Item 1A: Risk Factors
You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this annual report or in any other of our filings with the Securities and Exchange Commission ("SEC") could have a material adverse effect on our business, financial position, liquidity and results of operations. In evaluating us, you should consider carefully, among other things, the factors and the specific risks set forth below and in documents we incorporate by reference. This annual report contains forward-looking statements that involve risks and uncertainties. Some of the following risks relate principally to the industry in which we operate and to our business. Other risks relate principally to the securities markets and ownership of our common shares. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected, the trading price of your shares could decline, and you may lose all or part of your investment.
Risks Relating to the Oil and Natural Gas Industry and Our Business
Oil and natural gas prices are volatile. Volatility in oil and natural gas prices can adversely affect our results and the price of our common stock. This volatility also makes valuation of natural gas and oil producing properties difficult and can disrupt markets.
Oil and natural gas prices have historically been, and are likely to continue to be, volatile. Oil and natural gas prices are subject to wide fluctuations 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. Some of the factors that cause these fluctuations are:
•demand for oil and gas, which is affected by worldwide population growth, economic development and general economic and business conditions;
•the domestic and foreign supply of oil and natural gas;
•political and economic uncertainty and socio-political unrest;
•the price of foreign imports;
•political and economic conditions in oil producing countries, especially the Middle East and South America;
•the ability of the Organization of Petroleum Exporting Countries ("OPEC") to set and maintain oil price and production controls;
•the level of worldwide oil exploration and production activity;
•the cost of exploring for, producing and delivering oil and gas;
•weather conditions;
•technological advances affecting energy consumption;
•domestic and foreign governmental regulations;
•proximity and capacity of oil and gas pipelines and other transportation facilities;
•the price and availability of alternative energy; and
•variations between product prices at sales points and applicable index prices.
The long-term effects of these and other conditions on the prices of crude oil and natural gas are uncertain. Price volatility makes it difficult to budget and project the return on exploration and development projects involving our natural gas and oil properties and to estimate with precision the value of producing properties that we may own or propose to acquire. In addition, unusually volatile
prices often disrupt the market for natural gas and oil properties, as buyers and sellers have more difficulty agreeing on the purchase price of properties. Our annual and quarterly results of operations may fluctuate significantly as a result of, among other things, variations in natural gas and oil prices and production performance. In recent years, natural gas and oil price volatility has become increasingly severe.
A decline in oil and natural gas prices would adversely affect our ability to meet our capital expenditure obligations, financial commitments, financial results, cash flows, access to capital and ability to grow.
Our revenues, operating results, cash flow, profitability and future rate of growth depend upon the prevailing prices of, and demand for, natural gas and oil. All of our operating revenues are derived from the sale of our oil and gas production. A continuing substantial or extended decline in oil and natural gas prices would have a material adverse effect on our financial position, our ability to meet capital expenditure obligations and commitments, our results of operations, our access to capital and the quantities of natural gas and oil that may be economically produced by us. A significant decrease in price levels for an extended period negatively affects us in several ways including:
•our cash flow will be reduced, decreasing funds available for capital investments employed to replace reserves, increase production or to operate;
•certain reserves will no longer be economic to produce, leading to both lower proved reserves and cash flow and may result in charges to earnings for impairment of the value of these assets; and
•access to other sources of capital, such as bank loans, equity or debt markets, could be severely limited or unavailable.
Based on crude and natural gas pricing in recent years, the Company's oil and gas revenues may from time to time decrease, resulting in a negative impact on liquidity. The Company's current plans to address lower crude and natural gas prices are primarily to reduce capital expenditures to a level equal to cash flow from operations, reduce operating expenses and seek additional capital financing. However, the Company's plans may not be successful in improving its results of operations and liquidity. If oil or natural gas prices decline significantly for extended periods of time in the future, we might not be able to generate enough cash flow from operations to meet our obligations and make planned capital expenditures, which could impair our liquidity and our ability to develop our properties and to operate.
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 exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. Under these laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs), and other damages. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations, or subject us to administrative, civil and criminal penalties, including the assessment of natural resources damages. Environmental and other governmental laws and regulations also increase the costs to plan, permit, design, drill, install, operate and abandon oil and natural gas wells. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects. Compliance costs are significant. The exploration and production of oil and gas involves many risks concerning equipment and human operational problems that could lead to leaks or spills of petroleum products. These laws and regulations, particularly in the California and Rocky Mountain regions, are extensive and involve severe penalties and could change in ways that substantially increase our costs and associated liabilities.
Part of the regulatory environment in which we operate includes, in some cases, federal and state requirements for performing or preparing environmental assessments, environmental impact statements, studies, reports and/or plans of development before commencing exploration and production activities. These regulations affect our operations and may hinder or limit the quantity of oil and natural gas we may be able to produce and sell.
A major risk inherent in our drilling plans is the need to obtain drilling permits from applicable federal, state and local authorities. Delays in obtaining regulatory approvals or drilling permits for producing and water injection wells, the failure to obtain a drilling permit for a well, or the receipt of a permit with excessive conditions or costs could have a material adverse effect on our ability to explore or develop our 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. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells and larger operating area. Any or all of these contingencies could delay or halt our drilling activities or the construction of ancillary facilities necessary for production, which would prevent us from developing our property interests as planned. Conditions, delays or restrictions imposed on the management of groundwater produced during drilling could severely limit our operations or make them uneconomic. Any unfavorable developments in the Washakie Basin could impede our growth, as we intend to undertake significant activity in order to increase our production and reserves in this area.
We cannot be certain that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not harm our business, results of operations and financial condition. For example, matters subject to regulation and the types of permits required include:
•drilling permits;
•water discharge and disposal permits for drilling operations;
•the amounts and types of substances and materials that may be released into the environment;
•drilling and operating bonds;
•environmental matters and reclamation;
•spacing of wells;
•the use of underground injection wells, which affects the disposal of water from our wells;
•occupational safety and health;
•unitization and pooling of properties;
•air quality, noise levels and related permits;
•rights-of-way and easements;
•reports concerning operations to regulatory authorities;
•calculation and payment of royalties;
•gathering, transportation and marketing of gas and oil;
•taxation; and
•waste disposal.
Under these laws and regulations, we could be liable for:
•personal injuries;
•property damage;
•oil spills;
•discharge or disposal of hazardous materials;
•well reclamation costs;
•surface remediation and clean-up costs;
•fines and penalties;
•natural resource damages; and
•other environmental protection and damages issues.
See "Items 1 and 2: Business and Properties-Regulations and Environmental Matters" and "Item 3:-Legal Proceedings" for a more detailed discussion of laws affecting our operations.
Changes in applicable laws and regulations could increase our costs, reduce demand for our production, impede our ability to conduct operations or have other adverse effects on our business.
Future changes in the laws and regulations to which we are subject may make it more difficult or expensive to conduct our operations and may have other adverse effects on us. For example, the EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other greenhouse gases ("GHG") present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has recently begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress is considering "cap and trade" legislation that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission "allowances" corresponding to their annual emissions of GHGs. On September 27, 2006, California's governor signed into law Assembly Bill (AB) 32, known as the "California Global Warming Solutions Act of 2006," which establishes a statewide cap on GHGs that will reduce the state's GHG emissions to 1990 levels by 2020 and establishes a "cap and trade" program. The California Air Resources Board has been designated as the lead agency to establish and adopt regulations to implement AB 32 by January 1, 2012. Similar regulations may be adopted by the federal government. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for our production.
Additionally, the recently enacted Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Reform Act, among other things, imposes restrictions on the use and trading of certain derivatives, including energy derivatives. The nature and scope of those restrictions will be determined in significant part through implementing regulations to be adopted by the SEC, the Commodities Futures Trading Commission and other regulators. If, as a result of the Reform Act or its implementing regulations, additional capital or margin requirements or other limitations relating to our commodity derivative activities are imposed, this could have an adverse effect on our ability to implement our hedging strategy. In particular, a requirement to post cash collateral in connection with our derivative positions, which are currently collateralized on a non-cash basis by our oil and natural gas properties and other assets, would likely make it impracticable to implement our current hedging strategy or to meet the hedging requirements contained in our revolving credit facility. In addition, requirements and limitations imposed on our derivative counterparties could increase the costs of pursuing our hedging strategy.
In addition, some of our activities involve the use of hydraulic fracturing, which is a process that creates a fracture extending from the well bore in a rock formation to enable oil or natural gas to
move more easily through the rock pores to a production well. Fractures are typically created through the injection of water and chemicals into the rock formation. Legislative and regulatory efforts at the federal level and in some states have been made to render permitting and compliance requirements more stringent for hydraulic fracturing. These proposals, if adopted, would likely increase our costs and make it more difficult, or impossible, to pursue some of our development projects.
We could also be adversely affected by future changes to applicable tax laws and regulations. For example, proposals have been made to amend federal and/or California state and local laws to impose "windfall profits," severance or other taxes on oil and natural gas companies. If any of these proposals become law, our costs would increase, possibly materially. Significant financial difficulties currently facing the State of California and localities may increase the likelihood that one or more of these proposals will become law.
President Obama's 2011 Fiscal Year Budget includes proposals that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could defer or eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.
We have incurred losses and may do so in the future.
At December 31, 2010, we had an accumulated deficit of $312.2 million and total stockholders' equity of $150.7 million. We have recognized a significant amount of annual net losses in the past. See "Item 6: Selected Consolidated Financial Data". The uncertainty and factors described throughout this section may impede our ability to economically find, develop, exploit and acquire natural gas and oil reserves. We may not achieve or sustain profitability or positive cash flows from operating activities in the future.
Our proved reserves are estimates based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
No one can measure underground accumulations of oil and natural gas in an exact way. There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control that could cause the quantities and net present value of our reserves to be overstated or understated. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, operating and development costs, drilling expenses, severance and excise taxes, capital expenditures, ownership and title matters, taxes and the availability of funds. The engineering process of estimating natural gas and oil reserves is complex and is not an exact science. It requires interpretations of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.
Estimates of reserves based on risk of recovery and estimates of expected timing and future net cash flows prepared or audited by different engineers, or by the same engineers at different times, may vary substantially. Because of the subjective nature of crude oil and natural gas reserve estimates, each of the following items may differ materially from the amounts or other factors estimated:
•The amount and timing of crude oil and natural gas production.
•The revenues and costs associated with that production.
•The amount and timing of future development expenditures.
Over time, our independent petroleum engineering consultants may make material changes to reserve estimates taking into account the results of actual drilling, testing, and production. Further, the potential for future reserve revisions, either upward or downward, is significantly greater than normal because a significant portion of our potential reserves are undeveloped.
In accordance with SEC requirements, our estimates of proved reserves for 2010 are determined based on a historical 12-month average price as of the first day of each month during the fiscal year. Any significant variance from these prices and costs could greatly affect our estimates of reserves. In addition, proved undeveloped reserves locations to limited to those scheduled to be drilled within the next five years
As of December 31, 2010 and 2009, approximately 27% and 22%, respectively, of our estimated net proved reserves were undeveloped. Undeveloped reserves, by their nature, are less certain. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Additionally, as oil and gas commodity prices become lower, the quantity of economically recoverable proved reserves declines. The reserve data assumes that we will make significant capital expenditures to develop our reserves. We have prepared estimates of our natural gas and oil reserves and the costs associated with these reserves in accordance with industry standards. However, the estimated costs may not be accurate, development may not occur as scheduled, or the actual results may not be as estimated. We may not have, or be able to obtain, the capital we need to develop these proved reserves.
Actual natural gas and oil prices, future production, revenues, operating expenses, taxes, development expenditures and quantities of recoverable natural gas and oil reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of future net revenues set forth in this annual report. A reduction in natural gas and oil prices, for example, would reduce the value of proved reserves and reduce the amount of natural gas and oil that could be economically produced, thereby reducing the quantity of reserves. We may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control.
You should not assume that the present value of future net revenues referred to in this annual report is the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of 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. Any change in consumption by natural gas and oil purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses for the development and production of our natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor, nor does it reflect discount factors used in the marketplace for the purchase and sale of oil and gas properties. Conditions in the oil and gas industry and oil and gas prices will affect whether the 10% discount factor accurately reflects the market value of our estimated reserves.
Drilling for and producing natural gas and oil are high risk activities with many uncertainties that could have a material adverse effect on our business, financial condition or results of operations.
Our future success depends largely on the success of our exploration, exploitation, development and production activities. These activities are subject to numerous risks beyond our control, including the risk that we will not find any commercially productive natural gas or oil reservoirs. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties depends in part on the
evaluation of geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our costs of drilling, completing, producing and operating wells are often uncertain before drilling commences. Drilling for oil and natural gas can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenues to return a profit. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
•delays in obtaining drilling permits from applicable regulatory authorities;
•unusual or unexpected geological formations;
•unexpected drilling conditions, including ground shifting or quakes;
•pressure or irregularities in geological formations;
•equipment failures or accidents;
•well blow-outs;
•fires and explosions;
•pipeline and processing interruptions or unavailability;
•title problems;
•objections from surface owners and nearby surface owners in the areas where we operate;
•adverse weather conditions;
•lack of market demand for natural gas and oil;
•delays imposed by or resulting from compliance with environmental and other regulatory requirements;
•shortages of or delays in the availability or delivery of drilling rigs and the delivery of equipment; and
•reductions in natural gas and oil prices.
Our future drilling activities may not be successful. Our drilling success rate could decline generally or within a particular area and we could incur losses by drilling unproductive wells. Also, we may not be able to obtain sufficient contracts covering our lease rights in potential drilling locations. We cannot be sure that we will ever drill our identified potential drilling locations, or that we will produce natural gas or oil from them or from any other potential drilling locations. Shut-in wells, curtailed production and other production interruptions may negatively impact our business and result in decreased revenues.
The recent crisis in U.S. and world financial and securities markets could have a material adverse effect on our business and operations.
Our operations are affected by local, national and worldwide economic conditions. The national and global economy, which experienced a significant downturn throughout 2008 and 2009, including widespread recessionary conditions, record levels of unemployment, significant distress of financial institutions, extreme volatility in security prices, severely diminished liquidity and credit availability, began showing signs of gradual improvement in 2010. However, while some economic indicators trended positively, the overall rate of national and global recovery experienced during the course of 2010 has been uneven and uncertainty continues to exist over the stability of the recovery. Although consumer confidence in the U.S. has improved since the economic downturn, it still remains low, while unemployment remains high and the housing market remains depressed. There can be no assurance
that any of the recent economic improvements will be broad based and sustainable, or that they will enhance conditions in markets relevant to us. In the past, we have relied on the capital markets, particularly for equity securities, as well as the banking and debt markets, to meet financial commitments and liquidity needs if internally generated cash flow from operations is not adequate to fund our capital requirements. If the economic recovery does not continue, we may be unable to obtain equity or debt financing, which may require us to limit or reduce our capital expenditures. Additionally, the economic slowdown could continue to lead to lower demand for oil and natural gas by individuals and industries, which in turn could result in lower prices for the oil and natural gas we sell, thereby adversely resulting in declining production, lower revenues, and possibly losses and negative cash flow.
Our credit facility contains operating restrictions and financial covenants, and we may have difficulty obtaining additional credit.
We will depend on our revolving credit facility for a portion of our future capital needs. As of December 31, 2010, we had $69.5 million in principal amount of senior indebtedness outstanding under our secured revolving bank Credit Facility and our available borrowing base was $120 million. Our Credit Facility restricts our ability to obtain additional financing, make investments, pay dividends, lease equipment, sell assets and engage in business combinations. We also are, and will continue to be, required to comply with certain financial covenants and ratios. The Credit Facility contains affirmative and negative covenants, including the following financial maintenance covenants: an EBITDAX to interest coverage ratio for any period of four consecutive fiscal quarters to be not less than 2.5 to 1.0, determined as of the last day of each fiscal quarter; and a minimum current ratio of current assets (including availability under the Credit Facility) to current liabilities of not less than 1.0 to 1.0. At December 31, 2010, the Company was in full compliance with the covenants and other provisions of the Credit Facility.
In addition to those described above, other factors may impair the Company's ability to comply with the covenants. Any failure to be in compliance with any material provision or covenant of the Credit Facility could result in a default, which could have a material adverse effect on our liquidity, results of operations and financial condition. At certain oil and natural gas price levels, the Company's current cost structure, inclusive of our current plans, may exceed the costs required to operate profitably. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants contained in the Credit Facility could result in a default under the facility, which could cause all of our existing indebtedness to become immediately due and payable.
Our Credit Facility limits the funds we can borrow to a borrowing base amount, determined by the lenders in their sole discretion, based upon projected revenues from the oil and natural gas properties securing our loan. In addition, under the terms of our credit facility, our borrowing base is subject to redeterminations at least semiannually on April 1 and October 1 of each year based in part on prevailing natural gas and oil prices. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the required lenders do not agree on an increase, then the borrowing base will be the lowest borrowing base acceptable to the required number of lenders. In the event the borrowed amount outstanding exceeds the re-determined borrowing base, we could be forced to repay a portion of our borrowings. If lower oil and natural gas commodity prices occur, our borrowing base may be lowered by the lenders upon a future borrowing base re-determination. We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, in order to prevent a default we may have to sell a portion of our assets. If we cannot timely sell a portion of our assets under such circumstances, the lenders could
declare the Credit Facility in default, which could cause all of our existing indebtedness to be immediately due and payable.
Our Credit Facility is secured by a pledge of substantially all of our producing natural gas and oil properties and assets, is guaranteed by our subsidiaries, and contains covenants that limit additional borrowings, dividends to nonpreferred shareholders, the incurrence of liens, investments, sales or pledges of assets, changes in control, repurchases or redemptions for cash of our common or preferred stock, speculative commodity transactions and other matters. We may not be able to refinance our debt or obtain additional financing, particularly in view of the credit facility's restrictions on our ability to incur additional debt, and the fact that substantially all of our assets are currently pledged to secure obligations under the Credit Facility. The restrictions in our credit facility and our difficulty in obtaining additional debt financing may have adverse consequences on our operations and financial results, including:
•our ability to obtain financing for working capital, capital expenditures, our drilling program, purchases of new technology or other purposes may be impaired;
•the covenants in our credit facility that limit our ability to borrow additional funds and dispose of assets may affect our flexibility in planning for, and reacting to, changes in business conditions;
•because our indebtedness is subject to variable interest rates, we are vulnerable to increases in interest rates;
•any additional financing we obtain may be on unfavorable terms;
•we may be required to use a substantial portion of our cash flow to make debt service payments, which will reduce the funds that would otherwise be available for operations and future business opportunities;
•a substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements or covenants, and could require us to modify our operations, including curtailing portions of our drilling program, selling assets, reducing our capital expenditures, refinancing all or a portion of our existing debt or obtaining additional financing; and
•we may become more vulnerable to downturns in our business or the economy generally.
We may be required to incur additional debt in order to fund our exploration and development activities. A higher level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and reduce our level of indebtedness depends on future performance. General economic conditions, natural gas and oil prices and financial, business and other factors, many of which are beyond our control, affect our operations and our future performance.
We are subject to the full cost ceiling limitation which resulted in a write-down of our estimated net reserves in 2008 and may result in a write-down of our estimated net reserves in the future.
We utilize the full cost method of accounting for costs related to our natural gas and oil properties. Under the full cost method, we are subject to quarterly calculations of a "ceiling" or limitation on the amount of our oil and gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and gas properties exceed the cost center ceiling, we are subject to a write-down of our net oil and gas properties to the extent of such excess. A capitalized cost ceiling test impairment also reduces earnings and impacts stockholders' equity in the period of occurrence and results in lower amortization expense in future periods. The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. For 2008, realized commodity prices declined to $32.92 per barrel of oil
and $4.80 per Mcf of gas at December 31, 2008. For our 2008 full-cost ceiling test we recognized an impairment of $272.2 million on our oil and natural gas properties. For 2010 and 2009, there was no ceiling test impairment on our oil and gas properties.
The risk that we will be required to write down the carrying value of oil and natural gas properties increases when natural gas and crude oil prices are depressed or volatile. In addition, a write-down of proved oil and natural gas properties may occur if we experience substantial downward adjustments in our estimated proved reserves, or if purchasers cancel long-term contracts for our natural gas production. An expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the applicable ceiling in the subsequent period. This and other factors could cause us to write down our natural gas and oil properties or other assets in the future and incur a non-cash charge against future earnings.
Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas and oil reserves.
The oil and natural gas industry is capital intensive. We spend and will continue to need a substantial amount of capital for the acquisition, exploration, exploitation, development and production of oil and gas reserves. We have historically addressed our short and long-term liquidity needs through the use of cash flow provided by operating activities, borrowing under bank credit facilities, and the issuance of equity and debt securities. Without adequate financing we may not be able to successfully execute our operating strategy. The availability of these sources of capital will depend upon a number of factors, some of which are beyond our control. These factors include:
•general economic and financial market conditions;
•oil and natural gas prices;
•our market value and operating performance;
•timely issuance of permits and licenses by governmental agencies;
•the success of our CBM projects in the Washakie Basin;
•the success of our waterflood recovery oil projects in the Wilmington Townlot Unit and the North Wilmington Unit;
•our success in locating and producing new reserves;
•amounts of necessary working capital and expenses; and
•the level of production from existing and new wells.
We may be unable to execute our operating strategy if we cannot obtain adequate capital. If low oil and natural gas prices, lack of adequate gathering or transportation facilities, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, it may limit or reduce our borrowing base under our credit facility, and therefore, limit our ability to obtain the capital necessary to sustain our operations.
Additional financing sources may be required in the future to fund our developmental and exploratory drilling. Our Credit Facility restricts our ability to obtain new financing. There can be no assurance as to the availability or terms of any additional financing. Issuing equity securities to satisfy our financing requirements could cause substantial dilution to our existing stockholders. Additional debt financing could lead to:
•a substantial portion of our operating cash flow being dedicated to the payment of principal and interest;
•becoming more vulnerable to competitive pressures and economic downturns; and
•restrictions on our operations.
Financing may not be available in the future under existing or new financing arrangements, or we may not be able to obtain the necessary financing on acceptable terms, if at all. If sufficient capital resources are not available, we may be forced to curtail our drilling, acquisition and other operations, or be forced to sell some of our assets on an untimely or unfavorable basis, or face a possible loss of properties and a decline in our oil and natural gas reserves, which would have an adverse affect on our business, financial condition and results of operations.
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.
Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future success depends on our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves generally decline when production occurs unless we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. We may not be able to find, develop or acquire additional reserves on an economic basis. Furthermore, if oil and natural gas prices increase, our costs for additional reserves could also increase. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find, finance or acquire additional reserves to replace our current and future production at acceptable costs.
Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs and expenses, and drilling and production results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled, or if we will be able to produce natural gas or oil from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
We face significantly increasing water disposal regulations and costs in our drilling operations.
The Wyoming Department of Environmental Quality, or Wyoming DEQ, has restrictive regulations applicable to the surface disposal of water produced from our CBM drilling operations. We typically obtain Clean Water Act, Safe Drinking Water Act and analogous state and local permits to use surface discharge methods, such as settling ponds, to dispose of water when the groundwater produced from the coal seams will not exceed surface discharge permit limitations. Surface disposal options have volumetric limitations and require an extensive third-party water sampling and laboratory analysis program to ensure compliance with state permit standards. Alternative methods to surface disposal of water are more expensive. These alternatives include installing and operating treatment facilities or drilling disposal wells to inject the produced water into the underground rock formations adjacent to the coal seams or lower sandstone horizons. Injection wells are regulated by the Wyoming DEQ and the Wyoming Oil & Gas Conservation Commission, and permits to drill these wells are obtained from these agencies. Based on our experience with CBM production, we believe that permits for surface
discharge of produced water in the Washakie Basin will become difficult to obtain. In Wyoming, our produced water is currently re-injected into water disposal wells.
In California, as part of our development plan for the WTU, we have filed 12 applications for water injection wells that are currently pending before the California Division of Oil, Gas and Geothermal Resources ("DOGGR"). However, we believe that because of the DOGGR's personnel constraints and new more rigid review and interpretation procedures, these water injection permits are taking longer than previous permits. Due to the volume of water being injected into the Upper Terminal formation and the corresponding rise in reservoir pressure, during 2011, we have elected to temporarily shut-in approximately 300 net BOPD (approximately 110,000 barrels of oil annually) from lower producing, higher water-cut wells, until water injection well permits are obtained for the Tar and Ranger formations. Additionally, as a result of the delay in receiving water injection permits, the reservoir pressure in the Tar formation has been dropping, resulting in a steeper production decline. If DOGGR permit approvals are obtained as anticipated in the summer and fall of 2011, we believe that these temporarily shut-in wells will begin to return to production in late 2011 and eventually return to full production during 2012 and 2013. We cannot be certain, however, of when DOGGR will issue the water injection permits for the WTU.
We expect the regulation and costs to dispose of produced water to increase significantly, which could have a material adverse effect on our business, financial condition and results of operations.
We face significantly increasing natural gas disposal regulations and costs in our Wilmington oil drilling operations that could limit our oil production.
The State of California and the EPA have restrictive regulations for the disposition of natural gas produced from our Wilmington oil drilling operations. Natural gas production has continued to grow with the oil production, particularly at the WTU. Because the gas volume from the WTU was historically too low to justify gas sales equipment, the gas has been flared for many years under a permit from the SCAQMD. In late 2007, Warren entered into an agreement with the SCAQMD which allowed Warren to commission six microturbines to generate electrical power from the otherwise flared gas and resume full production. As oil production grew since that time, the excess gas produced but not consumed by our microturbines could have exceeded our gas flare limitation.
In March 2008, the Company presented its plan to the SCAQMD to seek approvals from regulatory authorities to dispose of our produced gas by injection or sell it directly into a nearby public utility pipeline or to a third party user. Warren also applied to the SCAQMD for a permit to construct a new high efficiency clean enclosed burner to replace the existing gas flare. Based on pressure from environmental groups and due to its heightened concern regarding a possible legal challenge, the SCAQMD has become more conservative regarding the issuance of these types of permits. The SCAQMD is now requiring that Warren conduct a significant analysis under CEQA of the possible environmental impacts resulting from the installation and operation of this new equipment. If the SCAQMD does not issue the necessary permits, the implementation of the new equipment will be significantly delayed. Delays by regulatory agencies in approving our permits to dispose of the natural gas could limit our future oil production levels until the permits are issued.
See "Items 1 and 2: Business and Properties-Future Regulations-Wilmington Field"
Operational impediments may hinder our access to natural gas and oil markets or delay our production.
The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. This dependence is heightened in our CBM operations where this infrastructure is less developed than in our traditional oil and gas operations. For example, there is limited pipeline capacity in the southern portion of the Washakie Basin. Also, as production volumes grow in the Atlantic Rim, additional pipeline capacity and gas compression will be required.
We deliver natural gas and oil through gathering systems and pipelines that we do not own. These facilities may not be available to us in the future. Our ability to produce and market natural gas and oil is affected and may be harmed by:
•the lack of pipeline transmission facilities or carrying capacity;
•federal and state regulation of natural gas and oil production; and
•federal and state transportation, taxation and energy policies.
In 2003, we entered into an agreement with Anadarko to jointly construct compression facilities and a pipeline in the Washakie Basin. Any significant change in our arrangement with Anadarko or other market factors affecting our overall infrastructure facilities could adversely impact our ability to deliver the natural gas we produce to market in an efficient manner, or to obtain adequate natural gas prices. In some cases, we may be required to shut-in wells, at least temporarily, for lack of a market or because of the inadequacy or unavailability of transportation facilities. If that were to occur, we would be unable to realize revenue from those wells until arrangements could be made to deliver our production to market.
We may be affected by climate change and market or regulatory responses to climate change
Climate change, including the impact of global warming, could have a material adverse effect on our results of operations, financial condition, and liquidity. Restrictions, caps, taxes, or other controls on emissions of greenhouse gasses, including exhaust from generators, engines and flaring of excess natural gas, could significantly increase our operating costs. Restrictions on emissions could also affect our customers that (a) use oil and gas to produce energy, or (b) manufacture or produce goods that consume significant amounts of energy or burn fossil fuels, including chemical producers, farmers and food producers, and automakers and other manufacturers. Significant cost increases, government regulation, or changes of consumer preferences for goods or services relating to alternative sources of energy or emissions reductions could materially affect the markets for the oil and gas commodities, which in turn could have a material adverse effect on our results of operations, financial condition, and liquidity. Government incentives encouraging the use of alternative sources of energy could also affect certain of our oil and gas commodity purchasers and the markets for certain of the commodities in an unpredictable manner, including, for example, the impacts of ethanol incentives on farming and ethanol producers and tax credits for wind turbine and solar power generation. Finally, we could face increased costs related to defending and resolving legal claims and other litigation related to climate change and the alleged impact of our operations on climate change. Any of these factors, individually or in operation with one or more of the other factors, or other unforeseen impacts of climate change could reduce the demand for oil and gas commodities and have a material adverse effect on our results of operations, financial condition, and liquidity.
Our hedging activities could result in financial losses or could reduce our income.
To achieve a more predictable cash flow, to reduce our exposure to adverse fluctuations in the prices of oil and natural gas and to comply with credit agreement requirements, we currently, and may in the future, enter into hedging arrangements for a portion of our oil and natural gas production. Hedging arrangements for a portion of our oil and natural gas production expose us to the risk of financial loss in some circumstances, including when:
•production is less than expected;
•the counterparty to the hedging contract defaults on its contractual obligations; or
•there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received.
In addition, these types of hedging arrangements limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements.
The risk that a counterparty may default on its obligations is heightened by the recent sub-prime mortgage losses incurred by many banks and other financial institutions, including our counterparties or their affiliates. These losses may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which would reduce our revenues from hedges at a time when we are also receiving a lower price for our natural gas and oil sales. As a result, our financial condition could be materially or adversely affected.
We have elected not to designate our commodity derivatives as cash flow hedges for accounting purposes. Accordingly, such contracts are recorded at fair value on our Balance Sheet and changes in fair value are recorded in the Consolidated Statements of Operations as they occur.
We may incur additional debt in order to fund our exploration and development activities, which would reduce our financial flexibility and could have a material adverse effect on our business, financial condition or results of operations.
In addition to our credit facility, we may incur additional debt in order to fund our operations, make future acquisitions or develop our properties. A higher level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and reduce our level of indebtedness depends on future performance. General economic conditions, oil and gas prices, and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flow to pay the interest on our debt or pay our debt at maturity. If we are unable to repay our debt at maturity with existing cash on hand, we could attempt to refinance the debt or repay the debt with the proceeds of a debt or equity offering. We may be unable to sell public debt or equity securities, or do so on acceptable terms to pay or refinance the debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, our market value and profitability of our operations at the time of the offering or other financing. If we do not have sufficient funds, are otherwise unable to negotiate renewals of our borrowings, or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
Properties that we buy may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them, which could cause us to incur losses.
One of our growth strategies is to pursue selective acquisitions of natural gas and oil reserves. We perform a review of the target properties that we believe is consistent with industry practices. However, these reviews may not be completely accurate. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable, even when an inspection is undertaken. Even when problems are identified, a seller may be unwilling or unable to provide effective contractual protection against all or part of those problems, and we often assume environmental and other risks and liabilities in connection with the properties we acquire.
Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil and natural gas operations in the Rocky Mountains can be adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. Our operations in Wyoming are conducted in areas subject to extreme weather conditions and in difficult terrain. Primarily in the winter and spring, our operations are often curtailed because of cold, snow and wet conditions, as well as lease stipulations. In certain areas on federal lands, drilling and other oil and natural gas activities can only be conducted during limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs, and could have a material adverse effect on our business, financial condition and results of operations.
See "Items 1 and 2: Business and Properties-Glossary of Abbreviations and Terms-Identified drilling locations".
As co-venturer in joint ventures, we are liable for various obligations of those joint ventures.
As a co-venturer, we are contingently liable for the obligations of the joint venture, including responsibility for day-to-day operations and liabilities which cannot be repaid from joint venture assets, insurance proceeds or indemnification by others. In the future, we might be exposed to litigation in connection with joint venture activities, or find it necessary to advance funds on behalf of joint ventures to protect the value of the natural gas and oil properties by drilling wells to produce undeveloped reserves or to pay lease operating expenses in excess of production. These activities may have a material adverse effect on our business, financial condition and results of operations.
Our role as co-venturer in joint ventures may result in conflicts of interest, which may not be resolved in our best interests or the best interests of our stockholders.
Our role as co-venturer in joint ventures may result in conflicts of interest between the interests of those entities and our stockholders. Any resolution of these conflicts may not always be in our best interests.
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 many of these persons.
We depend to a large extent on the efforts and continued employment of Norman F. Swanton, our chief executive officer and chairman, Timothy A. Larkin, our executive vice president and chief financial officer, Kenneth A. Gobble, our senior vice president of exploration and production, and other key management and technical personnel. We maintain key person life insurance on Messrs. Swanton, Larkin and Gobble but not on other key management and technical personnel.
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 do not insure against all potential operating risks. We may incur substantial losses and be subject to substantial liability claims as a result of various lawsuits.
We are not insured against all risks. We ordinarily maintain insurance against various losses and liabilities arising from our operations in accordance with customary industry practices and in amounts that management believes to be prudent. Losses and liabilities arising from uninsured and underinsured events or in amounts in excess of existing insurance coverage could have a material adverse effect on our business, financial condition or results of operations. Business disruptions could seriously harm our future revenue and financial condition and increase our costs and expenses. Our operations could be subject to earthquakes, power shortages, telecommunications failures, water shortages, floods, hurricanes, extreme weather conditions and other natural or manmade disasters or business interruptions, for which we are predominantly self-insured. The occurrence of any of these business disruptions could seriously harm our revenue and financial condition and increase our costs and expenses. Our Long Beach, California regional operations and a substantial portion of oil properties are located in southern California near major earthquake faults. Our revenues and income could be adversely affected if our operations in these locations are disrupted for any reason, including natural disasters, environmental, public health, or political issues. The ultimate impact on us of being located near major earthquake faults and being consolidated in certain geographical areas is unknown, but our revenue, profitability and financial condition could suffer in the event of a major earthquake or other natural disaster.
Our natural gas and oil exploration and production activities are subject to numerous hazards and risks associated with drilling for, operating, producing and transporting natural gas and oil, and any of these risks can cause substantial losses resulting from:
•environmental hazards, such as uncontrollable flows of natural gas, oil, brine water, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
•abnormally pressured formations and ground subsidence;
•mechanical difficulties, inadequate oil field drilling and service tools, and casing collapses;
•fires and explosions;
•personal injuries and death;
•labor and employment;
•regulatory investigations and penalties; and
•natural disasters, such as earthquakes, hurricanes and floods.
Any of these risks could have a material adverse effect on our ability to conduct operations or result in substantial losses to us. Many of these risks are not insured as the cost of available insurance, if any, is excessive. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs that is not fully covered by insurance, it could have a material adverse effect on our business, financial condition and results of operations. See "Business and Properties-Operating Hazards and Insurance".
We have limited control over activities on properties we do not operate, which could reduce our production and revenues.
A substantial amount of our business activities are conducted through joint operating or other agreements under which we own partial ownership or working interests in natural gas and oil properties. We do not operate all of the properties in which we have an interest and in many cases we do not have the ability to remove the operator in the event of poor performance. As a result, we have
a limited ability to exercise influence over normal operating procedures, expenditures or future development of underlying properties and their associated costs. The failure of an operator of our wells to adequately perform operations, or an operator's breach of the applicable agreements, could reduce our revenues and production. Therefore, the success and timing of our drilling and development activities on properties operated by others depends upon a number of factors outside of our and the operator's control, including:
•timing and amount of capital expenditures;
•expertise and financial resources;
•inclusion of other participants in drilling wells; and
•use of technology.
Defects in the title to any of our natural gas and oil interests could result in the loss of some of our natural gas and oil properties or portions thereof, or liability for losses resulting from defects in the assignment of leasehold rights.
We obtain interests in natural gas and oil properties with varying degrees of warranty of title, such as general, special or quitclaim or without any warranty. We acquired our interests in the Wilmington Townlot Unit in 1999 and 2005 with no title opinion as to the interests acquired, which may ultimately prove to be less than the interests we believe we own. The prior owner had acquired its interests from a third party that, in turn, had acquired its interest from Exxon Corporation with no warranty of title. Exxon had owned the Wilmington Townlot Unit for over 25 years before its sale in 1997. Similarly, when we acquired our interest in the North Wilmington Unit in December 2005, we had no title opinion prepared as to the interests acquired. The prior owner had owned the North Wilmington Unit for over 15 years, acquired the North Wilmington Unit from Sun Oil Corporation without warranty of title, which had owned unit for over 20 years before its sale in 1990. Losses of title to the Wilmington Townlot Unit or North Wilmington Units may result from title defects or from ownership of a lesser interest than we believe we acquired. In other instances, title opinions may not be obtained if in our discretion it would be uneconomical or impractical to do so. This increases the possible risk of loss and could result in total loss of title to some or all of the properties we purchased. Furthermore, in certain instances we may determine to purchase properties even though certain technical title defects exist if we believe it to be an acceptable risk under the circumstances.
Prospects that we decide to drill may not yield natural gas or oil in commercially viable quantities.
A prospect is a property on which we have identified what our geoscientists believe, based on available seismic and geological information, to be indications of natural gas or oil. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation. However, the use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling and testing whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in sufficient quantities to recover drilling or completion costs or to be economically viable. If we drill wells in our current and future prospects that are identified as non-economic or dry holes, our drilling success rate may decline and materially harm our business. In sum, the cost of drilling, completing and operating any wells is often uncertain and new wells may not be productive.
Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial, technological and other resources than we do, which may adversely affect our ability to compete.
We operate in highly competitive areas of oil and natural gas exploration, development and acquisition with a substantial number of other companies. We face intense competition from independent, technology-driven companies, as well as from both major and other independent oil and gas companies, in each of the following areas:
•acquiring desirable producing properties or new leases for future exploration;
•marketing our natural gas and oil production;
•integrating new technologies; and
•acquiring the equipment, personnel and expertise necessary to develop and operate our properties.
Many of our competitors have financial, managerial, technological and other resources substantially greater than ours. These companies may be able to pay more for exploratory prospects and productive oil and gas properties, and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. To the extent our competitors are able to pay more for properties than we are, we will be at a competitive disadvantage. Further, many of our competitors may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for natural gas and oil and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties, and consummate transactions in this highly competitive environment.
Shortages of rigs, equipment, supplies and personnel could delay or otherwise adversely affect our cost of operations or our ability to operate according to our business plans.
If domestic drilling activity increases, particularly in the fields in which we operate, a general shortage of drilling and completion rigs, field equipment and qualified personnel could develop. As a result, the costs and delivery times of rigs, equipment and personnel could be substantially greater than in previous years. From time to time, these costs have sharply increased and could do so again. The demand for and wage rates of qualified drilling rig crews generally rises in response to the increasing number of active rigs in service and could increase sharply in the event of a shortage. Although Warren owns a drilling rig for use in the WTU, shortages of drilling and completion rigs, field equipment or qualified personnel could delay, restrict or curtail our exploration and development operations, which could in turn harm our operating results.
Increases in taxes on energy sources may adversely affect the company's operations.
Federal, state and local governments which have jurisdiction in areas where the company operates impose taxes on the oil and natural gas products sold. Historically, there has been an on-going consideration by federal, state and local officials concerning a variety of energy tax proposals. Such matters are beyond the company's ability to accurately predict or control.
Risks Relating to Ownership of Our Common Stock
The number of shares eligible for future sale or which have registration rights could adversely affect the future market for our common stock.
Sales of substantial amounts of previously restricted shares of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common
stock to decline, or could impair our ability to raise capital through the sale of additional common or preferred stock.
As of December 31, 2010, we had 71,338,149 shares of common stock outstanding, 52,522 shares of common stock were issuable upon conversion of our convertible debt and convertible preferred stock, 3,541,703 shares of common stock were issuable upon exercise of outstanding options, and 28,373 shares of restricted stock are issuable upon vesting. Our directors and executive officers, hold approximately 4% of the outstanding shares of our common stock.
If our stockholders sell significant amounts of common stock in any public market that develops or exercise their registration rights and sell a large number of shares, the price of our common stock could be negatively affected. If we were to include shares held by those holders in a registration statement pursuant to the exercise of their registration rights, those sales could impair our ability to raise needed capital by depressing the price at which we could sell our common stock or impede such an offering altogether.
Our stock price has been and may be volatile, and your investment in our stock could decline in value.
In recent years, the stock market has experienced significant price and volume fluctuations. Our common stock has and may continue to experience volatility unrelated to our operating performance for reasons that include:
•domestic and worldwide supplies and prices of and demand for natural gas and oil;
•political conditions in natural gas and oil producing regions;
•the success of our operating strategy;
•war and acts of terrorism;
•demand for our common stock;
•revenue and operating results failing to meet the expectations of securities analysts or investors in any particular quarter or period;
•changes in expectations of our future financial performance, or changes in financial estimates, if any, of public market analysts;
•investor perception of our industry or our prospects;
•general economic trends;
•limited trading volume of our stock;
•changes in and compliance with environmental and other governmental rules and regulations;
•actual or anticipated quarterly variations in our operating results;
•our involvement in litigation;
•conditions generally affecting the oil and natural gas industry;
•the prices of oil and natural gas;
•announcements relating to our business or the business of our competitors;
•our liquidity; and
•our ability to obtain or raise additional funds.
Many of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. We cannot assure you that the market price of our common stock will not
fluctuate or decline significantly in the future. In addition, the stock markets in general can experience considerable price and volume fluctuations.
Control by our executive officers and directors may limit your ability to influence the outcome of matters requiring stockholder approval and could discourage our potential acquisition by third parties.
As of March 1, 2011, our executive officers and directors beneficially owned approximately 4% of our common stock. These stockholders, if acting together, would be able to influence significantly all matters requiring approval by our stockholders, including the election of our board of directors and the approval of mergers or other business combination transactions. This concentration of ownership could have the effect of delaying or preventing a change in our control or otherwise discourage a potential acquirer from attempting to obtain control of us, which in turn could have an adverse effect on the market price of our common stock or prevent our stockholders from realizing a premium over the market price for their shares of our common stock.
Provisions in our articles of incorporation, bylaws and Maryland law may make it more difficult to effect a change in control, which could adversely affect the price of our common stock.
Provisions of our articles of incorporation, bylaws and Maryland law could make it more difficult for a third party to acquire us, even if doing so would be beneficial to our stockholders. We may issue shares of preferred stock in the future without stockholder approval and upon such terms as our board of directors may determine. Our issuance of this preferred stock could have the effect of making it more difficult for a third party to acquire, or of discouraging a third party from acquiring, a majority of our outstanding stock and potentially prevent the payment of a premium to stockholders in an acquisition.
Our articles of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us or our management. These provisions include:
•giving the board the exclusive right to fill all board vacancies;
•providing that special meetings of stockholders may only be called by the board pursuant to a resolution adopted by
-a majority of the board, either upon a motion or upon written request by holders of at least 662/3% of the voting power of the shares entitled to vote, or
-by our president;
•a classified board of directors;
•permitting removal of directors only for cause and with a super-majority vote of the stockholders;
•prohibiting cumulative voting in the election of directors; and
•granting existing shareholders certain rights in the event of an unsolicited take-over offer, unless the offeror receives approval of the board of directors.
These provisions also could discourage proxy contests and make it more difficult for our stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, and may limit the price that investors are willing to pay in the future for shares of our common stock.
We are also subject to provisions of the Maryland General Corporation Law that prohibit business combinations with persons owning 10% or more of the voting shares of a corporation's outstanding stock, unless the combination is approved by the board of directors prior to the person owning 10% or
more of the stock, for a period of five years, after which the business combination would be subject to special stockholder approval requirements. This provision could deprive our stockholders of an opportunity to receive a premium for their common stock as part of a sale of our company, or may otherwise discourage a potential acquirer from attempting to obtain control from us, which in turn could have a material adverse effect on the market price of our common stock. See "Description of Capital Stock".
We have not paid cash dividends on our common stock and do not anticipate paying any dividends on our common stock in the foreseeable future.
Under the terms of our convertible preferred stock, we may not pay dividends on our common stock unless all accrued dividends on our convertible preferred stock have been paid. We anticipate that we will retain all future earnings and other cash resources for the future operation and development of our business. Accordingly, we do not intend to declare or pay any cash dividends on our common stock in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our operating results, financial conditions, current and anticipated cash needs and plans for expansion.
We make estimates and assumptions in connection with the preparation of Warren's Consolidated Financial Statements, and any changes to those estimates and assumptions could have a material adverse effect on our results of operations.
In connection with the preparation of Warren's Consolidated Financial Statements, we use certain estimates and assumptions based on historical experience and other factors. Our most critical accounting estimates are described in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report. In addition, as discussed in Note A to the Consolidated Financial Statements, we make certain estimates, including decisions related to provisions for legal proceedings and other contingencies. While we believe that these estimates and assumptions are reasonable under the circumstances, they are subject to significant uncertainties, some of which are beyond our control. Should any of these estimates and assumptions change or prove to have been incorrect, it could have a material adverse effect on our results of operations.
Failure of the Company's internal control over financial reporting could harm its business and financial results.
The management of Warren is responsible for establishing and maintaining effective internal control over financial reporting. Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes maintaining records that in reasonable detail accurately and fairly reflect the Company's transactions; providing reasonable assurance that transactions are recorded as necessary for preparation of the financial statements; providing reasonable assurance that receipts and expenditures are made in accordance with management authorization; and providing reasonable assurance that unauthorized acquisition, use or disposition of the Company assets that could have a material effect on the financial statements would be prevented or detected on a timely basis. Because of its inherent limitations, internal control over financial reporting is not intended to provide absolute assurance that a misstatement of the Company's financial statements would be prevented or detected. Failure to maintain an effective system of internal control over financial reporting could limit the Company's ability to report its financial results accurately and timely or to detect and prevent fraud.
Item 1B:
Item 1B: Unresolved Staff Comments.
Not applicable.
Item 3:
Item 3: Legal Proceedings
Information with respect to this item may be found in Note F to the Consolidated Financial Statements in Item 8, which is incorporated herein by reference.
Item 4:
Item 4: Submission of Matters to a Vote of Security Holders
Not applicable.
PART II
Item 5:
Item 5: Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information.
Our common stock is listed on the NASDAQ Global Market under the symbol "WRES".
The following table sets forth, for the period indicated, the high and low sales prices for our common stock as reported by the NASDAQ Global Market:
On March 1, 2011, the closing sales price for our common stock as reported by the NASDAQ Global Market was $4.81 per share.
Holders
As of March 1, 2011 there were approximately 2,300 holders of our common stock.
Dividend Policy
We have never paid or declared any cash dividends on our common stock. We currently intend to retain earnings, if any, to finance the growth and development of our business and we do not expect to pay any cash dividends on our common stock in the foreseeable future. Payment of future cash dividends, if any, will be at the discretion of our board of directors after taking into account various factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion.
Stockholder Return Performance Presentation
The following performance graph compares the performance of the Company's common stock to the S&P 500 Index, and to the Dow Jones U.S. Oil & Gas Index for each year since December 31, 2004, which is a composite index consisting of 77 U.S. oil and gas companies that includes integrated major oil and gas companies as well as smaller independent U.S. companies. The graph also shows the performance of the Company's stock for the same five-year period to our peer group of companies consisting of Quicksilver Resources, Inc., Bill Barrett Corporation, St. Mary Land & Exploration, Berry Petroleum, Petroleum Development Corporation and Brigham Exploration, which companies have market capitalizations similar to Warren and are primarily involved in domestic U.S. exploration and production. The graph assumes that the value of the investment in the Company's common stock and each index was $100 at December 31, 2004, and that all dividends were reinvested.
Fiscal Year Ended December 31
Total Return Data Provided by S&P's Institutional Market Services and Dow Jones & Company, Inc.
Securities Authorized for Issuance Under Compensation Plans
The table below includes information about our equity compensation plans as of December 31, 2010, each of which has been approved by our stockholders:
Recent Sales of Unregistered Securities
There were no unregistered sales of equity securities in fiscal 2010.
Issuer Purchases of Equity Securities
The Company did not repurchase any of its equity securities in the fourth quarter of 2010.
Item 6:
Item 6: Selected Consolidated Financial Data
The following tables present selected financial and operating data for Warren and its subsidiaries as of and for the periods indicated. You should read the following selected data along with "Item 7:
Item 7: Management's Discussion and Analysis of Financial Condition and Results of Operations
The discussion and analysis that follows should be read together with the "Selected Consolidated Financial Data" and the accompanying financial statements and notes related thereto that are included elsewhere in this annual report. It includes forward-looking statements that may reflect our estimates, beliefs, plans and expected performance. The forward-looking statements are based upon events, risks and uncertainties that may be outside our control. Our actual results could differ significantly from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include but are not limited to, market prices for natural gas and oil, regulatory changes, estimates of proved reserves, economic conditions, competitive conditions, development success rates, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this annual report, including in "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements", all of which are difficult to predict. As a result of these assumptions, risks and uncertainties, the forward-looking matters discussed may not occur.
Overview
We are an independent energy company engaged in the exploration and development of domestic onshore oil and natural gas reserves. We focus our efforts primarily on our waterflood oil recovery programs and horizontal drilling in the Wilmington field within the Los Angeles Basin of California and on the exploration and development of coalbed methane ("CBM") properties located in the Rocky Mountain region. As of December 31, 2010, we owned natural gas and oil leasehold interests in approximately 135,904 gross (72,996 net) acres, approximately 80% of which are undeveloped. Substantially all our undeveloped acreage is located in the Rocky Mountains. Our total net proved reserves are located on less than 20% of our net acreage.
From our inception in 1990 through 2003, we functioned principally as the sponsor of privately placed drilling programs and joint ventures. Under these programs, we contributed drilling locations, paid tangible drilling costs and provided turnkey drilling services, natural gas marketing services and well services to the drilling programs and the Company retained an interest in the wells. Historically, a substantial portion of our revenue was attributable to these turnkey drilling services. After our initial public offering in 2004, the Company has transitioned from being the sponsor of privately placed drilling programs to becoming a more traditional exploration and production company. During the second quarter of 2007, the Company changed its accounting method for oil and gas properties from the successful efforts method to the full cost method. As a result of this accounting change, turnkey profit, well services profit and marketing profit are not recognized on the statement of operations but are recorded as reductions to the full cost pool. All historical information included in this Form 10-K has been retroactively restated to give effect to the change in accounting method.
Liquidity and Capital Resources
Our cash and cash equivalents decreased $6.1 million during 2010 to $11.1 million at December 31, 2010. This resulted from cash provided by operating activities of $45.3 million offset by cash used in investing activities of $29.1 million and cash used in financing activities of $22.4 million.
Cash provided by operating activities was primarily generated by oil and gas operations. Cash used in investing activities was primarily spent on oil and gas properties and equipment. Cash used in financing activities primarily represented the Company reducing its debt under the Credit Facility.
The Company recorded no impairment expense at December 31, 2010 and 2009. The Company recorded impairment expense of $272.3 million at December 31, 2008 relating to its ceiling test on the carrying costs of its oil and gas properties. This resulted primarily from realized oil prices decreasing 62% from $86.21 at December 31, 2007 to $32.92 at December 31, 2008. Additionally, the Company wrote off approximately $3.4 million of goodwill during 2008. This goodwill resulted from the acquisition of our wholly owned subsidiary Warren E&P, Inc. in 2000. The methodology for testing the carrying value of goodwill was by comparing the market value of the Company to the net assets of the Company. As a result of a significant decline in the market value of Warren E&P, Inc. in the fourth quarter of 2008, it was determined that an impairment of this goodwill had occurred.
On November 19, 2007, Warren entered into a five year, $250 million credit agreement with Merrill Lynch Capital on behalf of itself and a syndicate of five participating banks (the "Credit Facility"). The Credit Facility provides for a revolving loan up to the lesser of (i) the borrowing base (ii) $250 million or (iii) the draw limit requested by the Company. The Credit Facility matures on November 19, 2012. It is secured by substantially all of our assets. The borrowing base will be determined by the lenders at least semi-annually on or about April 1 and October 1 of each year, and is based in part on the proved reserves of the Company. Interest payments are made quarterly in arrears. The current borrowing base is $120 million. The Company is subject to certain covenants required by the Credit Facility which include, but are not limited to the maintenance of the following financial ratios (1) a minimum current ratio (including the unused borrowing base and current assets) of not less than 1.0 to 1.0 and (2) a minimum annualized consolidated EBITDAX (as defined by the Credit Facility) to net interest expense of not less than to of 2.5 to 1.0. As of December 31, 2010, the Company had borrowed $69.5 million under the Credit Facility and was in compliance with all covenants. If oil and gas commodity prices were to decline to lower levels, the Company may become in violation of Credit Facility covenants in the future. If the Company fails to satisfy its Credit Facility covenants, it would be an event of default. Under such event of default and upon notice, all borrowings would become immediately due and payable to the lending banks.
Depending on the current level of borrowing base usage, the annual interest rate on each base rate borrowing under the Credit Facility will be at our option either: (a) a "Base Rate Loan", or any other Obligation other than a LIBOR Loan, which has an interest rate equal to the sum of the "Base Rate" plus the applicable "Base Rate Margin", calculated to be the higher of (i) the Agent's prime rate of interest announced from time to time, or (ii) the Federal Funds rate most recently determined by the Agent, plus 3.0% per annum, plus an applicable margin that ranges from 1.5% to 2.25%, or (b) a "LIBOR Loan", which has an interest rate equal to the sum of the applicable LIBOR period plus the applicable "LIBOR Margin", that ranges from 2.75% to 3.50%. During 2010, the Company incurred $3.5 million of interest expense under the Credit Facility of which approximately $0.1 million was accrued for as of December 31, 2010. The weighted average interest rate as of December 31, 2010, was 3.4%.
Our operations are affected by local, national and worldwide economic conditions. We have relied on the capital markets, particularly for equity securities, as well as the banking and debt markets, to meet financial commitments and liquidity needs if internally generated cash flow from operations is not adequate to fund our capital requirements. Capital markets in the United States and elsewhere have been experiencing extreme adverse volatility and disruption for more 2 years, due in part to the financial stresses affecting the liquidity of the banking system, the real estate mortgage industry and the financial markets generally. During the past 15 months, this volatility and disruption has been reduced. As a result, our access to capital has improved as evidenced by our $29 million equity offering during October 2009.
If oil commodity prices were to drop precipitously and gas commodity prices go lower, the Company may not have enough liquidity to cover capital expenditures. The availability of funds under our Credit Facility is critical to our Company. The borrowing base is to be redetermined on or about April 1, 2011. If the Credit Facility's borrowing base is reduced to a level below current borrowings, the Company would be obligated to begin reducing the deficiency by 25% within 90 days after the deficiency occurs and the remaining 75% within 180 days after the deficiency occurs.
Low commodity prices may restrict our ability to meet our current obligations. As a result, Management has taken several actions to ensure that the Company will have sufficient liquidity to meet its obligations through December 31, 2011, including a 2011 capital expenditure budget which is expected to be funded primarily by discretionary cash flow, entered into price swap agreements, collars and differential swap agreements for a portion of its 2011 production to reduce price volatility and reductions in discretionary expenditures. As of February 1, 2011, approximately 30% of the Company's natural gas production and 55% of the Company's oil production are covered by price swaps. If the liquidity of the Company should worsen, the Company would evaluate other measures to further improve its liquidity, including, the sale of equity or debt securities, entering into joint ventures with third parties, additional commodity price hedging and other monetization of assets strategies. There is no assurance that the Company would be successful in these capital raising efforts if they became necessary to fund operations during 2011.
During 2010, the Company had net income of $20.4 million (of which $1.2 million represented an unrealized loss on derivative financial instruments). This compares to 2009 when the Company incurred a net loss of $13.8 million (of which $9.5 million represented an unrealized loss on derivative financial instruments) and a net loss of $241.7 million in 2008 (which resulted primarily from impairment charges of $275.7 million relating to its oil and gas properties and goodwill). At December 31, 2010, current assets were approximately $12.9 million less than current liabilities. Currently, the Company has a borrowing base of $120 million and $69.5 million outstanding under the Credit Facility.
In the future, if natural gas inventories rise to levels such that no natural gas storage capacity exists, certain U.S. natural gas production will need to be reduced or shut in. Additionally, if commodity prices decline to levels that make it uneconomic to produce oil and natural gas, the Company or its partners may elect to shut in or reduce production. As a result, some or all of the Company's oil and natural gas production may be shut in or curtailed during the next 12 months, which would have a material adverse effect on operations.
The Company's proved reserves increased as of December 31, 2010 compared to prior years. The 2010 increase was primarily due to 2010 drilling activities and higher commodity prices. At year-end 2008, we had revised our proved oil reserves downward by a total of 42,685 MBbls as follows: Due to a significant decrease in realized oil prices from $86.21 per barrel at December 31, 2007 to $32.92 per barrel at December 31, 2008, 20,210 MBbls of proved undeveloped oil reserves in the WTU property and 18,360 MBbls of proved undeveloped oil reserves in the NWU property were deemed non-economic and revised downward at year-end 2008. Also, due to lower realized oil prices, 755 MBbls of proved developed producing oil reserves in the NWU were revised downward at year-end 2008. As a result of these revisions, all of the proved oil reserves in the NWU were eliminated at year-end 2008. In addition, 3,360 MBbls of proved developed producing oil reserves in the WTU were revised downward primarily due to the decrease in realized oil prices, and, to a lesser extent, due to downward revisions to estimated oil recoveries in the WTU Upper Terminal and Ranger waterflood projects. Lower prices decrease the economic lives of the underlying oil and natural gas properties and thereby decrease the estimated future reserves. The Company's projects have material lease operating expenses. Our oil operations include a secondary recovery waterflood with significant fixed costs. During 2010, our oil lease operating expenses were $17.29 per barrel of oil produced. Our natural gas operations include reinjecting the produced water into deep formations and compressing and transporting the gas with significant fixed costs. During 2010, our natural gas lease operating expenses
were $2.60 per mcf of gas produced. The Company's proved reserves are based on assumptions that may prove to be inaccurate. The Company's proved reserves as of December 31, 2008 through December 31, 2010 are listed below.
2010 Capital Expenditure Program
At the present time, we are concentrating our activities in California and Wyoming. We have two California projects in the Wilmington field, the Wilmington Townlot Unit and the North Wilmington Unit. Additionally, we have a drilling project in Wyoming referred to as the Atlantic Rim Project.
During 2010, our capital expenditure program approximated $37.5 million. The Company drilled 10 wells in California (9 producers and 1 injector). The costs associated with the new oil wells in California wells were approximately $15.2 million and the facility costs were approximately $4.7 million. The Company purchased a sound-proofed drilling rig for our WTU and NWU units in California for $7 million and incurred $2.5 million of assembly costs in 2010. The Company estimates that an additional $2.5 million will be spent on improvements and assembly costs in 2011. Additionally, the Company stimulated 15 wells in the Doty Mountain Unit and 15 wells in the Sun Dog Unit in the Atlantic Rim Project. These stimulations cost approximately $3.1 million in total. Additionally, infrastructure costs for the gas wells in Wyoming approximated $3.4 million. Lastly, the Company had property acquisitions of approximately $1.6 million.
If the Company elects not to participate in drilling activities with its partners, it may lose all or a portion of its mineral leases and rights in certain acreage. As a result, our proved reserves may decline. Also, unless we continue to develop our properties, production may decline and, as a result, reserves would decline. Lastly, complex federal, state and local laws and regulations may adversely affect the cost and feasibility of drilling and completion activities. In our California operations, regulations involving the disposition of water and produced natural gas associated with oil production will result in the Company voluntarily curtailing 2011 oil production and could result in more material reductions of oil production in the future.
Our 2011 capital expenditure budget is forecasted to be approximately $59 million, $41 million for our California projects and $18 million for our Wyoming projects. However, our budget may change depending upon economic conditions, oil and gas prices and liquidity issues. In California, we are budgeting approximately $28 million for drilling new WTU sinusoidal wells and reworking existing WTU wells, $13 million for infrastructure and geological costs in the WTU and NWU. In Wyoming, we are budgeting $16 million for drilling new natural gas wells and one oil well in Niobrara formation and $2 for pipelines, compressors and infrastructure costs in our Atlantic Rim Project. The final determination regarding whether to drill and complete the budgeted wells and incur the capital expenditures referred to above is dependent upon many factors including, but not limited to:
•the availability of sufficient capital resources;
•the ability to acquire proper governmental permits and approvals; and
•economic and industry conditions at the time of drilling such as prevailing and anticipated crude oil and natural gas prices and the availability of drilling equipment.
A substantial portion of our economic success depends on factors over which we have no control, including oil and natural gas prices, operating costs, and environmental and other regulatory matters. In our planning process, we focus on maintaining financial flexibility and maintaining a low cost structure in order to reduce our vulnerability to these uncontrollable factors.
See "Item 1A: Risk Factors" for additional risks and factors which could have a material adverse effect on our business, financial condition and results of operations.
Stock Based Equity Compensation Plan Information
At December 31, 2010, we had approximately 1.3 million vested outstanding stock options issued under our stock based equity compensation plans. Of the total 1.3 million outstanding vested options, 0.3 million had exercise prices below the closing market price of our common stock on December 31, 2010 of $4.52.
For additional detail about our stock based equity compensation plans, see "Executive Compensation-Employee Benefit Plans" under Item 11 and as incorporated by reference from our Proxy Statement on Schedule 14A.
Critical Accounting Estimates
The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. 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. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. Below, we provide expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Notes to the Consolidated Financial Statements for a discussion of additional accounting policies and estimates made by management.
Oil and Gas Producing Activities
We account for our oil and gas activities using the full cost method. As prescribed by full cost accounting rules, all costs associated with property acquisition, exploration and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of oil and gas properties as well as other internal costs that can be specifically identified with acquisition, exploration and development activities are also capitalized. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The sum of net capitalized costs and estimated future development and dismantlement costs are depleted on the equivalent unit-of-production method, based on proved oil and gas reserves as determined by independent petroleum engineers.
In accordance with full cost accounting rules, Warren is subject to a limitation on capitalized costs. The capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization, may not exceed the estimated future net cash flows from proved oil and gas reserves discounted at 10 percent, plus the cost of unproved properties excluded from amortization, as adjusted for related tax effects. If capitalized costs exceed this limit (the "ceiling limitation"), the excess must be charged to expense. Warren recorded a $272 million ceiling test adjustment to earnings at December 31, 2008. There was no impairment charge in 2010 and 2009.
The costs of certain unevaluated oil and gas properties and exploratory wells being drilled are not included in the costs subject to amortization. Warren assesses costs not being amortized for possible impairments or reductions in value and if impairments or a reduction in value has occurred, the portion of the carrying cost in excess of the current value is transferred to costs subject to amortization.
Our estimate of proved reserves is based on the quantities of oil and gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows are derived from these reserve estimates, in accordance with SEC guidelines by an independent engineering firm based in part on data provided by us. The accuracy of our reserve estimates depends in part on the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.
Revenue Recognition
Oil and gas sales result from undivided interests held by us in various oil and gas properties. Sales of natural gas and oil produced are recognized when delivered to or picked up by the purchaser. Warren accrues for revenue based on estimated pricing and production.
Recent Accounting Pronouncements
In January 2010, the Financial Accounting Standards Board ("FASB") issued new guidance and clarifications for improving disclosures about fair value measurements. This guidance requires enhanced disclosures regarding transfers in and out of the levels within the fair value hierarchy. Separate disclosures are required for transfers in and out of Level 1 and 2 fair value measurements, and the reasons for the transfers must be disclosed. The new disclosures and clarifications of existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009. The adoption of this guidance did not have any effect on the financial statements.
Results of Operations
Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009
Oil and gas sales. Revenue from oil and gas sales increased $24.9 million during 2010 to $88.3 million, a 39% increase compared to 2009. This increase primarily resulted from an increase in oil production and an increase in realized oil prices. Net oil production for 2010 and 2009 was 969 Mbbls and 953 Mbbls, respectively. Net gas production for 2010 and 2009 was 4.7 Bcf and 3.9 Bcf, respectively. Additionally, the average realized price per barrel of oil for 2010 and 2009 was $71.47 and $53.93, respectively. The average realized price per Mcf of gas for 2010 and 2009 was $4.09 and $3.09, respectively.
Lease operating expense. Lease operating expense for 2010 increased 6% to $28.8 million ($16.54 per Boe) compared to $27.1 million ($16.93 per Boe) in 2009. Oil lease operating expense increased on a per barrel basis from $16.22 in 2009 to $17.29 per barrel in 2010. This resulted from higher costs associated with oil wells that were plugged and abandoned during 2010. Gas lease operating expense decreased on a per mcf basis from $3.00 in 2009 to $2.60 per mcf in 2010. This resulted from a reduction in the number of gas wells that required workover procedures during 2010.
Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased $1.4 million for 2010 to $22 million, a 7% increase compared to last year. This increase resulted from increased production in 2010 compared to 2009. The 2010 depletion rate decreased to $12.61 per Boe compared to $12.88 per Boe in 2009. The decrease in depreciation, depletion and amortization on a per barrel basis resulted from an increase in proved reserves at December 31, 2010 compared to December 31, 2009.
General and administrative expenses. General and administrative expenses increased $2.7 million in 2010 to $15.4 million, a 21% increase compared to 2009. This reflects an increase in the 2010 year end incentive compensation plan of $2.6 million. Additionally, the employer portion of taxes relating to vesting stock increased $0.6 million and stock option expense increased $0.5 million during 2010. These increases were offset by a decrease in litigation expense of $1.3 million during 2010 primarily relating to the Gotham litigation discussed in more detail in Note F to the financial statements-Commitment and Contingencies.
Interest expense. Interest expense decreased $2.4 million in 2010 to $3.5 million compared to 2009. The decrease results from a lower average balance outstanding under our Credit Facility during 2010 compared to 2009.
Interest and other income. Interest and other income increased $0.1 million in 2010 to $0.2 million, a 39% increase compared to the same period in 2009. This increase represents an increase in the sale of scrap inventory during 2010.
Gain (loss) on derivative financial instruments. Derivative gains of $1.5 million were recorded in 2010. This amount reflects $2.7 million of realized gains and $1.2 million of unrealized losses resulting from mark to market accounting of our oil and gas derivative positions. Derivative losses of $11.0 million were recorded in 2009. This amount reflects $1.5 million of realized losses and $9.5 million of unrealized losses resulting from mark to market accounting of our oil and gas swaps positions.
Income taxes. We recognize a deferred tax liability or asset for temporary differences, operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards net of a valuation allowance. The temporary differences consist primarily of depreciation, depletion and amortization of intangible and tangible drilling costs and unrealized gains on investments.
As of December 31, 2010, we had a net operating loss carryforward for federal income tax purposes of approximately $220 million. Also as of December 31, 2010, we have provided a 100% valuation allowance on our net deferred tax assets. Our net operating loss carryforwards begin to expire in 2012 and subsequent years.
Results of Operations
Year Ended December 31, 2009 Compared to the Year Ended December 31, 2008
Oil and gas sales. Revenue from oil and gas sales decreased $44.6 million during 2009 to $63.4 million, a 41% decrease compared to 2008. This decrease resulted from a decrease in realized oil and gas prices. The average realized price per barrel of oil for 2009 and 2008 was $53.93 and $88.65, respectively. Additionally, the average realized price per Mcf of gas for 2009 and 2008 was $3.09 and $6.28, respectively. Net oil production for 2009 and 2008 was 953 Mbbls and 1,011 Mbbls, respectively. Net gas production for 2009 and 2008 was 3.9 Bcf and 2.9 Bcf, respectively.
Lease operating expense. Lease operating expense for 2009 decreased 13% to $27.1 million ($2.82 per Mcfe) compared to $31.1 million ($3.45 per Mcfe) in 2008. Primarily, this decrease reflects reduced lease operating expenses in our Atlantic Rim Project resulting from shutting in uneconomic wells and reduced workovers on wells. Additionally, this decrease resulted from reduced field expenses in our California oil properties.
Impairment. The Company recorded impairment expense of $272 million at December 31, 2008 relating to its ceiling test write down of oil and gas properties. This resulted from realized oil prices decreasing 62% from $86.21 at December 31, 2007 to $32.92 at December 31, 2008. As a result, many of our proved undeveloped oil reserves became uneconomic at this oil price. In addition, the Company recorded $3.4 million of goodwill impairment expense. This goodwill related to the acquisition of the Company's wholly owned subsidiary Warren E&P, Inc.
Depreciation, depletion and amortization. Depreciation, depletion and amortization expense decreased $3.4 million for 2009 to $20.6 million, a 14% decrease compared to last year. This decrease reflects a net increase in replaced proved reserves in 2009 after factoring in 2009 production. The 2009 depletion rate decreased to $2.15 per mcfe compared to $2.66 per mcfe in 2008. Depreciation, depletion and amortization expense was impacted by the change in the SEC's pricing rules from the use of year end prices to 12-month average prices, which resulted in negative reserve revisions at December 31, 2009. This resulted in an increase in fourth quarter depreciation, depletion and amortization expense of approximately $0.4 million.
General and administrative expenses. General and administrative expenses decreased $2.1 million in 2009 to $12.6 million, a 14% decrease compared to 2008. This reflects a decrease in personnel as a result of cost cutting activities. These decreases were offset by a $1.3 million additional accrual related to Gotham litigation discussed in more detail in Note F to the financial statements-Commitment and Contingencies.
Interest expense. Interest expense increased $0.6 million in 2009 to $5.9 million compared to 2008. The increase results from a higher average balance outstanding under our Credit Facility during 2009 compared to 2008.
Interest and other income. Interest and other income decreased $0.8 million in 2009 to $0.2 million, an 83% decrease compared to the same period in 2008. This represents a decrease in interest earned due to lower cash and cash equivalents balances and lower interest rates as compared to the corresponding period last year.
Loss on derivative financial instruments. Derivative losses of $11.0 million were recorded in 2009. This amount reflects $1.5 million of realized losses and $9.5 million of unrealized losses resulting from mark to market accounting of our oil and gas swaps positions.
Income taxes. We recognize a deferred tax liability or asset for temporary differences, operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards net of a valuation allowance. The temporary differences consist primarily of depreciation, depletion and amortization of intangible and tangible drilling costs and unrealized gains on investments and our investment basis in oil and gas partnerships.
As of December 31, 2009, we had a net operating loss carryforward of approximately $199 million. Also as of December 31, 2009, we have provided a 100% valuation allowance on our net deferred tax assets. Our net operating loss carryforwards expire in 2012 and subsequent years.
Debentures
As of December 31, 2010, we had $1.7 million of convertible secured debentures that are convertible into our common shares. Further, all convertible secured debentures are callable by us if the average bid price of our public traded common shares traded at 133% or greater of the respective conversion price of the debentures for at least 90 consecutive trading days. In such an event, debentures not converted may be called by us upon 60 days notice at a price of 100% of par value plus accrued interest.
The principal of the convertible secured debentures is secured at maturity by zero coupon U.S. treasury bonds previously deposited into an escrow account equaling the par value of the debentures maturing on or before the due date of the debentures. The fair market value of these securities at December 31, 2010 was approximately $1.1 million.
The table below reflects the outstanding convertible secured debentures by issue, the fair market value of the zero coupon U.S. treasury bonds held in escrow on behalf of the debentures holders and the estimated cash outlay for the payment of debenture interest for 2011. The conversion prices listed below will increase in the future.
Preferred Stock
As of December 31, 2010, we had 10,703 shares of convertible preferred stock issued and outstanding. During 2010, no shares of our convertible preferred stock converted into common shares on a 1 to 0.5 basis. Dividends and accretion on preferred shares totaled approximately $18,000 and $0.1 million for the years ended December 31, 2010 and 2009, respectively.
All of our outstanding preferred stock has a dividend equal to 8% per annum, payable to the extent legally available quarterly in arrears, and has a liquidation preference of $12.00 per share. Any accrued but unpaid dividends shall be cumulative and paid upon liquidation, optional redemption or conditional repurchase. No dividends may be paid on the common stock as long as there are any
accrued and unpaid dividends on the preferred stock. Commencing July 1, 2006 and thereafter, at the election of the holder of our convertible preferred stock, each share of preferred stock is convertible into 0.50 share of common stock.
The conversion rate for our convertible preferred stock is subject to adjustment in the event of:
•the issuance of common stock as a dividend or distribution on any class of our capital stock;
•the combination, subdivision or reclassification of the common stock; or
•the distribution to all holders of common stock of evidences of indebtedness or assets, including securities issued by third parties, but excluding cash dividends or distributions paid out of surplus.
Commencing seven years after their respective date of issuance, the preferred stock may be redeemed by the holders at a redemption price equal to the liquidation value of $12.00 per share, plus accrued but unpaid dividends, if any. At December 31, 2010, there were 10,703 preferred shares outstanding that the Company may be required to redeem.
Upon receipt of a redemption election, we, at our option, shall either:
•pay the holder cash in an amount equal to $12.00 per convertible preferred share, subject to adjustment for stock splits, stock dividends or stock exchanges, plus accrued and unpaid dividends, to the extent that we have funds legally available for redemption, or
•issue to the holder shares of common stock in an amount equal to 125% of the cash redemption price and any accrued and unpaid dividends, based on the average of the closing sale prices of our common stock for the 30 trading days immediately preceding the date of the receipt of the written redemption election by the holder, as reported by the NASDAQ Stock Market, or by any exchange or electronic OTC listing service on which the shares of common stock are then traded. In the event that we elect to pay the Redemption Price in kind with our common stock, for the 10,703 shares of preferred stock representing $0.1 million of Redemption Price value, notwithstanding the market price of our common stock, we shall not issue to the redeeming preferred stockholders less than their proportionate share of 10,703 shares of our shares of common stock, nor be obligated to issue more than 16,055 shares of our common stock in full satisfaction of the redemption, subject to adjustment for stock splits, stock dividends and stock exchanges.
If we are not listed on an exchange or our common stock has no trading volume, upon redemption the Board shall determine the fair market value of the common stock.
If the closing sale price of our publicly traded common stock as reported by the NASDAQ Stock Market, or any exchange or electronic OTC listing service on which the shares of common stock are then traded, exceeds 133% of the conversion price then in effect for the preferred stock for at least 10 trading days during any 30-day period, we, at our option, may either:
•redeem the preferred stock in whole or in part, at a redemption price of $12.00 per share plus accrued and unpaid dividends, or
•convert the preferred stock, plus any accrued and unpaid dividends, into common stock at the then applicable conversion rate, based on the average closing sale prices of our common stock for the 30 trading days immediately preceding the date fixed for redemption.
In addition, the preferred stock, plus accrued and unpaid dividends, shall be converted into common stock at the then applicable conversion rate upon the vote or written consent of the holders of 662/3% of the then outstanding preferred stock, voting together as a class.
Accordingly, if the holders of any of the outstanding shares of our preferred stock request redemption and thereafter and we elect to pay the Redemption Price for the preferred stock in cash, we would need capital of $12.00 per share, plus the amount of any accrued but unpaid dividends, which funds may not be available and the payment of which could have a material adverse effect on our financial liquidity and results of operation. Alternatively, if we elect to pay the Redemption Price for the preferred stock and thereafter with shares of our common stock, such issuance could materially increase the number of our shares of common stock then outstanding and be dilutive to our earnings per share, if any.
Contractual Obligations
The contractual obligations table below assumes the maximum amount is tendered each year. The table does not give effect to the conversion of any bonds to common stock which would reduce payments due. All bonds are secured at maturity by zero coupon U.S. treasury bonds deposited into an escrow account equaling the par value of the bonds maturing on or before the maturity of the bonds. Such U.S. treasury bonds had a fair market value of approximately $1.1 million at December 31, 2010. The table below does not reflect the release of escrowed U.S. treasury bonds to us upon redemption.
*Does not include estimated interest of $2.6 million less than one year, $2.5 million 1-3 years, $0.4 million 3-5 years and $1.2 million thereafter.
Off-Balance Sheet Arrangements
The Company does not have any off-balance sheet arrangements.
Item 7A:
Item 7A: Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in natural gas and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Risk
Our primary market risk exposure is in the price we receive for our natural gas and oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the
future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.
In 2010 we entered into several commodity derivative contracts to hedge our exposure to commodity price risk associated with anticipated future oil and gas production. We are required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the fixed price is below the settlement price. We believe we will have more predictability of our crude oil and gas revenues as a result of these derivative contracts.
The following table summarizes our open financial derivative positions as of March 1, 2011 related to oil and gas production. The Company will receive prices as noted in the table below and will pay a counterparty market price based on the NYMEX (for natural gas production) or WTI (for oil production) index price, settled monthly.
*The Company paid $685,000 in net premiums for these calls.
**This represents a differential spread between NYMEX and CIG pricing.
Interest Rate Risk
We hold investments in U.S. treasury bonds available for sale, which represents securities held in escrow accounts on behalf of the drilling programs and purchasers of certain debentures. Occasionally, we hold U.S. treasury bonds trading securities, which predominantly represent U.S. treasury bonds released from escrow accounts. The fair market value of these securities will generally increase if the federal discount rate decreases and decrease if the federal discount rate increases. All of our convertible debt has fixed interest rates, so consequently we are not exposed to cash flow or fair value risk from market interest rate changes on this debt.
At December 31, 2010, we had debt outstanding under our Credit Facility of $69.5 million. Depending on the current level of borrowing base usage, the annual interest rate on each base rate borrowing under the Credit Facility will be at our option either: (a) the higher of (i) the Agent's prime
rate of interest announced from time to time, or (ii) the Federal Funds rate most recently determined by the Agent, plus 0.5% per annum, plus an applicable margin that ranges from 0.25% to 1.0%, or (b) a Eurodollar Loan rate plus an applicable margin that ranges from 1.25% to 2.0%. During 2010, the Company incurred $3.1 million of interest under the Credit Facility of which approximately $0.1 million of interest was accrued for at December 31, 2010. At December 31, 2010, the weighted average interest rate on our Credit Line was 3.4%. A 1% increase in this rate would result in annual additional interest of $0.7 million.
Financial Instruments
Our financial instruments consist of cash and cash equivalents, U.S. treasury bonds, collateral security accounts, derivatives and other long-term liabilities. The carrying amounts of cash and cash equivalents and U.S. treasury bonds approximate fair market value due to the highly liquid nature of these short-term instruments or they are reported at fair value. Debentures, derivatives, other long-term liabilities and the Credit Line are recorded at the approximate fair value of such items.
Inflation and Changes in Prices
The general level of inflation affects our costs. Salaries and other general and administrative expenses are impacted by inflationary trends and the supply and demand of qualified professionals and professional services. Inflation and price fluctuations affect the costs associated with exploring for and producing natural gas and oil, which have a material impact on our financial performance.
Item 8:
Item 8: Financial Statements and Supplementary Data
See Report of Independent Registered Public Accounting Firm and Audited Financial Statements at Item 15.
Item 9:
Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A:
Item 9A: Controls and Procedures
Disclosure Controls and Procedures.
We maintain controls and procedures designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Evaluations have been performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon those evaluations, management, including the Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2010 to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms.
Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These
inherent limitations include the realties that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives and the Chief Executive Officer and the Chief Financial Officer, as of December 31, 2010, have concluded that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.
Management's Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. As defined in Exchange Act Rule 13a-15(f), internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer and effected by our 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 purposes in accordance with generally accepted accounting principles and includes those polices and procedures that:
•pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our 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 our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
•provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2010 based on the criteria in "Internal Control-Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based upon this evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2010.
Grant Thornton LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this Annual Report on Form 10-K, has also audited the effectiveness of the Company's internal control over financial reporting as of December 31, 2010.
Changes in Internal Control over Financial Reporting.
There were no changes in internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting
Item 9B:
Item 9B: Other Information.
Not applicable.
PART III
Item 10:
Item 10: Directors, Executive Officers and Corporate Governance
See "Executive Officers, Board of Directors, Committees of the Board and Section 16(a) Beneficial Ownership Reporting Compliance" in the Warren Resources, Inc. Proxy Statement ("Proxy Statement"), for the Annual Meeting of Stockholders of Warren Resources, Inc. to be held on May 18, 2011 (to be filed with the SEC within 120 days after the end of the Company's fiscal year ended December 31, 2010) which is incorporated herein by reference.
The Company's Code of Business Conduct and Ethics and the Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer (Code of Ethics) can be found on the Company's internet website located at www.warrenresources.com. If the Company amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the Company intends to disclose the information on its internet website. This information will remain on the website for at least 12 months.
Item 11:
Item 11: Executive Compensation
Information required by this item will be contained in the Proxy Statement under the caption "Executive Compensation," and is hereby incorporated by reference herein.
Item 12:
Item 12: Securities Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information required by this item will be contained in the Proxy Statement under the caption "Securities Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters" and is incorporated herein by reference.
Item 13:
Item 13: Certain Relationships and Related Transactions, and Director Independence
Information required by this item will be contained in the Proxy Statement under the caption "Certain Transactions" and "Corporate Governance" and is hereby incorporated by reference herein.
Item 14:
Item 14: Principal Accountant Fees and Services
Information required by this item will be contained in the Proxy Statement under the caption "Auditors' Fees," and is hereby incorporated by reference "Regulations and Environmental Matters" and "-Future Regulations" herein.
PART IV
Item 15:
Item 15: Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
Form 10-K
Pages
Reports of Independent Registered Public Accounting Firm
Consolidated Balance Sheets, December 31, 2010 and 2009
Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and
Consolidated Statements of Stockholders' Equity and Comprehensive Income for the Years Ended December 31, 2010, 2009 and 2008
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and
Notes to Consolidated Financial Statements, December 31, 2010, 2009 and 2008
(a)(2) All other schedules have been omitted because the required information is inapplicable or is shown in the Notes to the Consolidated Financial Statements.
(a)(3) Exhibits required to be filed by Item 601 of Regulation S-K.
*Denotes a management contract or compensatory plan or arrangement.
(1)Incorporated by reference to the Company's Registration Statement on Form 10, Commission File No. 000-33275, filed on October 26, 2001.
(2)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed on December 17, 2002.
(3)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed on December 24, 2002.
(4)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed on February 11, 2004.
(5)Incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2002, Commission File No. 000-33275, filed on March 31, 2003.
(6)Incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2003, Commission File No. 000-33275, filed on March 15, 2004.
(7)Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, Commission File No. 000-33275, filed May12, 2004.
(8)Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, Commission File No. 000-33275, filed on August 13, 2003.
(9)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed November 30, 2004.
(10)Incorporated by reference to the Company's Registration Statement on From S-1/A, Commission File No. 333-118535, filed December 2, 2004.
(11)Incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 000-33275, filed on March 17, 2005.
(12)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed December 12, 2005.
(13)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed June 17, 2005.
(14)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed June 22, 2007.
(15)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed August 21, 2007.
(16)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed November 20, 2007.
(17)Incorporated by reference to the Company's Form 8-A filed on September 5, 2008, Commission File No. 001-34169.
(18)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed January 7, 2009.
(19)Incorporated by reference to the Company's Quarterly Report on Form 10-Q, Commission File No. 000-33275, filed August 5, 2009.
(20)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed May 15, 2009.
(21)Incorporated by reference to the Company's Definitive Proxy Statement on Form DEF 14-A filed on April 8, 2010.
Filed herewith.
SIGNATURES
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, thereunto duly authorized.
WARREN RESOURCES, INC.
By
/s/ NORMAN F. SWANTON
Norman F. Swanton
President, Chief Executive Officer,
Director and Chairman
By
/s/ TIMOTHY A. LARKIN
Timothy A. Larkin
Executive Vice President, Chief Financial Officer, and Principal Accounting Officer
Dated: March 2, 2011
Pursuant to the requirements of the Securities and Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Page
Reports of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2010 and 2009
Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008
Consolidated Statement of Stockholders' Equity and Comprehensive Income for the years ended December 31, 2010, 2009 and
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Warren Resources, Inc.
We have audited Warren Resources, Inc. (a Maryland Corporation) and subsidiaries (collectively, the "Company") internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("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, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit 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. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders' equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2010 and our report dated March 2, 2011 expressed an unqualified opinion.
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
March 2, 2011
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Warren Resources, Inc.
We have audited the accompanying consolidated balance sheets of Warren Resources, Inc. (a Maryland Corporation) and subsidiaries (collectively, the "Company") as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders' equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2010. 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 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Warren Resources, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note A, the Company changed its method of estimating oil and gas reserves and related disclosures in 2009.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 2, 2011 expressed an unqualified opinion.
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
March 2, 2011
Warren Resources, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
December 31,
The accompanying notes are an integral part of these statements.
Warren Resources, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended December 31,
The accompanying notes are an integral part of these statements.
Warren Resources, Inc. and Subsidiaries
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
Years ended December 31, 2010, 2009 and 2008
The accompanying notes are an integral part of these statements.
Warren Resources, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31,
The accompanying notes are an integral part of these statements.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
NOTE A-ORGANIZATION AND ACCOUNTING POLICIES
Nature of Operations
Warren Resources, Inc. (the "Company" or "Warren"), was originally formed on June 12, 1990 for the purpose of acquiring and developing oil and gas properties. The Company is incorporated under the laws of the state of Maryland. The Company's properties are primarily located in Wyoming, California, New Mexico, North Dakota and Texas.
Principles of Consolidation
The consolidated financial statements include accounts of the Company, its wholly-owned subsidiaries, Warren Development Corp., Warren Drilling Corp., Warren Management Corp., Warren Resources of California, Inc, Warren Energy Services LLC and Warren E&P, Inc. All significant intercompany accounts and transactions have been eliminated in consolidation.
Oil and Gas Properties
The Company accounts for its oil and gas activities using the full cost method. As prescribed by full cost accounting rules, all costs associated with property acquisition, exploration and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of oil and gas properties as well as other internal costs that can be specifically identified with acquisition, exploration and development activities are also capitalized. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The sum of net capitalized costs and estimated future development and dismantlement costs are depleted on the equivalent unit-of-production method, based on proved oil and gas reserves as determined by independent petroleum engineers.
In accordance with full cost accounting rules, the Company is subject to a limitation on capitalized costs. The capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization, may not exceed the estimated future net cash flows from proved oil and gas reserves discounted at 10 percent, plus the cost of unproved properties excluded from amortization, as adjusted for related tax effects. If capitalized costs exceed this limit (the "ceiling limitation"), the excess must be charged to expense. The Company recorded a $272 million ceiling limitation impairment charge for the year ended December 31, 2008. There was no impairment charge in 2010 or 2009.
The costs of certain unevaluated oil and gas properties and exploratory wells being drilled are not included in the costs subject to amortization. The Company assesses costs not being amortized for possible impairments or reductions in value and if impairments or a reduction in value has occurred, the portion of the carrying cost in excess of the current value is transferred to costs subject to amortization.
Revenue Recognition
Oil and gas sales result from undivided interests held by the Company in various oil and gas properties. Sales of natural gas and oil produced are recognized when delivered to, or picked up, by the
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE A-ORGANIZATION AND ACCOUNTING POLICIES (Continued)
purchaser. For 2010, the largest purchasers and marketers for the Company's production primarily included ConocoPhillips and Anadarko Energy Services, which accounted for 55% and 33%, respectively, of total oil and natural gas sold in 2010. For 2009, the largest purchasers and marketers for the Company's production primarily included ConocoPhillips and Anadarko Energy Services, which accounted for 59% and 28%, respectively, of total oil and natural gas sold in 2009. For 2008, the largest purchasers and marketers for the Company's production primarily included ConocoPhillips and Anadarko Energy Services, which accounted for 67% and 19%, respectively, of total oil and natural gas sold in 2008.
Cash and Cash Equivalents
The Company considers all highly liquid investments with maturities of three months or less when acquired to be cash equivalents. The Company maintains its cash and cash equivalents in bank deposit accounts that exceed federally insured limits. At December 31, 2010, the Company had the majority of its cash and cash equivalents with one financial institution. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on cash and cash equivalents.
Accounts Receivable
Accounts receivable include trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on evaluation of a customer's financial condition and, generally, collateral is not required. Accounts receivable under joint operating agreements generally have a right of offset against future oil and gas revenues if a producing well is completed. Accounts receivable are due within 30 days and are stated at amounts due from customers net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time trade accounts receivable are past due, the Company's previous loss history, the customer's current ability to pay its obligation to the Company, and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. As of December 31, 2010 and 2009, the Company has an allowance of $125,000 and $100,000 for doubtful accounts, respectively.
Investments
The Company classifies its investment in debt securities into two categories: trading securities and available-for-sale securities. Trading securities, classified as current assets, are recorded at fair value with net unrealized gains or losses included in the determination of net earnings. Available-for-sale securities are recorded at fair value, with net unrealized gains and losses excluded from net earnings and reported as other comprehensive income (loss). Available-for-sale securities represent the market value of zero coupon Treasury Bonds collateralizing convertible debentures and are classified as current or non-current based on the classification of the related debentures. Realized gains and losses are determined on the basis of specific identification of the securities.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE A-ORGANIZATION AND ACCOUNTING POLICIES (Continued)
Offering Costs
Costs incurred in connection with the issuance of debt are capitalized and amortized over the term of the related debt using the effective interest rate method. The Company has $1.5 million and $1.5 million, net of accumulated amortization of $879 thousand and $680 thousand, included in other assets at December 31, 2010 and 2009, respectively. Costs associated with the issuance of preferred and common stock are reflected as a reduction of proceeds. Preferred stock is accreted to its liquidation value over seven years from the date of issuance.
Income Taxes
Deferred income taxes are recognized for the tax consequences in future years of differences between the tax basis of assets and liabilities and their financial reporting amounts based on enacted tax laws and statutory rates applicable to the period in which the differences are expected to affect taxable income. Valuation allowances are established when, in management's opinion, it is more likely than not that a portion or all of the deferred tax assets will not be realized. The Company's policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company's income tax provision. The Company routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. Only tax positions that meet the more-likely-than-not recognition threshold are recorded.
Use of Estimates
In preparing financial statements, accounting principles generally accepted in the United States of America require management to make estimates and assumptions in determining the reported amounts of assets and liabilities and 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. In addition, significant estimates are used in determining year end proved oil and gas reserves. Actual results could differ from those estimates. The estimate of the Company's oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect reported results.
Gas Imbalances
The Company follows the sales method of accounting for gas imbalances. A liability is recorded when the Company's excess takes of natural gas volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production. The Company has no significant gas imbalances.
Stock Based Compensation
The Company uses the Black-Scholes option-pricing formula to estimate the fair value of stock based compensation expense at the grant date related to stock options issued. This expense is then recognized using the straight-line method over the vesting period. For the years ended December 31, 2010, 2009 and 2008, the Company recognized approximately $2.4 million, $1.9 million and $2.6 million in compensation expense, respectively, related to stock option plans and restricted stock.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE A-ORGANIZATION AND ACCOUNTING POLICIES (Continued)
The fair value of each grant is estimated on the date of grant using the Black-Scholes options-pricing model with the following weighted-average assumptions used for grants in 2010, 2009 and 2008, respectively: No expected dividends, weighted average volatility of 78%, 70%, and 48%, risk-free interest rates of 1.60%, 1.54%, and 2.06% and expected lives of 3.5 years for incentive options issued in 2010, 2009 and 2008. The volatility assumptions were calculated based on the performance of our stock prices for the year. The weighted average fair values of the options issued in 2010, 2009 and 2008 were $1.33, $0.28, and $4.20, respectively.
Accounting for Long-Lived Assets
The Company reviews property and equipment for impairment whenever indicators of impairment are present to determine if the carrying amounts exceed the estimated future net cash flows to be realized. Impairment losses are recognized based on the estimated fair value of the asset.
Derivative financial instruments
The Company has entered into several crude oil and natural gas hedges in order to minimize any effect of a downturn in oil and gas prices and protect profitability. These derivative financial instruments are carried on the balance sheet at fair value. If a derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If a derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income ("OCI") and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges are recognized in earnings. The Company has elected not to designate its derivatives as fair value or cash flow hedges (Note I). Gains and losses resulting from changes in the fair value of the non-designated hedges are recognized in earnings.
Property and Equipment
Property and equipment are stated at cost and are depreciated using the straight-line method over the estimated useful lives of the assets, ranging from three through 25 years, except for land which is not depreciated. Property and equipment consisted of the following at December 31:
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE A-ORGANIZATION AND ACCOUNTING POLICIES (Continued)
Earnings (Loss) Per Common Share
Basic earnings (loss) per common share is computed by dividing the net earnings (loss) applicable to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share is based on the assumption that stock options and warrants are converted into common shares using the treasury stock method and convertible debentures and preferred stock are converted using the if-converted method. Conversion or exercise is not assumed if the results are antidilutive.
For the year ended December 31, 2010, diluted weighted average common shares outstanding includes in the money employee stock options of 1,046,950.
Potential common shares relating to options, warrants, preferred stock, restricted stock and convertible debentures excluded from the computations of diluted earnings (loss) per share because they are antidilutive are as follows:
Preferred stock is convertible from the date of issuance until redemption at 100% of the redemption price amount into common stock of the Company at a conversion rate between 1 to 1 and 1 to 0.5 (Note D).
At December 31, 2010, the Convertible Debentures may be converted until maturity at 100% of principal amount into common stock of the Company at prices ranging from approximately $35.00 to $50.00 (Note C).
Goodwill
Historically the Company tested goodwill for impairment purposes quarterly, to determine if the value of this asset had been impaired. As a result of the Company's low market capitalization at December 31, 2008, the valuation of goodwill relating to the acquisition of Warren E&P was reviewed, and the Company recorded an impairment charge of $3.4 million in the fourth quarter of 2008.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE A-ORGANIZATION AND ACCOUNTING POLICIES (Continued)
Asset Retirement Obligations
The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a risk adjusted rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method. The associated liability is classified in other long-term liabilities, net of current portion, in the accompanying Consolidated Balance Sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense, and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization. The Company has cash held in escrow with a fair market value of $3.2 million that is legally restricted for potential plugging and abandonment liability in the Wilmington field which is recorded in other assets in the Consolidated Balance Sheets. A reconciliation of the Company's asset retirement obligations is as follows:
Recently Issued Accounting Pronouncements
On December 31, 2008, the SEC published a final rule to revise its oil and gas reserves estimation and disclosure requirements. The primary objectives of the revisions are to increase the transparency and information value of reserve disclosures and improve comparability among oil and gas companies. The rule is effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. The revised rules amend the definition of proved reserves to permit consideration of new technologies in evaluating oil and natural gas reserves; require the use of an average price based on the prior twelve month period rather than year-end prices, permit the disclosure of probable and possible oil and gas reserves, and revises other oil and natural gas disclosure requirements for operations. The adoption of these rules resulted in lower prices being used for both oil and gas in the preparation of the 2009 reserve report and a decrease in 2009 reserves of approximately 11.2 Bcfe. Additionally, the decrease in reserves resulted in additional depletion, depreciation and amortization being recorded in the fourth quarter of approximately $0.4 million. In January 2010, the FASB issued guidance in the "Extractive Activities-Oil and Gas" topic of the FASC that aligns the FASB's oil and gas reserve estimation and disclosure requirements with the new SEC rule revisions. The new guidance is effective for the Company for the year ending December 31, 2009.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE A-ORGANIZATION AND ACCOUNTING POLICIES (Continued)
In January 2010, the Financial Accounting Standards Board ("FASB") issued new guidance and clarifications for improving disclosures about fair value measurements. This guidance requires enhanced disclosures regarding transfers in and out of the levels within the fair value hierarchy. Separate disclosures are required for transfers in and out of Level 1 and 2 fair value measurements, and the reasons for the transfers must be disclosed. The new disclosures and clarifications of existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009. The adoption of this guidance did not have any effect on the financial statements.
NOTE B-INVESTMENTS
The amortized cost, unrealized gains and estimated fair values of the Company's available-for-sale securities held are summarized as follows:
During 2010, 2009, and 2008, the Company recognized approximately $0, $3 thousand and $98 thousand, respectively, of realized gains from its investments in trading and available-for-sale securities. The basis of available for sale securities sold is determined using the specific identification method.
The realized gains for each year results from the release of such securities due to the release of the Company's obligation related to securing its commitment under certain repurchase agreements and debentures (Notes C & F).
The amortized cost and estimated fair values of available-for-sale securities, by contractual maturity at December 31, 2010 are shown below.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE C-LONG-TERM LIABILITIES
(1)Debentures can be called at par if the Company's stock trades at or above 133% of the conversion price for a period of ninety consecutive trading days.
The Convertible Debentures may be converted from the date of issuance until maturity at 100% of principal amount into common stock of the Company at prices which generally increase over the term of the Debentures and range from approximately $35.00 to $50.00. Conversion of the Debentures would increase the number of shares outstanding at December 31 as follows:
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE C-LONG-TERM LIABILITIES (Continued)
Each year, holders of the Secured Convertible Debentures may tender to the Company up to 10% of the aggregate amount outstanding. As of December 31, 2010, the estimated principal that can be tendered by the secured holders is as follows:
Long-term liabilities, excluding derivative financial instruments consist of the following at December 31:
During 2002, the Company entered into an agreement to purchase 702,500 shares of common stock from a shareholder through the issuance of a noninterest-bearing note. The Company discounted the note at 10% and the outstanding balance at December 31, 2010 and 2009 was approximately $245 thousand and $374 thousand, respectively, net of discount of approximately $22 thousand and $54 thousand, which is included in other long-term liabilities. The note requires monthly payments of $13 thousand until August 2012 and is collateralized by treasury stock. In the event of default as defined by the agreement, the only remedy by the note holder will be the issuance of the common stock. During 2010, the Company acquired a drilling rig for a purchase price of $7 million. The Company paid $3.5 million at closing and executed a non-interest bearing secured note for the remaining $3.5 million, payable in fifteen equal monthly payments commencing September 2010.
On November 16, 2006, the Company entered into a five year, $150 million credit agreement with JPMorgan Chase Bank. On November 19, 2007, the Company entered into an Amended and Restated Credit Agreement with Merrill Lynch Capital ("the Lender"). The Merrill Lynch Credit Agreement
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE C-LONG-TERM LIABILITIES (Continued)
replaced the existing agreement entered into with JPMorgan Chase Bank. The Credit Facility provides for a revolving credit line up to the lesser of (i) the Borrowing Base (ii) $250 million, and (iii) the Draw Limit requested by the Company. The Credit Facility matures on November 19, 2012. It is secured by substantially all of our assets and is guaranteed by two of our wholly-owned subsidiaries.
The Borrowing Base will be determined by the Lender at least semi-annually on each April 1 and October 1. The current Borrowing Base is $120 million. We may request one unscheduled borrowing base determination subsequent to each scheduled determination, and the Lenders may request unscheduled determinations at any time. If the borrowing base is reduced below the outstanding balance, the Company would be obligated to reduce the deficiency by 25% within 90 days and has an additional 90 days to cure the remaining deficiency.
Depending on the current level of Borrowing Base usage, the annual interest rate on each base rate borrowing will be at the Borrower's option: a) a "Base Rate Loan", or any other Obligation other than a LIBOR Loan, which has an interest rate equal to the sum of the "Base Rate" plus the applicable "Base Rate Margin", calculated to be the higher of (i) the Agent's prime rate of interest announced from time to time, or (ii) the Federal Funds rate most recently determined by the Agent, plus 3.0% per annum, plus an applicable margin that ranges from 1.5% to 2.25%, or (b) a "LIBOR Loan", which has an interest rate equal to the sum of the applicable LIBOR period plus the applicable "LIBOR Margin", that ranges from 2.75% to 3.50%. As of December 31, 2010, the weighted average interest rate on the credit line was 3.4%. Interest is payable quarterly.
The Company is subject to certain covenants under the terms of the Credit Facility. These covenants include, but are not limited to, the maintenance of the following financial covenants: (1) a minimum current ratio (including unused borrowing base in current assets as defined in the Credit Facility), of 1.0 to 1.0; and (2) a minimum interest coverage ratio (Consolidated EBITDAX to interest expense, as defined in the Credit Facility) of not less than 2.5 to 1.0. As of December 31, 2010, the Company had borrowed $69.5 million under the Credit Facility and was in compliance with all covenants.
The Credit Facility also places restrictions on certain additional indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of our common stock, speculative commodity transactions, transactions with affiliates and other matters.
The Credit Facility is subject to customary events of default. If an event of default occurs and is continuing, the Agent may, or at the request of the Lenders shall, accelerate amounts due under the Credit Facility (except for a bankruptcy event of default, in which case such amounts will automatically become due and payable).
NOTE D-STOCKHOLDERS' EQUITY
On October 23, 2009, the Company sold 11,775,000 shares of common stock to the public in a secondary offering at a price of $2.60 per share. After deducting the underwriters' commission and offering expenses, the Company received total net proceeds of approximately $28.7 million.
During 2010, the Company issued 249,671 shares of common stock to individuals who exercised options at an exercise price of $0.51 per share. During 2008, the Company issued 614,535 shares of
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE D-STOCKHOLDERS' EQUITY (Continued)
common stock to individuals who exercised options at exercise prices ranging from $4 to $10.51 per share.
The preferred stock has an 8% cumulative dividend, payable quarterly. Preferred dividends of approximately $59 thousand ($4.32 per share) and $337 thousand ($3.36 per share) were accrued at December 31, 2010 and 2009, respectively. The holders of the preferred stock are not entitled to vote except as defined by the agreement or as provided by applicable law. The preferred stock may be voluntarily converted into common stock at the election of the holder based on the table below. The conversion rate is subject to adjustment as defined by the agreement.
Additionally, commencing December 31, 2010, holders of the preferred stock may elect to require the Company to redeem their preferred stock at a redemption price equal to the liquidation value of $12 per share, plus accrued but unpaid dividends, if any ("Redemption Price"). Upon the receipt of a redemption election, the Company, at its option, shall either: (1) pay the holder cash in the amount equal to the Redemption Price or (2) issue to holder shares of common stock as defined by the agreement. The Company is accreting the carrying value of its preferred stock to its redemption price using the effective interest method with accretion recorded to additional paid in capital. The accretion of preferred stock results in a reduction of earnings per share applicable to common stockholders. There are 10,703 preferred shares outstanding that the Company may be required to redeem at the aggregate Redemption Price of $0.1 million after December 31, 2010. As noted above, the Company could, at its option, settle the redemption requests in shares of common stock.
During 2010, the Company redeemed 87,409 shares of preferred stock plus accrued dividends, at a cost of approximately $1.3 million. During 2008, the Company redeemed 126,258 shares of preferred stock plus accrued dividends, at a cost of approximately $1.7 million.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE D-STOCKHOLDERS' EQUITY (Continued)
Securities Authorized for Issuance Under Compensation Plans
The table below includes information about our equity compensation plans as of December 31, 2010:
During 2010, the Board of Directors approved and the Company issued 1,098,500 stock options to officers and employees of the Company exercisable at prices ranging from $2.42 to $3.08 per share and 533,437 shares of restricted stock. During 2009, the Board of Directors approved and the Company issued 1,619,874 stock options to officers and employees of the Company exercisable at prices ranging from $0.51 to $2.06 per share. During 2008, the Board of Directors approved and the Company issued 470,250 stock options to officers and employees of the Company exercisable at prices ranging from $10.79 to $13.46 per share and 112,857 shares of restricted stock. The options are exercisable at a price not less than the fair market value of the stock at the date of grant, have an exercisable period of five years and generally vest over three years.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE D-STOCKHOLDERS' EQUITY (Continued)
A summary of the status of the Company's options issued to employees as of December 31, 2010, 2009 and 2008 and changes during the years ended on those dates is presented below:
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE D-STOCKHOLDERS' EQUITY (Continued)
The following table summarizes information about the Company's stock options outstanding at December 31, 2010.
The total intrinsic value of options exercised during the year ended December 31, 2010 and 2008 was $0.7 million and $5.2 million. There were no option exercises in 2009.
As of December 31, 2010 there was $1.3 million of total unrecognized compensation cost related to non-vested stock options granted under the Plans. This cost is expected to be recognized over a weighted average period of 1.9 years.
Cash received from option exercises under all stock-based payment arrangements for the years ended December 31, 2010 and 2008 was $0.1 million and $2.9 million. We issue new shares of common stock to settle option exercises. No options were exercised in 2009.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE D-STOCKHOLDERS' EQUITY (Continued)
A summary of the status of the Company's restricted stock issued to employees as of December 31, 2010 and 2009 and changes during the years ended on those dates is presented below:
Restricted stock awards for executive officers and employees generally vest ratably over three years, excluding shares granted in March 2010 which vest ratably over nine months. Fair value of our restricted shares is based on our closing stock price on the date of grant. As of December 31, 2010, total unrecognized stock-based compensation expense related to non-vested restricted shares was $43,000 which is expected to be recognized over a weighted average period of approximately 0.2 years.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE D-STOCKHOLDERS' EQUITY (Continued)
A summary of the status of the Company's warrants issued as of December 31, 2010, 2009 and 2008 and changes during the years ended on those dates is presented below:
The total intrinsic value of warrants outstanding at December 31, 2010 and 2009 was zero.
NOTE E-INCOME TAXES
The Company and its subsidiaries file a consolidated federal income tax return.
The Company's effective income tax rate differed from the federal statutory rate as follows:
(a)34% for 2010, 34% for 2009 and 35% for 2008.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE E-INCOME TAXES (Continued)
Deferred tax assets and liabilities are as follows as of December 31:
A valuation allowance for deferred tax assets is required when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of this deferred tax asset depends on the Company's ability to generate sufficient taxable income in the future. Management believes it is more likely than not that the net deferred tax asset will not be realized by future operating results. The valuation allowance increased (decreased) by approximately ($8 million), $16 million and $109 million for the years ended December 31, 2010, 2009 and 2008, respectively.
At December 31, 2010, the Company had net operating loss carryforwards for federal income tax purposes of approximately $220 million, of which approximately $1 million will expire in 2012, with the remaining $219 million to expire in years 2018 through 2029.
The Company routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. Only tax positions that meet the more-likely-than-not recognition threshold are recorded.
NOTE F-COMMITMENTS AND CONTINGENCIES
General Commitments
The Company has entered into various commitments and operating agreements related to development and production of certain oil and gas properties. It is management's belief that such commitments, as stated below, will be met without significant adverse impact to the Company's financial position or results of operations.
The Company has entered into employment agreements with certain key executives. Under the terms of these agreements, certain executives are entitled to termination compensation equal to at least two years annual salary if terminated without cause or in the event of a change in control. At
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE F-COMMITMENTS AND CONTINGENCIES (Continued)
December 31, 2010, the maximum termination compensation for all executives is approximately $2.6 million.
Trust Indenture Agreements
Under certain Trust Indenture Agreements, the Company has purchased zero coupon U.S. Treasury Bonds to secure repayment of the outstanding principal amount of debentures when due at maturity. At December 31, 2010 and 2009, the face amounts of U.S. Treasury Bonds securing the Company's obligation under the Trust Indenture Agreements were $1.7 million and $1.7 million, respectively, and the market values of these U.S. Treasury Bonds were approximately $1.1 million and $1.0 million, respectively (see Note B).
Leases
The Company leases corporate office space in New York City, which expires in March 2013. The Company's oil and gas administrative office in Casper, Wyoming occupies 5,554 square feet under a lease which expires in July 2012. The Company leases office space in Roswell, New Mexico, which expires in May 2013. The Company leases office space in Long Beach, California which expires in April 2015.
Future minimum annual rental payments, which are subject to escalation and include utility charges as of December 31, 2010, are as follows:
Rent expense under these leases was approximately $728 thousand, $700 thousand and $658 thousand for the years ended December 31, 2010, 2009 and 2008, respectively.
Legal Proceedings
In 2005, Warren recorded a provision for $1.8 million relating to a contingent liability that the Company may face as a result of a lawsuit originally filed in 1998 by Gotham Insurance Company in the 81st Judicial District Court of Frio County, Texas (Gotham Insurance Company v. Pedeco, Inc., et al.,) seeking a refund of approximately $1.8 million paid by Gotham and other insurers under an insurance policy issued for a well blow-out that occurred in 1997. After several appeals to the Texas Court of Appeals and the Texas Supreme Court, the case was remanded to the trial court for further proceedings. Both parties filed Motions for Summary Judgment in mid-2009, and on November 19, 2009, the trial court heard oral arguments on both Motions for Summary Judgment. On January 22, 2010, the court granted Gotham's Motion for Summary Judgment for restitution in the amount of
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE F-COMMITMENTS AND CONTINGENCIES (Continued)
$1,823,156 and also awarded prejudgment interest at the rate of 5% per annum in the amount of $976,011. As a result of the January 2010 Summary Judgment, Warren recorded an additional provision of $1.3 million in the fourth quarter of 2009 relating to this contingent liability. We filed our Notice of Appeal with the Frio County District Court on or about June 24, 2010. On July 7, 2010, Warren E&P posted a supersedeas bond with the court and commenced to appeal the order of the trial court to the Texas Court of Appeals. The San Antonio Court of Appeals assigned and transferred this appeal to the El Paso Court of Appeals. Based on extensions given by the El Paso Court of Appeals, the Frio County District Court Clerk certified and filed the Record on Appeal on October 26, 2010. We are in the process of preparing and filing our brief with the El Paso Court of Appeals, which is due on March 13, 2011. Although Warren believes that it has meritorious grounds for the appeal, if its appeal is unsuccessful, it will pay the amount of restitution to Gotham, as ordered by the trial court.
The Company is a party to various other matters of litigation arising in the normal course of business. Management believes that the ultimate outcome of the matters will not have a material effect on the Company's financial condition or results of operations.
NOTE G-EMPLOYEE BENEFIT PLANS
The Company has a retirement plan covering substantially all qualified employees under section 401(k) of the Internal Revenue Code. On October 1, 2006, the Company changed its matching policy to contribute up to 100% of the participant's contribution, up to federally allowed limits. On January 1, 2009, the Company changed to a safe harbor matching plan where the Company contributes up to 100% of the participants' 401(k) contributions, up to a maximum of 3% of the participants' compensation plus 50% of the next 2% of the active participants' compensation. The Company's safe harbor match vests immediately. The Company may also make discretionary contributions. The Company's expenses under the plan were approximately $173 thousand, $137 thousand and $485 thousand for the years ended December 31, 2010, 2009 and 2008, respectively.
NOTE H-FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of financial instruments recognized in the Consolidated Balance Sheets or disclosed within these Notes to Consolidated Financial Statements have been determined using available market information, information from unrelated third party financial institutions and appropriate valuation methodologies, primarily discounted projected cash flows. However, considerable judgment is required when interpreting market information and other data to develop estimates of fair value.
Short-term Assets and Liabilities. The fair values of cash and cash equivalents, accounts receivable, accounts payable and accrued expenses and other current liabilities approximate their carrying values because of their short-term nature.
U.S Treasury Bonds-Available-For-Sale Securities. The fair values are based upon quoted market prices for those or similar investments and are reported on the Consolidated Balance Sheets at fair value.
Collateral Security Agreement Account (included in other non-current assets). The balance sheet carrying amount approximates fair value, as it earns a market rate.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE H-FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)
Fixed Rate Debentures: Fair values of fixed rate convertible debentures were calculated using interest rates in effect as of year end for similar instruments with the other terms unchanged.
Other Long-Term Liabilities. The carrying amount approximates fair value due the current rates offered to the Company for long-term liabilities of the same remaining maturities.
Drilling Rig Obligation. The carrying amount approximates fair value due to the short term of this obligation.
Line of Credit. The carrying amount approximates fair value due the current rates offered to the Company for lines of credit.
FAIR VALUE MEASUREMENTS:
Fair value as defined by authoritative literature is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:
Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.
Level 2: Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter forwards and swaps.
Level 3: Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.
The valuation assumptions utilized to measure the fair value of the Company's commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs).
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE H-FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)
The following table presents for each hierarchy level our assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis.
NOTE I-DERIVATIVE FINANCIAL INSTRUMENTS
To minimize the effect of a downturn in oil and gas prices and protect our profitability and the economics of our development plans, we enter 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. This price hedging program is designed to moderate the effects of a crude oil and natural gas price downturn while allowing us to participate in some commodity price increases. Management regularly monitors the crude oil and natural gas markets and our financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging and/or basis adjustments or other price protection is appropriate. Currently, our derivatives are in the form of swaps, long and short calls and costless collars. However, we may use a variety of derivative instruments in the future to hedge. The Company has not designated these derivatives as hedges.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE I-DERIVATIVE FINANCIAL INSTRUMENTS (Continued)
The following table summarizes the open financial derivative positions as of December 31, 2010 related to oil and gas production. The Company will receive prices as noted in the table below and will pay a counterparty market price based on the NYMEX (for natural gas production) or WTI (for oil production) index price, settled monthly.
*The Company paid $685,000 in net premiums for these calls.
**This represents a differential spread between NYMEX and CIG pricing.
The tables below summarize the amount of gains (losses) recognized in income from derivative instruments not designated as hedging instruments under authoritative guidance.
In May 2010, the Company repurchased 385 Bbld (approximately 141,000 Bbls in total) under our 2011 $61.80 price swap for $2 million, which is included in realized cash settlements in gain (loss) on derivative financial instruments.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE I-DERIVATIVE FINANCIAL INSTRUMENTS (Continued)
The table below reflects the line item in our Consolidated Balance Sheet where the fair value of our net derivatives, are included.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE J-OIL AND GAS INFORMATION
Costs related to the oil and gas activities of the Company were incurred as follows for the years ended December 31:
Asset retirement cost included in oil and gas property costs increased by approximately $1.4 million in 2010, increased by $0.2 million in 2009 and increased by approximately $2.5 million in 2008.
The Company had the following aggregate capitalized costs relating to the Company's oil and gas activities at December 31:
The following table sets forth the Company's results of operations from oil and natural gas producing activities for the years ended December 31:
In the presentation above, no deduction has been made for indirect costs such as corporate overhead or interest expense. No income taxes are reflected above due to the Company's tax loss carryforwards.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE J-OIL AND GAS INFORMATION (Continued)
The following is a summary of Warren's oil and gas properties not subject to amortization as of December 31, 2010:
(1)The Company's development costs primarily reflect investment in well cellars and facilities in its Wilmington oil field to facilitate the development of future oil wells. These costs will be allocated to future wells drilled, the majority of these wells are expected to be drilling during the next five to eight years.
NOTE K-OIL AND GAS RESERVE DATA (UNAUDITED)
In December 2008, the SEC announced that it had approved revisions to modernize the oil and gas reserves reporting requirements. The Company adopted these rules effective December 31, 2009. The most significant impact to the Company in the calculation of its reserves was the use of 12-month average pricing to calculate year end reserves instead of year end prices.
The following estimates of proved reserve quantities and related standardized measure of discounted future net cash flows are estimates only, and do not purport to reflect realizable values or fair market values of the Company's reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. All of the Company's reserves are located in the United States.
Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that 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 reserves are those expected to be recovered through existing wells, equipment and operating methods.
The standardized measure of discounted future net cash flows for 2008 was computed by applying year-end prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE K-OIL AND GAS RESERVE DATA (UNAUDITED) (Continued)
basis of the properties and available credits, and assuming continuation of existing economic conditions. The standardized measure of discounted future net cash flows for 2010 and 2009, were computed by applying 12-month average prices for oil and gas during these years. The estimated future net cash flows are then discounted using a rate of 10%.
The following summaries of changes in reserves and standardized measure of discounted future net cash flows were prepared from estimates of proved reserves developed by Williamson Petroleum Consultants, Inc., our independent petroleum engineers.
Summary of Changes in Proved Reserves
(a)Due to a significant decrease in oil prices at December 31, 2008, a majority of the Company's proved undeveloped locations in the WTU and NWU facility were deemed non economic at year end.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE K-OIL AND GAS RESERVE DATA (UNAUDITED) (Continued)
Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
Changes in Standardized Measure of Discounted Future Net Cash Flows
Related to Proved Oil and Gas Reserves
Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2010 and 2009 and current sales prices for 2008, along with estimates of the operating costs, production taxes and future development and abandonment costs (less salvage value) necessary to produce such reserves. The prices used at December 31, 2010, 2009 and 2008 were $73.30, $54.33 and $32.92 per Bbl and $4.13, $3.22 and $4.80 per Mcf, respectively. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2010, 2009 and 2008
NOTE K-OIL AND GAS RESERVE DATA (UNAUDITED) (Continued)
Operating costs and production taxes are estimated based on current costs with respect to producing oil and natural gas properties. Future development costs are based on the best estimate of such costs assuming current economic and operating conditions. The future cash flows estimated to be spent to develop the Company's portion of proved undeveloped properties through December 31, 2014 are $84.6 million.
Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable carryforwards, for both regular and alternative minimum tax. The Company's net operating loss carryforward is expected to fully absorb any future income taxes from oil and gas operations.
The future net revenue information assumes no escalation of costs or prices, except for oil and natural gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.
NOTE L-QUARTERLY INFORMATION (UNAUDITED)
Summarized quarterly financial data for the years ended December 31, 2010 and 2009 are as follows:
Quarterly and year-to-date computations of per share amounts are made independently. Therefore, the sum of quarterly per share amounts may not agree with per share amounts for the year. Gross profit represents oil and gas revenues less lease operating expenses.
Warren Resources, Inc. and Subsidiaries
WARREN RESOURCES, INC.
FORM 10-K
December 31, 2010
INDEX TO EXHIBITS
*Denotes a management contract or compensatory plan or arrangement.
(1)Incorporated by reference to the Company's Registration Statement on Form 10, Commission File No. 000-33275, filed on October 26, 2001.
(2)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed on December 17, 2002.
(3)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed on December 24, 2002.
(4)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed on February 11, 2004.
(5)Incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2002, Commission File No. 000-33275, filed on March 31, 2003.
(6)Incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2003, Commission File No. 000-33275, filed on March 15, 2004.
(7)Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, Commission File No. 000-33275, filed May12, 2004.
(8)Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, Commission File No. 000-33275, filed on August 13, 2003.
(9)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed November 30, 2004.
(10)Incorporated by reference to the Company's Registration Statement on From S-1/A, Commission File No. 333-118535, filed December 2, 2004.
(11)Incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 000-33275, filed on March 17, 2005.
(12)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed December 12, 2005.
(13)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed June 17, 2005.
(14)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed June 22, 2007.
(15)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed August 21, 2007.
(16)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed November 20, 2007.
(17)Incorporated by reference to the Company's Form 8-A filed on September 5, 2008, Commission File No. 001-34169.
(18)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed January 7, 2010.
(19)Incorporated by reference to the Company's Quarterly Report on Form 10-Q, Commission File No. 000-33275, filed August 5, 2009.
(20)Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed May 15, 2009.
(21)Incorporated by reference to the Company's Definitive Proxy Statement on Form DEF 14-A filed on April 8, 2010.
Filed herewith.