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 of proved undeveloped acreage. Major and independent oil and gas companies actively bid for desirable oil and gas properties, as well as for the equipment, supplies, labor and services required to operate and develop their properties. Some of these resources may be limited and have higher prices due to current strong demand. Many of our competitors have financial resources that are substantially greater than ours, which may adversely affect our ability to compete within the industry.

      Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, there is substantial competition for investment capital in the oil and gas industry. These larger companies may have a greater ability to continue drilling activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

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. Also, 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:

• obtaining government and tribal required permits;
• unexpected drilling conditions;
• pressure or irregularities in formations;
• equipment failures or accidents;
• adverse weather conditions;
• compliance with governmental or landowner requirements; and
• shortages or delays in the availability of drilling rigs and the delivery of equipment and/or services, including experienced labor.

      As a result, there can be no assurance that our anticipated production levels will be realized. For example, although we expect that our diatomite production will average approximately 5,000 BOE/D by the end of 2010, actual production from these assets could be significantly lower.

The oil and gas business involves many operating risks that can cause substantial losses. We maintain insurance. However, insurance may not protect us against all of these risks. These risks include:

• fires;
• explosions;
• blow-outs;
• uncontrollable flows of oil, gas, formation water or drilling fluids;
• natural disasters;
• pipe or cement failures;
• casing collapses;
• embedded oilfield drilling and service tools;
• abnormally pressured formations;
• major equipment failures, including cogeneration facilities; and
• 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:

• injury or loss of life;
• severe damage or destruction of property, natural resources and equipment;
• pollution and other environmental damage;
• investigatory and clean-up responsibilities;
• regulatory investigation and penalties;
• suspension of operations; and
• repairs to resume operations.

      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. For instance, we do not carry business interruption insurance. We may elect not to carry insurance if 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 insurance coverage we deem appropriate 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 existing and pending laws and regulations that could give rise to substantial liabilities from environmental contamination or otherwise adversely affect our cost, manner or feasibility of doing business. All facets of our operations are regulated extensively at the federal, state, regional and local levels. Environmental laws and regulations impose limitations on our discharge of pollutants into the environment, establish standards for our management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose on us obligations to investigate and remediate contamination in certain circumstances. We also must satisfy, in some cases, federal and state requirements for providing environmental assessments, environmental impact studies and/or plans of development before we commence exploration and production activities. Environmental and other requirements applicable to our operations generally have become more stringent in recent years, and compliance with those requirements more expensive. Frequently changing environmental and other governmental laws and regulations have increased our costs to plan, design, drill, install, operate and abandon oil and natural gas wells and other facilities, and may impose substantial liabilities if we fail to comply with such regulations or for any contamination resulting from our operations. Our business results from operations and financial condition may be adversely affected by any failure to comply with, or future changes to, these laws and regulations. In particular, 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.

      From time to time we have experienced accidental spills, leaks and other discharges of contaminants at some of our properties. We could be liable for the investigation or remediation of such contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage. We have incurred expenses and penalties in connection with remediation of contamination in the past, and we may do so in the future. Such liabilities may arise at many locations, including properties in which we have an ownership interest but no operational control, properties we formerly owned or operated and sites where our wastes have been treated or disposed of, as well as at properties that we currently own or operate, and may arise even where the contamination does not result from any noncompliance with applicable environmental laws. Under a number of environmental laws, including the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), such liabilities may be joint and several, meaning that we could be held responsible for more than our share of the liability involved, or even the entire share. Some of the properties that we have acquired, or in which we may hold an interest but not operational control, may have past or ongoing contamination for which we may be held responsible. Some of our operations are in environmentally sensitive areas that may provide habitat for endangered or threatened species, and other protected areas, and our operations in such areas must satisfy additional regulatory requirements. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed certain drilling projects and/or access to prospective lands and have filed litigation to attempt to stop such projects, including decisions by the Bureau of Land Management regarding several leases in Utah that we have been awarded.

Climate change legislation or regulatory initiatives may adversely affect our operations, our cost structure, and the demand for oil and natural gas. There is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of greenhouse gasses (GHG). Moreover, in 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for GHGs, became binding on all those countries that had ratified it. International discussions are currently underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2012. While it is not possible at this time to predict how regulation that may be enacted to address GHG emissions would impact our business, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing oil and gas exploration in the areas of the United States in which we operate could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased costs. In addition, existing or new laws, regulations or treaties (including incentives to conserve energy or use alternative energy sources) could have a negative impact on our business if such incentives reduce demand for oil and gas.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies, and the proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process. The adoption of any future federal or state laws or implementing regulation imposing reporting obligation on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to perform hydraulic fracturing, complete natural gas wells in shale formations and increase our costs of compliance and doing business.

Our operations are subject to numerous federal, state and tribal regulations and laws; compliance with existing and future laws may increase our costs and delay our operations. Our activities are also subject to regulation by the federal government, oil and natural gas-producing states and one Native American tribe. 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 federal, 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 that are more expensive than we have anticipated could have a negative effect on our ability to explore or develop our properties.

Changes to current laws may affect our ability to take certain deductions. Substantive changes to the existing federal income tax laws have been proposed that, if adopted, would affect, among other things, our ability to take certain deductions related to our operations, including depletion deductions, deductions for intangible drilling and development costs and deductions for United States production activities. These changes, if enacted into law, could negatively affect our financial condition and results of operations.

The adoption of derivative legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business. Congress is currently considering legislation to impose restrictions on certain derivatives, including in some cases energy derivatives, which could affect the use of derivatives in hedging transactions. For example, the “cap and trade" legislation contains provisions that, until other derivative regulation is enacted, would subject almost all energy commodity derivative transactions, including hedging, to the authority of the Commodity Futures Trading Commission, which can impose capital, margin and position limits on traders and require on-exchange trading and other forms of regulation. Separately, the House of Representatives adopted financial regulatory reform legislation on December 11, 2009, that, among other things, would impose comprehensive regulation on the over-the-counter derivatives marketplace. Although it is not possible at this time to predict whether or when Congress may act on derivatives regulation legislation, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge certain risks associated with our business or on the cost of our hedging activity.

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 properties with additional development potential and properties with minimal production at acquisition but significant growth potential, 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 pre-closing 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.

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. Any acquisition involves potential risks, including, among other things:

• the validity of our assumptions about reserves, future production, the future prices of oil and natural gas, revenues and costs, including synergies;
• an inability to integrate successfully the properties and businesses we acquire;
• a decrease in our liquidity to the extent we use a significant portion of our available cash or borrowing capacity to finance acquisitions;
• a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;
• the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
• the diversion of management’s attention from other business concerns;
• an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;
• unforeseen difficulties encountered in operating in new geographic areas; and
• customer or key employee losses at the acquired businesses.

      Our decision to acquire a property or business will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.

If third-party pipelines interconnected to our natural gas wells and gathering facilities become partially or fully unavailable to transport our natural gas, our results of operations and financial condition could be adversely affected. We depend upon third party pipelines that provide delivery options from our wells and gathering facilities. Since we do not own or operate these pipelines, their continuing operation in their current manner is not within our control. If any of these third-party pipelines become partially or fully unavailable to transport our natural gas, or if the gas quality specifications for their pipelines change so as to restrict our ability to deliver natural gas to those pipelines, our revenues and cash available for distribution could be adversely affected.

      In 2008, we executed two transportation precedent agreements with Ruby Pipeline LLC (Ruby), which was proposing to construct a pipeline with a capacity of 1,500,000 decatherms per day from the Opal Hub in southwest Wyoming to the Malin Hub at the California-Oregon border. One of the precedent agreements is for 25,000 decatherms per day commencing upon operation of the pipeline and the other is for 12,857 decatherms commencing two years after the commencement of operation of the pipeline for an average of 35,000 decatherms per day over the 10 year term. One of the conditions, among many, under these agreements, is that we will maintain evidence of satisfaction of creditworthiness. Under the agreements, we as the shipper have the option to choose among a variety of creditworthiness supports, one of which is that the two parties have to reach a mutually agreeable creditworthiness support. Ruby’s initial proposal is not acceptable to us and on January 29, 2010, we proposed an alternative credit arrangement that would be satisfactory to us and would be consistent with that offered by Ruby to other shippers who we believe are less creditworthy than us. On February 9, 2010, Ruby responded by rejecting Berry’s proposal and filing a lawsuit against us. This dispute may result in a termination of our contracts for capacity on this pipeline in which case we will make alternative arrangements for the transportation and marketing of our production. Additionally, the termination of these contracts may also result in monetary damages.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. Section 1(b) of the Natural Gas Act (NGA) exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission (FERC) as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company, but the status of these lines has never been challenged before FERC. The distinction between FERC-regulated transmission services and federally unregulated gathering services is subject to change based on future determinations by FERC, the courts, or Congress, and application of existing FERC policies to individual factual circumstances. Accordingly the classification and regulation of some of our natural gas gathering facilities may be subject to challenge before FERC or subject to change based on future determinations by FERC, the courts, or Congress. In the event our gathering facilities are reclassified to FERC-regulated transmission services, we may be required to charge lower rates and our revenues could thereby be reduced.

Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. FERC has issued an order requiring certain participants in the natural gas market, including natural gas gatherers and marketers, that engage in a minimum level of natural gas sales or purchases to submit annual reports regarding those transactions to FERC. In addition, FERC has issued an order requiring major non-interstate pipelines, defined as certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of gas over the previous three calendar years, to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has design capacity equal to or greater than 15,000 MMBtu per day. Should we fail to comply with these requirements or any other applicable FERC-administered statute, rule, regulation or order, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation.

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 and professionals, our ability to compete could be harmed.

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:

• results of our exploration efforts and the acquisition, review and analysis of our seismic data, if any;
• availability of sufficient capital resources to us and any other participants for the drilling of the prospects;
• approval of the prospects by other participants after additional data has been compiled;
• 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
• 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. For instance, our drilling schedule may vary from our expectations because of future uncertainties and rig availability and access to our drilling locations utilizing available roads. In addition, we will not necessarily drill wells on all of our identified drilling locations on our acreage.

We may incur losses as a result of title deficiencies. We acquire from third parties, or directly from the mineral fee owners, working and revenue interests in the oil and natural gas leaseholds and estates upon which we will perform our exploration activities. The existence of a material title deficiency can reduce the value or render a property worthless thus adversely affecting the results of our operations and financial condition. Title insurance covering mineral leaseholds is not always available and when available is not always obtained. As is customary in our industry, we rely upon the judgment of staff and independent landmen who perform the field work of examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and/or undertake drilling activities. We, in some cases, perform curative work to correct deficiencies in the marketability of the title to us. In cases involving title problems, the amount paid for affected oil and natural gas leases or estates can be generally lost, and a prospect can become undrillable.

We have received a notice of proposed civil penalty of $69.6 million from the Bureau of Land Management that may result in our payment of a significant penalty. In July 2009, we received a notice of proposed civil penalty from the Bureau of Land Management (the BLM) related to our alleged non-compliance during 2007 with regulations relating to the operation and position of certain valves in our Uinta basin operations. The regulations are intended to address production security on Federal and tribal lands managed by the BLM. The proposed civil penalty is $69.6 million and reflects the theoretical maximum penalty amount under applicable regulations, absent mitigating factors. We immediately remediated the instances of non-compliance in 2007, cooperated fully with the BLM’s investigation and we believe no production was lost, all royalties were paid and there was no harm to the environment. Due to the above mitigating factors, among others, we believe this matter will be resolved by the payment of a penalty that will not exceed $2.1 million and have accrued such amount in the second quarter of 2009. However, there can be no assurance that any penalty would not be in excess of $2.1 million or have a material adverse affect on us.

 

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