Item 1A. Risk Factors
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Form 10-K, actually occurs, our business, financial condition or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or that we currently consider immaterial also may adversely affect our Company.
Risks Related to the Oil and Natural Gas Industry and Our Business
Oil and natural gas prices are volatile and a decline in oil and natural gas prices can significantly affect our financial results, impede our growth and result in downward adjustments in our estimated proved oil and gas reserves.
Our revenue, profitability and cash flow depend upon the prices and demand for oil and natural gas. The markets for these commodities are very volatile, and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in oil and natural gas prices have a significant impact on the value of our reserves and on our cash flow. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:
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the domestic and foreign supply of oil and natural gas;
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economic conditions in the United States, and the level of consumer product demand;
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domestic and foreign governmental regulations;
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variations between product prices at sales points and applicable index prices.
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overall domestic and global economic conditions;
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political and economic conditions in oil producing countries, including the Middle East and South America;
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the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
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weather conditions;
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technological advances affecting energy consumption;
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proximity and capacity of oil and gas pipelines, refineries and other transportation facilities; and
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the price and availability of alternative fuels.
Lower oil and natural gas prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration or development results deteriorate, successful efforts accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.
Our exploratory and development drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We acquire significant amounts of unproved property in order to attempt to further our exploration and development efforts. Exploration and development drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. From time to time, we may seek industry partners to help mitigate our risk on certain exploration prospects. We cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, that we will recover all or any portion of our investment in such unproved property or wells, or that we will succeed in bringing on additional partners.
Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. We rely to a significant extent on seismic data and other advanced technologies in identifying unproved property prospects and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of unproved property or drilling a well, whether oil or natural gas is present or may be produced economically. The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies. Drilling results in our shale plays may be more uncertain than in other shale plays that are more mature and have longer established drilling and production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other shale formations to maximize recoveries will be ultimately successful when used in our shale prospects. As a result, we may incur future dry hole costs and or impairment charges due to any of these factors.
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A U.S. and global economic downturn could have a material adverse effect on our business and operations.
The European sovereign debt crisis has increased concerns about global economic recovery. Any or all of the following may occur as a result of a renewed crisis in the global financial and securities markets and resulting economic downturn:
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The economic slowdown could lead to lower demand for oil and natural gas by individuals and industries, which in turn has resulted and could continue to result in lower prices for the oil and natural gas sold by us, lower revenues and possibly losses. This is exacerbated by increases in gas supply resulting from increases in U.S. gas production.
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The lenders under our revolving credit facility may become more restrictive in their lending practices or unable or unwilling to fund their commitments, which would limit our access to capital to fund our capital expenditures and operations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth, leading to declining production and possibly losses.
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We may be unable to obtain additional debt or equity financing, which would require us to limit our capital expenditures and other spending. This would lead to lower growth in our production and reserves than if we were able to spend more than our cash flow. Financing costs may significantly increase as lenders may be reluctant to lend without receiving higher fees and spreads.
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The losses incurred by financial institutions as well as the insolvency of some financial institutions heightens the risk that a counterparty to our hedge arrangements could default on its obligations. These losses and the possibility of a counterparty declaring bankruptcy or being placed in conservatorship or receivership may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which could 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, adversely affected.
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Our credit facility bears floating interest rates based on the London Interbank Offer Rate, or LIBOR. As banks were reluctant to lend to each other to avoid risk, LIBOR increased to unprecedented spread levels in 2008. While spreads returned to normal levels in late 2009 and 2010, they increased again in late 2011 in response to the European sovereign debt crisis. While this increase did not reach the levels seen in 2008, such spread levels are possible in the future. Such increases cause higher interest expense for unhedged levels of LIBOR-based borrowings.
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Our credit facility requires the lenders to redetermine our borrowing base semi-annually. The redeterminations are based on our proved reserves and hedge position based on price assumptions that our lenders require us to use to calculate reserves pursuant to the credit facility. The lenders could reduce their price assumptions used to determine reserves for calculating our borrowing base due to lower commodities and futures prices and our borrowing base could be reduced. This would reduce our funds available to borrow.
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Bankruptcies of financial institutions or illiquidity of money market funds may limit or delay our access to our cash equivalent deposits, causing us to lose some or all of those funds or to incur additional costs to borrow funds needed on a short-term basis that were previously funded from our money market deposits.
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Bankruptcies of purchasers of our oil and natural gas could lead to the delay or failure of us to receive the revenues from those sales.
Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and
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acquisition of oil and natural gas reserves. To date, we have financed capital expenditures primarily with sales of our equity and debt securities, proceeds from bank borrowings and cash generated by operations. We intend to finance our capital expenditures with cash flow from operations and our existing financing arrangements. Our cash flow from operations and access to capital are subject to a number of variables, including:
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our proved reserves;
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the level of oil and natural gas we are able to produce from existing wells;
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the prices at which oil, natural gas and NGLs are sold;
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our ability to acquire, locate and produce new reserves;
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global credit and securities markets; and
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the ability and willingness of lenders and investors to provide capital and the cost of that capital.
If our revenues or the borrowing base under our credit facility decreases as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current or planned levels. We may, from time to time, need to seek additional financing. Our credit facility and senior note indentures place certain restrictions on our ability to obtain new financing. There can be no assurance as to the availability or terms of any additional financing.
If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves as well as our revenues and results of operations.
Drilling for and producing oil and natural gas are risky activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our drilling activities subject us to many risks, including the risk that we will not discover commercially productive reservoirs. 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 or subject us to liabilities as a result of other factors, including:
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unusual or unexpected geological formations or other features;
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pressures;
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fires;
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blowouts;
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loss of drilling fluid circulation;
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title problems;
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facility or equipment malfunctions;
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leaks of natural gas, oil, condensate, natural gas liquids, produced water and other hydrocarbons or losses of these hydrocarbons as a result of accidents during drilling and completion operations or in the gathering and transportation of hydrocarbons, malfunctions of or leaks from pipelines, measurement equipment or processing or other facilities in our operations or at delivery points to third parties;
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other hazards, including those associated with high-sulfur content, or sour gas, such as an accidental discharge of hydrogen sulfide gas;
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unexpected operational events;
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shortages or delivery delays of equipment and services;
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objections from surface owners and nearby surface owners in the areas where we operate;
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compliance with environmental and other governmental requirements and related lawsuits; and
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adverse weather conditions.
The occurrence of these events could also impact third parties, including persons living near our operations, our employees and employees of our contractors, leading to injuries, death, environmental damage, property damage, or suspension of operations. As a result, we face the possibility of liabilities from these events that could adversely affect our business, financial condition or results of operations as well as adverse publicity that could lead to delays in or cessation of our operations in the affected area and loss of related assets or revenues.
Additionally, the coalbeds in the Powder River Basin from which we produce methane gas typically contain water, which may hamper our ability to produce gas in commercial quantities. This water must be partially removed in order for the gas to detach from the coal and flow to the well bore. Our ability to remove and economically dispose of sufficient quantities of water from the coal seam will determine whether we can produce coalbed methane in commercial quantities.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.
We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. For example, we do not carry business interruption insurance for these reasons. Thus, losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.
We are subject to complex federal, state, tribal, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business and the recording of proved reserves.
Our exploration, development, production and marketing operations are subject to extensive environmental regulation at the federal, state and local levels including those governing emissions to air, wastewater discharges, hazardous and solid wastes, remediation of soil, protection of surface and groundwater, and preservation of natural resources. In addition, a portion of our leases in the Uinta Basin are, and some of our future leases may be, regulated by Native American tribes. 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 and subject us to administrative, civil, and criminal penalties, including the assessment of natural resource damages. Environmental and other governmental laws and regulations also increase the costs to plan, design, drill, install, operate and abandon oil and natural gas wells and related facilities. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.
Our Powder River Basin coalbed methane exploration and production activities involve the permitted discharge of produced groundwater into adjacent lands and waterways. The environmental soundness of discharging produced groundwater pursuant to water discharge permits has come under increased scrutiny. Moratoriums on the issuance of additional water discharge permits, or requirements for more costly methods of handling these produced waters, may affect future well development. Compliance with more stringent laws or regulations, more vigorous enforcement policies of the regulatory agencies, difficulties in negotiating required surface use agreements with land owners or receiving other governmental approvals could delay our Powder
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River Basin exploration and production activities and/or require us to make material expenditures for the installation and operation of systems and equipment for pollution control and/or remediation, all of which could have a material adverse effect on our financial condition or results of operations.
Part of the regulatory environment in which we operate includes, in some cases, federal requirements for performing or preparing environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to state regulation of oil and natural gas production and Native American tribes conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling and other permits from state, local and Native American tribal authorities. Delays in obtaining regulatory approvals or drilling and other permits, 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 on or develop our properties. In addition, if we do not reasonably believe that we can obtain the drilling permits in a timely fashion covering locations for which we recorded proved undeveloped reserves, we may be required to write down the level of our proved reserves. 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, larger operating areas, and other aspects of their businesses. See “Items 1 and 2. Business and Properties-Business-Operations-Environmental Matters and Regulation” and “Items 1 and 2. Business and Properties-Business-Operations-Other Regulation of the Oil and Gas Industry.”
Federal and state legislation and regulatory initiatives relating to well completion techniques known as hydraulic fracturing could result in increased costs and additional operating restrictions or delays and inability to book future reserves.
Hydraulic fracturing is a well completion technique that involves the injection of water, sand and chemicals under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate oil and natural gas production. Sponsors of bills proposed before the U.S. Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies, and the proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process. Under the direction of Congress, the EPA has undertaken a study of the effect of well completion techniques known as hydraulic fracturing on drinking water and groundwater. Congress also is currently considering legislation to amend the Federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Certain states, including Colorado and Wyoming, have issued similar disclosure rules. In addition, the Department of Interior is considering expanded or new regulations concerning the use of hydraulic fracturing on lands under its jurisdiction, which includes many of the lands on which we conduct or plan to conduct operations. The adoption of any future federal or state laws or implementing regulations imposing reporting or permitting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to perform, or even prohibit, hydraulic fracturing, and complete oil and natural gas wells. Any such laws and or regulations may also increase our costs of compliance and doing business, and prevent us from accessing, developing and recording reserves in the future.
Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these assumptions will materially affect the quantities of our reserves.
Underground accumulations of oil and natural gas cannot be measured in an exact way. Oil and natural gas reserve engineering requires estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be incorrect.
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Our estimates of proved reserves are determined at prices and costs at the date of the estimate. Any significant variance from these prices and costs could greatly affect our estimates of reserves. We prepare our own estimates of proved reserves, which are audited by independent third party petroleum engineers. Over time, our internal engineers may make material changes to reserves estimates taking into account the results of actual drilling, testing and production. For additional information about these risks and their impact on our reserves, see “Items 1 and 2. Business and Properties-Oil and Gas Data-Proved Reserves” and “Supplementary Information to Consolidated Financial Statements-Supplementary Oil and Gas Information (unaudited)-Analysis of Changes in Proved Reserves” in this Annual Report on Form 10-K.
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. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent upon 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 or acquire additional reserves to replace our current and future production at acceptable costs.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.
We describe some of our prospects and our plans to explore those prospects in “Items 1 and 2. Business and Properties.” A prospect is a specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons. 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 oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to recover drilling or completion costs or to be economically viable. If we drill additional wells that we identify as dry holes in our current and future prospects, our drilling success rate may decline and materially harm our business. The cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive. Such uncertainties may harm our business and results of operations.
Certain of our coalbed methane leases in the Powder River Basin are in areas that may have been partially depleted or drained by offset wells or impacted by nearby coal mining activities.
In the Powder River Basin, nearly all of our current operations are in coalbed methane plays, and our key project areas are located in areas that have been the most active drilling areas in the Rockies. As a result, many of our leases are in areas that may have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of natural gas in these areas. In addition, activities related to the mining of coal near our operations, including core-hole drilling to determine the aerial extent of coal deposits and the mining of coal, may introduce oxygen into our producing wells and compressors, causing production to be shut-in, or allowing hydrocarbons to escape before they can be recovered. This would lead to a loss of reserves and revenues.
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,
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including the availability of capital, seasonal conditions, regulatory approvals, natural gas and oil prices, costs and drilling 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 oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may differ materially differ from those presently identified, which could adversely affect our business.
Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas and, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures and the amount of hydrocarbons. We are employing 3C 3-D seismic technology to evaluate certain of our projects. The implementation and practical use of 3C 3-D seismic technology is relatively new, unproven and unconventional, which can lessen its effectiveness, at least in the near term, and increase our costs. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.
We often gather 3-D seismic data over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and, in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 3-D data without having an opportunity to attempt to benefit from those expenditures.
Substantially all of our producing properties are located in the Rocky Mountains, making us vulnerable to risks associated with operating in one major geographic area.
Our operations have been focused on the Rockies, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of oil and natural gas produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells.
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 are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. 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.
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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.
One of our growth strategies is to capitalize on opportunistic acquisitions of oil and natural gas reserves. Our reviews of acquired properties are inherently incomplete, because it generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties and will sample the remaining properties for reserve potential. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties.
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of our reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and refineries owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for a lack of a market or because of inadequacy or unavailability of natural gas pipeline, gathering system capacity or processing facilities. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver the production to market.
Our hedging activities could result in financial losses or could reduce our income.
To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of commodities, we currently, and will likely in the future, enter into hedging arrangements for a significant portion of our production revenues. Hedging arrangements for a portion of our production revenues expose us to the risk of financial loss in some circumstances, including when:
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there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received;
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there is a change in the mark to market value of our derivatives; or
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the counterparty to the hedging contract defaults on its contractual obligations.
In addition, these types of hedging arrangements limit the benefit we would receive from increases in commodities prices and may expose us to cash margin requirements if we hedge with counterparties who are not parties to our credit facility.
Our counterparties are typically financial institutions that are lenders under our credit facility or affiliates of such lenders. The risk that a counterparty may default on its obligations was heightened by the financial sector crisis of 2008-2009, the current European sovereign debt crisis and losses incurred by many banks and other financial institutions, including some of 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 production revenues, thus triggering the hedge payments. As a result, our financial condition could be materially adversely affected.
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Federal legislation may decrease our ability to enter into, and increase the cost, and risk of entering into, hedge transactions.
The Dodd-Frank Wall Street Reform and Consumer Protective Act (“Dodd-Frank” or the “new law”) was signed into law on July 21, 2010. Dodd-Frank regulates derivative transactions, including our commodity derivative swaps. The new law required the Treasury Department to implement final administrative procedures related to derivatives within one year, but many of such procedures have still not been implemented. The effect of such rules on our business is currently uncertain. However, we expect that as a commercial end user using derivatives to manage commercial risks, we will be exempt from posting collateral requirements and mandatory trading on a centralized exchange. We expect to be able to continue to trade with our counterparties, which are all lenders in our credit facility, or affiliates of lenders, although we may only be able to hedge with separately capitalized affiliates of our lenders. We do expect that the cost to hedge will increase as a result of fewer counterparties in the market and the pass-through of increased capital costs of bank subsidiaries. Decreasing our ability to enter into hedging transactions would expose us to additional risks related to commodity price volatility and impair our ability to have certainty with respect to a portion of our cash flow, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves. Entering into hedging transactions with an affiliate of a lender will, in the absence of a guarantee from such lender of the obligations of its affiliate, likely eliminate our ability to offset amounts we owe such lender against amounts owed us under such hedging agreements thereby increasing our risk under such hedging agreements.
The inability of one or more of our customers to meet their obligations may adversely affect our financial results.
Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil and natural gas hedging arrangements expose us to credit risk in the event of nonperformance by counterparties. An economic downturn, a delayed economic recovery, and the European sovereign debt crisis further increase these risks.
Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies are able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or integrated competitors are better able to absorb the burden of existing and any changes to federal, state, local and Native American tribal laws and regulations than we are, which could adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.
The ability of our lenders to fund their lending obligations under our revolving credit facility may be limited, which would affect our ability to fund our operations.
Our revolving credit facility has commitments from 17 lenders. If credit markets become turbulent as a result of an economic downturn, delayed economic recovery or other factors, our lenders may become more restrictive in their lending practices or may be unable to fund their commitments, which would limit our access to
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capital to fund our capital expenditures and operations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth, leading to declining production and potentially losses and could lead to defaults by our hedge counterparties.
We face risks related to rating agency downgrades.
If one or more rating agencies downgrades our outstanding debt, raising debt capital could become more difficult and more costly and we may be required to provide collateral or other credit support to certain counterparties. Providing credit support increases our costs and can limit our liquidity.
Compliance with Environmental Protection Agency (“EPA”) regulations is expected to become increasingly costly and may lead to our inability to obtain permits necessary to construct and operate new facilities.
The EPA regulates the level of ozone in ambient air and may propose to lower the allowed level of ozone in the future. Because of climate processes, most of the Rockies, where we operate, has higher levels of ozone. As a result of these existing and possible more stringent standards, we may not be able to obtain permits necessary to construct and operate new facilities, or, if we obtain the permits, the added costs to comply with the permit requirements could substantially increase our operating expenses, which would reduce our profits or make certain operations uneconomical.
Possible additional regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and gas.
Scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases”, including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. The Kyoto Protocol to the United Nations Framework Convention on Climate Change went into effect in February 2005 and requires all industrialized nations that ratified the Protocol to reduce or limit greenhouse gas emissions to a specified level by 2012. The United States has not ratified the Protocol, and the U.S. Congress has not passed proposed legislation directed at reducing greenhouse gas emissions. However, there is increasing public pressure from environmental groups and some states for the United States to develop a national program for regulating greenhouse gas emissions, and several states have already adopted regulations or announced initiatives focused on decreasing or stabilizing greenhouse gas emissions associated with industrial activity, primarily CO2 emissions from power plants. The EPA has also taken certain regulatory actions to address issues related to climate change. Passage of state or federal climate control legislation or other regulatory initiatives or the adoption of regulations by the EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse effect on our operations and demand for oil and gas.
Possible additional regulation could have an adverse effect on our operations.
Proposed energy legislation and new regulations, driven in part by the Macondo oil spill in the Gulf of Mexico, could limit our ability to operate on federal lands, delay access to federal lands, and increase the cost of our operations. These include the Consolidated Land, Energy, and Aquatic Resources Act (CLEAR), the Clean Energy Jobs and Oil Company Accountability Act, the Blowout Prevention Act, and public land leasing reforms. The inability to access federal lands, as well as delays and the increased cost of operating on federal lands could result in losses of revenues, increased costs and devaluing of our assets.
Our business could be negatively impacted by security threats, including cyber-security threats, and other disruptions.
As an oil and natural gas producer, we face various security threats, including cyber-security threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the safety of our employees, threats to the security of our facilities and infrastructure or third party facilities and infrastructure,
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such as processing plants and pipelines, and threats from terrorist acts. Cyber-security attacks in particular are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities, essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.
Risks Related to Our Common Stock
Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of us, which could adversely affect the price of our common stock.
Delaware corporate law and our current certificate of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us or our management. These provisions include:
•
a classified board of directors;
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giving the board the exclusive right to fill all board vacancies;
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permitting removal of directors only for cause and with a super-majority vote of the stockholders;
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requiring special meetings of stockholders to be called only by the board;
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requiring advance notice for stockholder proposals and director nominations;
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prohibiting stockholder action by written consent;
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prohibiting cumulative voting in the election of directors; and
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allowing for authorized but unissued common and preferred shares, including shares used in our shareholder rights plan.
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, which may limit the price that investors are willing to pay in the future for shares of our common stock.
Risks Related to our Senior Notes, Convertible Notes and Amended Credit Facility
We may not be able to generate enough cash flow to meet our debt obligations, including our obligations and commitments under our senior notes, our convertible senior notes and our revolving credit facility.
We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. In addition, our future cash flow may be insufficient to meet our debt obligations and commitments, including our 9.875% Senior Notes due 2016 (“9.875% Senior Notes”) and our 7.625% Senior Notes due 2019 (“7.625% Senior Notes”), our 5% Convertible Senior Notes due 2028 (“Convertible Notes”) and our revolving credit facility (“Amended Credit Facility”). Any insufficiency could negatively impact our business. A range of economic, competitive, business, and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to repay our debt, including the notes. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.
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As of December 31, 2011, the total outstanding principal amount of our long term indebtedness was approximately $892.5 million, and we had approximately $804.0 million in additional borrowing capacity under our Amended Credit Facility, which, if borrowed, would be secured debt effectively senior to the Senior Notes and Convertible Notes to the extent of the value of the collateral securing that indebtedness. Our Amended Credit Facility has $900.0 million in commitments. The borrowing base is dependent on our proved reserves and was, as of December 31, 2011, $1.1 billion based on our June 30, 2011 proved reserves and hedge position. Our borrowing capacity is reduced by a $26.0 million letter of credit. As of December 31, 2011, the outstanding principal balance under our Amended Credit Facility was $70.0 million.
If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake one or more alternative financing plans, such as:
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refinancing or restructuring our debt;
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selling assets;
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reducing or delaying capital investments; or
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seeking to raise additional capital.
However, any alternative financing plans that we undertake, if necessary, may not allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including our obligations under the notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.
Our debt could have important consequences. For example, it could:
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increase our vulnerability to general adverse economic and industry conditions;
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limit our ability to fund future capital expenditures and working capital, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive terms of our debt;
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limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
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impair our ability to obtain additional financing in the future; and
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place us at a competitive disadvantage compared to our competitors that have less debt.
In addition, if we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders and holders of our convertible notes and our senior notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. Realization of any of these factors could adversely affect our financial condition.
Restrictions in our existing and future debt agreements could limit our growth and our ability to respond to changing conditions.
Our Amended Credit Facility contains a number of significant covenants in addition to covenants restricting the incurrence of additional debt. Our Amended Credit Facility requires us, among other things, to maintain certain financial ratios or reduce our debt. These restrictions also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the indenture governing the notes and our Amended Credit Facility impose on us.
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Our Amended Credit Facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine based upon projected revenues from the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Amended Credit Facility. Any increase in the borrowing base requires the consent of the lenders holding 98% 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. Outstanding borrowings in excess of the borrowing base must be repaid immediately or we must pledge other oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make mandatory principal prepayments required under the Amended Credit Facility.
A breach of any covenant in our Amended Credit Facility or the agreements and indentures governing our other indebtedness would result in a default under that agreement or indenture after any applicable grace periods. A default, if not waived, could result in acceleration of the debt outstanding under the agreement and in a default with respect to, and an acceleration of, the debt outstanding under other debt agreements. The accelerated debt would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such debt or take other actions to pay accelerated debt. Even if new financing were available at that time, it may not be on terms that are acceptable to us.
Risks Relating to Tax
We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions currently available with respect to oil and natural gas exploration and development are eliminated as a result of future legislation.
President Obama has proposed eliminating certain key U.S. federal income tax deductions and credits currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to
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the repeal of the percentage depletion allowance for oil and natural gas properties,
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the elimination of current deductions for intangible drilling and development costs,
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the elimination of the deduction for certain U.S. production activities,
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an extension of the amortization period for certain geological and geophysical expenditures.
It is unclear whether any of the foregoing changes will actually be enacted or how soon any such changes could become effective. The passage of any legislation changing U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to oil and natural gas exploration and development. Any such change could negatively impact our financial condition and results of operations by increasing the costs we incur which in turn would make it uneconomic to drill some prospects if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.
Item 1B.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 3.
Item 3. Legal Proceedings
We are not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable
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PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market For Registrant’s Common Equity.
Our common stock is listed on the New York Stock Exchange under the symbol “BBG.”
The range of high and low sales prices for our common stock for the two most recent fiscal years as reported by the New York Stock Exchange was as follows:
On January 27, 2012, the closing sales price for our common stock as reported by the NYSE was $27.53 per share.
Holders. On January 27, 2012, the number of holders of record of common stock was 468.
Dividends. We have not paid any cash dividends since our inception. Because we anticipate that all earnings will be retained for the development of our business and our Amended Credit Facility and Senior Notes prohibit the payment of cash dividends, no cash dividends will be paid on our common stock in the foreseeable future. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional discussion of restrictions on the payment of dividends.
Unregistered Sales of Securities There were no sales of unregistered equity securities during the year ended December 31, 2011.
Issuer Purchases of Equity Securities. The following table contains information about our acquisitions of equity securities during the three months ended December 31, 2011:
(1) Represents shares delivered by employees to satisfy the exercise price of stock options and tax withholding obligations in connection with the exercise of stock options and shares withheld from employees to satisfy tax withholding obligations in connection with the vesting of shares of restricted common stock issued pursuant to our employee incentive plans.
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Stockholder Return Performance Presentation
As required by applicable rules of the SEC, the performance graph shown below was prepared based upon the following assumptions:
1. $100 was invested in our common stock on December 31, 2006, and $100 was invested in each of the Standard & Poors 500 Index and the Standard & Poors MidCap 400 Index-Energy Sector at the closing price on December 31, 2006.
2. Dividends are reinvested on the ex-dividend dates.
Item 6.
Item 6. Selected Financial Data
The following table presents our selected historical financial data for the years ended December 31, 2011, 2010, 2009, 2008 and 2007. Future results may differ substantially from historical results because of changes in oil and gas prices, production increases or declines and other factors. This information should be read in conjunction with the consolidated financial statements and notes thereto and “Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction
The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the accompanying consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This section and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties. See the “Cautionary Note Regarding Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K. Forward-looking statements are not guarantees of future performance and our actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed in the subsection entitled “Risk Factors” above, which are incorporated herein by reference. We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.
Overview
We explore for and develop oil and natural gas in the Rocky Mountain region of the United States. We seek to build stockholder value through profitable growth in reserves and production, which we expect will include investing in and profitably developing key existing development programs as well as growth through exploration and acquisitions. We seek high quality exploration and development projects with potential for providing long-term drilling inventories that generate high returns. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGLs recovery at market prices and from the settlement of commodity hedges.
We were formed in January 2002 and are incorporated in the State of Delaware. In December 2004, we completed our initial public offering of 14,950,000 shares of our common stock at a price to the public of $25.00 per share. Since inception, we have built our portfolio of exploration and development properties primarily through acquisitions where we seek to add value through our geologic and operational expertise. Our acquisitions have included key assets in the Piceance (Colorado) Uinta (Utah), Denver-Julesburg (Colorado and Wyoming), Powder River (Wyoming) and Wind River (Wyoming) Basins in the Rockies.
We are committed to exploring for, developing and producing oil and natural gas in a responsible manner. We work diligently with environmental, wildlife and community organizations to ensure that our exploration and development activities are designed with all stakeholders in mind.
While there are currently no unannounced agreements for the acquisition of any material businesses or assets, future acquisitions could have a material impact on our financial condition and results of operations by increasing our proved reserves, production, and revenues as well as expenses and future capital expenditures. We currently anticipate that we would finance any future acquisitions with available borrowings under our Amended Credit Facility, other indebtedness, and/or debt, equity or equity-linked securities. Our prior acquisitions and capital expenditures were financed with a combination of funding from the sale of our equity securities, our Amended Credit Facility, other debt financing and cash flows from operations.
Because of our rapid growth through acquisitions and, more recently, development of our properties, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful. In addition past results are not indicative of future results.
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The following table summarizes the estimated net proved reserves and related Standardized Measure for the years indicated. The Standard Measure is not intended to represent the current market value of our estimated oil and natural gas reserves.
(1) December 31, 2011 was based on average prices of $3.93 CIG for natural gas and $92.71 WTI for oil using the current SEC requirements. December 31, 2010 was based on average prices of $3.95 CIG for natural gas and $75.96 WTI for oil using the current SEC requirements. December 31, 2009 was based on average prices of $3.04 CIG for natural gas and $57.65 WTI for oil using the current SEC requirements.
The following table summarizes the average sales prices received for natural gas and oil, before the effects of hedging contracts, for the years indicated:
The following table summarizes the average sales prices received for natural gas and oil, after the effects of hedging contracts, for the years indicated:
Commodity prices, particularly in the Rockies, are inherently volatile and are influenced by many factors outside of our control. We plan our activities and capital budget using what we believe to be conservative sales price assumptions and our existing hedge position. Our strategic objective is to hedge 50% to 70% of our anticipated production on a forward 12-month basis using a combination of swaps, cashless collars and other financial derivative instruments. We focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our revenues and overall cost structure to a level that allows for profitable production.
Like all oil and gas exploration and production companies, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and gas production from a typical well naturally decreases. Thus, an oil and gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. See “ -Trends and Uncertainties-Regulatory Trends” below. The permitting and approval process has been more difficult in recent years than in the past due to more stringent rules, such as those enacted by the Colorado Oil and Gas Conservation Commission (“COGCC”) in 2009, increased activism from environmental and other groups, which has extended the time it takes us to receive permits, and other necessary approvals. Because of our relatively small size and concentrated property base, we
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can be disproportionately disadvantaged by delays in obtaining or failing to obtain drilling approvals compared to companies with larger or more dispersed property bases. As a result, we may be less able to shift drilling activities to areas where permitting may be easier, and we have fewer properties over which to spread the costs related to complying with these regulations and the costs or foregone opportunities resulting from delays.
Results of Operations
The following table sets forth selected operating data for the periods indicated:
Year Ended December 31, 2011 Compared with Year Ended December 31, 2010
(1) Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense in the Consolidated Statements of Operations for a total of $66.8 million and $57.8 million for the years ended December 31, 2011 and 2010, respectively. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash
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component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expense. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower stock-based compensation expense.
(2) Average prices shown in the table are net of the effects of all of our realized commodity hedging transactions. Our average realized price calculation includes all cash settlements for commodity derivatives, whether or not they qualify for hedge accounting. As a result of our realized hedging transactions, natural gas production revenues and oil production revenues increased (decreased) by the following (in millions):
Before the effects of hedging, the average prices we received for natural gas and oil were as follows:
(3) Excludes non-cash stock-based compensation expense as described in footnote (1) above. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation expense, as presented in the Consolidated Statements of Operations, were $0.63 and $0.60 for the years ended December 31, 2011 and 2010, respectively.
(4) Natural gas average prices include the effect of NGL related revenue.
Production Revenues and Volumes. Production revenues increased to $780.8 million for the year ended December 31, 2011 from $708.5 million for the year ended December 31, 2010 due to an 11% increase in production and a 1% decrease in oil and natural gas prices on a per Mcfe basis after the effects of realized cash flow hedges. The effects of realized hedges only include settlements from hedging instruments that were designated as cash flow hedges and exclude those that do not qualify, or were not designated, as cash flow hedges such as basis only and NGL swaps. The settlements from hedging instruments that were not designated as cash flow hedges are included in the line item “Commodity derivative loss” within operating revenues in the Consolidated Statements of Operations. See below for more information related to the Commodity derivative loss line item. The net increase in production added approximately $75.3 million of production revenues, and the decrease in average price reduced production revenues by approximately $3.0 million.
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Total production volumes increased to 106.8 Bcfe for the year ended December 31, 2011 from 96.5 Bcfe for the year ended December 31, 2010 due to increased production in the Piceance, Uinta and Powder River Basins and production from the DJ Basin wells we acquired in August 2011. The increased production was partially offset by a decrease in production in the Wind River Basin. Additional information concerning production is in the following table:
* Not meaningful.
The production increase in the Piceance Basin was primarily the result of our initial sales from 119 new gross wells during 2011. The production increase in the Uinta Basin resulted primarily from our development activities in the West Tavaputs area with initial sales from 86 new gross wells during 2011. In addition, we had increased production resulting from our Uinta Oil Program at Blacktail Ridge and Lake Canyon, which had initial sales from 33 new gross wells during 2011, as well as the acquisition of East Bluebell in June 2011, which added 610 MMcfe of additional production. The production increase in the Powder River Basin was due to increased oil production in the Powder River Basin due to initial sales on 20 new gross conventional wells in 2011, offset by natural production declines in our natural gas producing coalbed methane fields with no significant drilling or recompletion activities to offset these declines. Further, the producing wells we acquired within the DJ Basin field in August 2011, added to our production increases during 2011. The production decrease in the Wind River Basin was due to natural production declines with no significant drilling or recompletion activities to offset these declines.
Hedging Activities. In 2011, approximately 67% of our natural gas volumes (excluding basis-only swaps, which were equivalent to 7% of our natural gas volumes), 53% of our NGL related recoveries and 66% of our oil volumes were subject to financial hedges, which resulted in an increase in natural gas revenues of $73.9 million and a decrease in oil revenues of $2.0 million after settlements for all commodity derivatives, including basis-only and NGL swaps. In 2010, approximately 74% of our natural gas volumes (excluding basis-only swaps, which were equivalent to 12% of our natural gas volumes), 54% of NGL related volumes and 53% of our oil volumes were subject to financial hedges, which resulted in an increase in natural gas revenues of $133.2 million and an increase in oil revenues of $2.2 million after settlements for all commodity derivatives, including basis-only swaps. The decrease in revenues related to hedging natural gas resulted from the expiration of hedges entered into at higher prices and our inability to enter into new hedges at those prices because natural gas prices have fallen since we entered into those hedges. This trend is expected to continue based on future prices and hedge quotes.
Commodity Derivative Loss. The “Commodity derivative loss” line item on the Consolidated Statements of Operations is comprised of ineffectiveness on cash flow hedges and realized and unrealized gains and losses on hedges that do not qualify for cash flow hedge accounting or were not designated as cash flow hedges. Ineffectiveness on cash flow hedges relates to slight differences between the contracted location and the actual delivery location. Unrealized gains and losses represent the change in the fair value of the derivative instruments
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that do not qualify for cash flow hedge accounting, which includes our basis only swaps and NGL swaps. As those instruments settle, their settlement will be presented as realized gains and losses within this same line item. In addition to the basis only and NGL swaps, we had certain cash flow hedges that were de-designated in 2011 and settled prior to December 31, 2011. As a result, their settlements were reflected in realized gains and losses for the year ended December 31, 2011.
Commodity derivative loss decreased to a loss of $14.3 million for the year ended December 31, 2011 from a loss of $10.6 million for the year ended December 31, 2010 primarily due to the increase in realized losses and the decrease in unrealized gains resulting from the change in fair value of our basis only swaps as of December 31, 2011.
The table below summarizes the realized and unrealized gains and losses we recognized in commodity derivative loss for the periods indicated:
Effective January 1, 2012, we elected to discontinue hedge accounting prospectively. Consequently, as of January 1, 2012 we will no longer designate any hedges as cash flow hedges and we will de-designate all commodity hedge instruments that were previously designated as cash flow hedges. As such, subsequent to January 1, 2012, we will recognize unrealized gains and losses from prospective changes in commodity derivative fair values immediately in the consolidated statement of operations rather than deferring any such amounts in accumulated other comprehensive income. This change in reporting will have no impact on our reported cash flows, although future results of operations will be affected by unrealized gains and losses, which fluctuate with volatile oil and gas prices. We expect to reclassify $50.8 million of the net after-tax derivative loss from AOCI to earnings during the next 12 months.
Other Operating Revenues. Other operating revenues increased to $4.9 million for the year ended December 31, 2011 from $0.6 million for the year ended December 31, 2010. Other operating revenues for 2011 primarily consisted of $2.9 million of income from gathering, compression and salt-water disposal fees received from third parties and $2.0 million in net gains realized from the sale and exchange of properties. Other operating revenues for 2010 consisted of $2.6 million of income from gathering, compression and salt-water disposal fees received from third parties offset by $2.0 million in net losses realized from the sale and exchange of properties.
Lease Operating Expense. Lease operating expense decreased to $0.53 per Mcfe for the year ended December 31, 2011 from $0.54 per Mcfe for the year ended December 31, 2010. The year ended December 31, 2010 included $2.4 million of nonrecurring remediation efforts related to a minor condensate leak at the Dry Canyon Compressor Station in the Uinta Basin, which increased lease operating expense by $0.02 per Mcfe. The drilling program in our Blacktail Ridge field in the Uinta Basin throughout 2011 has increased water production. The additional trucking and disposal costs associated with this water production are primarily responsible for the overall increase in lease operating expense.
Gathering, Transportation and Processing Expense. Gathering, transportation and processing expense increased to $0.87 per Mcfe for the year ended December 31, 2011 from $0.72 per Mcfe for the year ended December 31, 2010. Increased production from the West Tavaputs field within the Uinta Basin has led to an increase in volumes gathered, transported and processed under higher cost structured agreements, that resulted in
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higher costs on a per unit basis. As a result, gathering, transportation and processing expense increased approximately $0.10 per Mcfe for the year ended December 31, 2011 compared to the year ended December 31, 2010. Firm transportation agreements related to West Tavaputs that became effective in late July 2011 for the Ruby Pipeline and Wyoming Interstate Company Pipeline were the primary reason for this increase. The remaining increase in gathering, transportation and processing expense on a per unit basis related to new gathering and transportation agreements in the Blacktail Ridge field and the Piceance Basin, which added approximately $0.02 per Mcfe for each area. In 2011, we incurred one-time charges of $0.01 per Mcfe related to gathering and processing agreements in the Paradox and Powder River Basins.
We have entered into long-term firm transportation contracts for a portion of our production to guarantee capacity on major pipelines and reduce the risk and impact related to possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production in the Piceance and Uinta Basins where we expect to allocate a portion of our capital expenditure programs in future years. In addition, we have entered into long-term firm processing contracts on a portion of our production in the Piceance and Uinta Basins. Included in gathering, transportation and processing expense are $0.33 and $0.19 per Mcfe of firm transportation and gathering expense for the years ended December 31, 2011 and 2010, respectively, and $0.05 and $0.04 per Mcfe of firm processing expense from long-term contracts for years ended December 31, 2011 and 2010 respectively. The increase in firm transportation and gathering expense to $0.33 per Mcfe for the year ended December 31, 2011 compared with $0.18 per Mcfe for the year ended December 31, 2010 was the result of additional long-term contracts executed with various pipelines for our natural gas production in the Piceance and Uinta Basins as mentioned above.
Production Tax Expense. Total production taxes increased to $37.5 million for the year ended December 31, 2011 from $32.7 million for the year ended December 31, 2010. The increase in production taxes is primarily related to an increase in production revenues during the year ended December 31, 2011. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production tax expense for the year ended December 31, 2010 included a one-time reduction of $2.2 million related to amended 2004 through 2009 State of Utah annual severance tax calculations. Production taxes as a percentage of natural gas and oil sales before hedging adjustments was 5.5% for the year ended December 31, 2011 compared with 6.0% for the year ended December 31, 2010, which included a reduction of 0.4% related to the nonrecurring item associated with Utah severance taxes.
Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas. The decrease in the overall production tax rate is consistent with our production increase throughout 2011 from states with lower production tax rates.
Exploration Expense. Exploration expense decreased to $3.6 million for the year ended December 31, 2011 from $9.1 million for the year ended December 31, 2010. Exploration expense for the year ended December 31, 2011 consisted of $2.7 million for seismic programs and $0.9 million for delay rentals. Exploration expense for the year ended December 31, 2010 consisted of $3.5 million for seismic programs, $1.1 million for delay rentals, $0.1 million related to the evaluation of non-acquired assets and $4.4 million for one scientific well drilled for data gathering purposes.
Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense increased to $117.6 million for the year ended December 31, 2011 from $44.7 million for the year ended December 31, 2010. For the year ended December 31, 2011, impairment expense was $100.3 million, abandonment expense was $3.9 million and dry hole costs were $13.4 million. For the year ended December 31, 2010, impairment expense was $15.6 million, abandonment expense was $2.6 million and dry hole costs were $26.5 million.
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We evaluate the impairment of our proved oil and gas properties on a property-by-property basis whenever events or changes in circumstances indicate a property’s carrying amount may not be recoverable. If the carrying amount exceeds the property’s estimated fair value, we will adjust the carrying amount of the property to fair value through a charge to impairment expense. As a result of declining natural gas prices, we recorded a $75.2 million impairment charge regarding proved oil and gas properties within the CBM fields of the Powder River Basin and a $7.6 million impairment charge regarding proved oil and gas properties within the Wallace Creek field of the Wind River Basin for the year ended December 31, 2011. For the year ended December 31, 2010, we did not record any impairment charges on proved oil and gas properties.
Unproved oil and gas properties are also assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop existing acreage. During the year ended December 31, 2011, we recorded a $17.5 million impairment charge regarding unproved oil and gas properties within various exploration projects. This non-cash impairment charge was primarily a result of unfavorable market conditions as well as uneconomic drilling results in exploratory areas where we currently have no plans to develop or evaluate the remaining acreage. For the year ended December 31, 2010, we recorded a $15.6 million impairment charge regarding unproved oil and gas properties within various exploration projects.
We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices because we will be less likely to devote capital to exploration activities. We continue to review our acreage position and future drilling plans based on the current price environment. If our attempts to market interests in certain properties to industry partners are unsuccessful, additional leasehold impairments and abandonments in exploration prospects may be recorded.
We account for oil and gas exploration and production activities using the successful efforts method of accounting under which we capitalize exploratory well costs until a determination is made as to whether or not the wells have found proved reserves. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well, and we are making sufficient progress assessing the reserves and the economic and operating viability of the project. If proved reserves are not assigned to an exploratory well, the costs of drilling the well are charged to expense. Otherwise, the costs remain capitalized and are depleted as production occurs. As of December 31, 2011, there were no exploratory well costs included in unproved oil and gas properties that had been capitalized for a period greater than one year since the completion of drilling.
Dry hole costs of $13.4 million for the year ended December 31, 2011 were associated with one uneconomic exploratory well in the McRae Gap prospect of the Wind River Basin and two unsuccessful exploratory wells within the northern DJ Basin on acreage acquired prior to our 2011 DJ Basin acquisition. Dry hole costs of $26.5 million for the year ended December 31, 2010 were associated with seven unsuccessful exploratory wells within the Paradox Basin and one unsuccessful exploratory well in each of the Uinta and Big Horn basins.
Depreciation, Depletion and Amortization. DD&A was $288.4 million for the year ended December 31, 2011 compared with $260.7 million for the year ended December 31, 2010. The increase of $27.7 million was a result of increased production during the year ended December 31, 2011 compared with the year ended December 31, 2010. The weighted average DD&A rate for each of the years ended December 31, 2011 and 2010 was $2.70 per Mcfe. Under successful efforts accounting, DD&A expense is separately computed for each producing area based on geologic and reservoir delineation. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a weighted average DD&A rate for current production. Future DD&A rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.
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General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased to $47.7 million for the year ended December 31, 2011 from $40.9 million for the year ended December 31, 2010. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 47 for a reconciliation and explanation. This increase was primarily due to a 12% increase in headcount in 2011, which increased employee compensation and benefits. On a per Mcfe basis, general and administrative expense, excluding non-cash stock based compensation, increased to $0.45 in 2011 from $0.42 in 2010.
Non-cash stock-based compensation expense was $19.0 million for the year ended December 31, 2011 compared with $16.9 million for the year ended December 31, 2010. Non-cash stock-based compensation expense for 2011 and 2010 related primarily to the vesting of our stock option awards and nonvested shares of common stock granted to employees.
The components of non-cash stock-based compensation expense for 2011 and 2010 are shown in the following table:
Interest Expense. Interest expense increased to $58.6 million for the year ended December 31, 2011 from $44.3 million for the year ended December 31, 2010. The increase was primarily due to an increase in our weighted average outstanding debt, including our Amended Credit Facility, Convertible Notes, 9.875% Senior Notes and 7.625% Senior Notes, to $587.4 million for the year ended December 31, 2011 from $403.4 million for the year ended December 31, 2010. The increase in our weighted average outstanding debt was primarily due to the issuance of our $400.0 million aggregate principal amount of 7.625% Senior Notes on September 27, 2011 and an increase in the outstanding debt balance on our Amended Credit Facility during the year ended December 31, 2011. However, our effective interest rate decreased to 10.2% for the year ended December 31, 2011 compared with 12.1% for the year ended December 31, 2010.
Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. We capitalized interest costs of $1.4 million and $4.2 million for the years ended December 31, 2011 and 2010, respectively. For the year ended December 31, 2011, we had fewer projects in progress as compared with the year ended December 31, 2010, which resulted in a lower amount of interest costs that were capitalized during the period.
Income Tax Expense. Income tax expense totaled $17.7 million and $48.0 million for the years ended December 31, 2011 and 2010, resulting in effective tax rates of 36.5% and 37.3% in 2011 and 2010, respectively. Our effective tax rate differs from the federal statutory rate primarily because we recorded stock-based compensation expense and other operating expenses that are not deductible for income tax purposes as well as the effect of state income taxes. The effective tax rate decrease from 2010 to 2011 was primarily the result of a net reduction in permanent differences affecting the tax rate calculation, principally the increase in tax deductible compensation related to incentive stock options. Additionally, a greater proportion of our operating revenue was attributable to lower tax rate jurisdictions, thereby decreasing the overall statutory tax rate. The effect of this rate decrease on our prior year net deferred tax liability was included in income tax expense for 2011. At December 31, 2011, we had approximately $125.3 million of federal tax net operating loss carryforwards, or “NOLs”, which expire through 2031. We also had a federal alternative minimum tax credit carryforward of $0.1 million, which has no expiration date. We believe it is more likely than not that we will use these tax attributes to
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offset and reduce current tax liabilities in future years. During 2011, we booked a valuation allowance of $4.2 million against a deferred tax asset of the same amount for state income tax credit carryforwards. The valuation allowance has no impact on our income tax expense, as the credits were not recorded as deferred tax assets in prior years. We believe it is more likely than not that this deferred tax asset will not be realized.
The following table sets forth selected operating data for the periods indicated:
Year Ended December 31, 2010 Compared with Year Ended December 31, 2009
(1) Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense in the Consolidated Statements of Operations for a total of $57.8 million and $54.4 million for the years ended December 31, 2010 and 2009, respectively. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better
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understanding of our required cash for general and administrative expense. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower stock-based compensation expense.
(2) Average prices shown in the table are net of the effects of all of our realized commodity hedging transactions. Our average realized price calculation includes all cash settlements for commodity derivatives, whether or not they qualify for hedge accounting. As a result of our realized hedging transactions, natural gas production revenues and oil production revenues increased (decreased) by the following amounts (in millions) for the periods indicated:
Before the effects of hedging, the average prices we received for natural gas and oil were as follows:
(3) Excludes non-cash stock-based compensation expense as described in footnote (1) above. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation expense, as presented in the Consolidated Statements of Operations, were $0.60 and $0.61 for the years ended December 31, 2010 and 2009, respectively.
(4) Natural gas average prices include the effect of NGL related revenue.
Production Revenues and Volumes. Production revenues increased to $708.5 million for the year ended December 31, 2010 from $647.8 million for the year ended December 31, 2009 due to an 8% increase in production and a 2% increase in natural gas and oil prices on a per Mcfe basis after the effects of realized cash flow hedges. The effects of realized hedges only include settlements from hedging instruments that were designated as cash flow hedges and exclude those that do not qualify, or were not designated, as cash flow hedges such as basis only and NGL swaps. The settlements from hedging instruments that were not designated as cash flow hedges are included in the line item “Commodity derivative loss” within operating revenues in the Consolidated Statements of Operations. See below for more information related to the Commodity derivative gain (loss) line item. The net increase in production added approximately $49.6 million of production revenues, and the increase in average price increased production revenues by approximately $11.1 million.
During the year ended December 31, 2010, we realized production revenues of approximately $68.5 million, or $0.71 per Mcfe, compared with $28.8 million, or $0.32 per Mcfe, for the year ended December 31, 2009 related to NGL values received for a portion of our gas production in the Piceance Basin. There is no assurance that in the future the amount received related to NGLs resulting from the processing of natural gas will exceed the additional cost of processing or the price of natural gas. In addition, as we reduce activities in the Piceance Basin in 2010, we expect production revenues related to NGL values to decline.
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Total production volumes for the year ended December 31, 2010 of 96.5 Bcfe increased from 89.7 Bcfe for the year ended December 31, 2009 due to increased gas production in the Piceance and Powder River Basins and increased oil production in the Uinta Basin. The increased production was partially offset by a decrease in gas production in the Uinta and Wind River Basins. Additional information concerning production is in the following table:
The production increase in the Piceance Basin was the result of our continued development activities, with initial sales on 161 new gross wells throughout 2010. The production increase in the Powder River Basin was the result of our continued development activities, with initial sales from 43 new gross wells throughout 2010. Although we reduced our 2010 development activities in the Powder River Basin as the result of lower natural gas prices, our production in that basin has benefited from prior years’ development programs due to the extended dewatering process of the coal bed methane wells. The production increase in oil from the Uinta Basin resulted from our ongoing development program at Blacktail Ridge and Lake Canyon with initial sales from 19 new gross wells throughout 2010. The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields with no significant drilling or recompletion activities to offset these declines. The decrease in gas production from the Uinta Basin is due to natural production declines as well as a limited development program compared to prior years in our West Tavaputs field, partially offset by higher volumes from our Blacktail Ridge/Lake Canyon development. Due to the issuance of the final EIS and ROD in the West Tavaputs field of the Uinta Basin authorizing full field development, we anticipate an overall increase in production in this basin in 2011. The increase of production in the Uinta Basin may be slightly offset by an anticipated reduction in production in the Piceance and Wind River Basins due to natural production declines and a reduced drilling schedule in those areas.
Hedging Activities. For the year ended December 31, 2010, approximately 74% of our natural gas volumes (excluding basis only swaps, which were equivalent to 12% of our natural gas volumes) and 53% of our oil volumes were subject to financial hedges, which resulted in an increase in natural gas revenues of $133.2 million and an increase in oil revenues of $2.2 million after settlements for all commodity derivatives, including basis only and NGL swaps. For the year ended December 31, 2009, approximately 79% of our natural gas volumes (excluding basis only swaps, which were equivalent to 4% of our natural gas volumes) and 52% of our oil volumes were subject to financial hedges, which resulted in an increase in natural gas revenues of $265.1 million and an increase in oil revenues of $6.7 million after settlements for all commodity derivatives, including basis only swaps. The decrease in revenues related to hedging natural gas resulted from the expiration of hedges entered into at higher prices and our inability to enter into new hedges at those prices because natural gas prices have fallen since we entered into those hedges. This trend is expected to continue based on future prices and hedge quotes.
Commodity Derivative Loss. The overall change in commodity derivative loss from a loss of $54.6 million for the year ended December 31, 2009 to a loss of $10.6 million for the year ended December 31, 2010 was primarily due to the unrealized gains resulting from the change in fair value of our basis only swaps as of December 31, 2010.
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The table below summarizes the realized and unrealized gains and losses we recognized in commodity derivative loss for the periods indicated:
Other Operating Revenues. Other operating revenues decreased to $0.6 million for the year ended December 31, 2010 from $4.9 million for the year ended December 31, 2009. Other operating revenues for the year ended December 31, 2010 primarily consisted of $2.0 million in net losses realized from the sale and exchange of properties offset by $2.6 million of income from gathering, compression and salt-water disposal fees received from third parties. Other operating revenues for the year ended December 31, 2009 primarily consisted of $1.4 million in gains realized from the sale of properties as well as $3.5 million in gathering, compression and salt-water disposal fees received from third parties for the use of our facilities.
Lease Operating Expense. Lease operating expense increased to $0.54 per Mcfe for the year ended December 31, 2010 from $0.52 per Mcfe for the year ended December 31, 2009. The increase was primarily due to remediation efforts related to a condensate leak at our Dry Canyon Compressor Station in the Uinta Basin. The condensate leak was detected in March 2010 and remediation of the area resulted in an additional $2.4 million (or $0.02 per Mcfe) in lease operating expense for the year ended December 31, 2010.
Gathering, Transportation and Processing Expense. Gathering, transportation and processing expense increased to $0.72 per Mcfe for the year ended December 31, 2010 from $0.63 per Mcfe for the year ended December 31, 2009. Higher fees associated with the Rockies Express Pipeline (“REX”) contributed to the increase in expense as the final two segments of the pipeline were completed, giving us access to gas sales delivery points farther east. In addition, we recognized expense associated with the start-up of new firm contracts to gather, transport and process our production from the Powder River and Uinta Basins ahead of anticipated production increases.
Included in gathering, transportation and processing expense are $0.19 and $0.17 per Mcfe of firm transportation and gathering expense and $0.04 and $0.05 per Mcfe of firm processing expense from long-term contracts for the years ended December 31, 2010 and 2009, respectively. The increase in firm transportation expense to $0.19 per Mcfe for the year ended December 31, 2010 from $0.17 per Mcfe for the year ended December 31, 2009 was the result of additional long-term contracts executed with various pipelines for our natural gas production in the Powder River and Uinta Basins and higher fees on REX as mentioned above.
Production Tax Expense. Total production taxes increased to $32.7 million for the year ended December 31, 2010 from $13.2 million for the year ended December 31, 2009. The increase in production taxes is primarily related to an increase in production and increase in oil and natural gas prices during the year ended December 31, 2010. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production tax expense for the year ended December 31, 2010 included a one-time reduction of $2.2 million related to amended 2004 through 2009 State of Utah annual severance tax calculations. In 2009, we reduced our production tax expense by $5.0 million based upon amended Colorado severance tax returns for the years 2004 through 2008. The amended Colorado severance tax returns completed in 2009 were nonrecurring adjustments based on a settlement agreement with the State of Colorado relating to the severance tax computation. Our 2009 production tax expense
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also included a decrease of $3.4 million primarily related to a surplus of ad valorem taxes withheld from 2008 based on the estimated mill levy rates compared to the actual rates. Production taxes as a percentage of oil and natural gas sales before hedging adjustments was 6.0% for the year ended December 31, 2010, which included a reduction of 0.4% related to the nonrecurring item associated with the Utah severance tax. For the year ended December 31, 2009, production taxes as a percentage of oil and natural gas sales before hedging adjustments was 3.6%, which included a reduction of 2.3% related to these nonrecurring items associated with the Colorado severance and ad valorem taxes.
Exploration Expense. Exploration expense increased to $9.1 million for the year ended December 31, 2010 from $3.2 million for the year ended December 31, 2009. Exploration expense for 2010 consisted of $3.5 million for seismic programs, $1.1 million for delay rentals, $0.1 million related to the evaluation of non-acquired assets and $4.4 million for one scientific well drilled for data gathering purposes. Exploration expense for 2009 consisted of $1.7 million for seismic programs, $1.1 million for delay rentals and $0.4 million related to the evaluation of non-acquired assets.
Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense decreased to $44.7 million for the year ended December 31, 2010 from $52.3 million for the year ended December 31, 2009. For the year ended December 31, 2010, impairment expense was $15.6 million, abandonment expense was $2.6 million and dry hole costs were $26.5 million. For the year ended December 31, 2009, impairment expense was $19.7 million, abandonment expense was $1.9 million and dry hole costs were $30.7 million.
We evaluate the impairment of our proved oil and gas properties on a property-by-property basis whenever events or changes in circumstances indicate a property’s carrying amount may not be recoverable. If the carrying amount exceeds the property’s estimated fair value, we will adjust the carrying amount of the property to fair value through a charge to impairment expense. For the year ended December 31, 2010, we did not record any impairment charges on proved oil and gas properties. For 2009, we recorded a non-cash impairment charge of $2.8 million to our proved oil and gas properties in the North Hill Creek field, located in the Uinta Basin based upon our fair value analysis. For 2009, we also recorded a non-cash impairment charge of $16.9 million to our proved oil and gas properties in the Yellow Jacket prospect, located in the Paradox Basin. This impairment expense was primarily the result of sub-economic performing wells in the Yellow Jacket prospect.
Unproved oil and gas properties are also assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop existing acreage. During the year ended December 31, 2010, we recorded a $15.6 million impairment charge regarding unproved oil and gas properties within various exploration projects. This non-cash impairment charge was primarily a result of unfavorable market conditions as well as uneconomic drilling results in exploratory areas where we had no future plans to develop or evaluate the remaining acreage based on 2011 capital allocation plans that were finalized during the fourth quarter of 2010. In addition, we incurred non-cash impairment charges on unproved oil and gas properties related to acreage in other areas that we no longer considered prospective. For the year ended December 31, 2009, we did not record an impairment on unproved oil and gas properties.
We account for oil and gas exploration and production activities using the successful efforts method of accounting under which we capitalize exploratory well costs until a determination is made as to whether or not the wells have found proved reserves. If proved reserves are not assigned to an exploratory well, the costs of drilling the well are charged to expense. Otherwise, the costs remain capitalized and are depleted as production occurs. Dry hole costs of $26.5 million for the year ended December 31, 2010 were associated with seven unsuccessful exploratory wells within the Paradox Basin and one unsuccessful exploratory well in each of the Uinta and Big Horn Basins. Dry hole costs of $30.7 million for the year ended December 31, 2009 were associated with six unsuccessful exploratory wells within the Montana Overthrust area, four unsuccessful exploratory wells within the Uinta Basin, two unsuccessful exploratory wells within the Paradox Basin and one unsuccessful exploratory well in each of the Big Horn and Laramie Basins.
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The following table shows the costs of the remaining exploratory wells for which drilling was completed and which are included in unproved oil and gas properties as of December 31, 2010 pending determination of whether the wells will be assigned proved reserves. The following table does not include $0.1 million related to exploratory wells in progress for which drilling had not been completed at December 31, 2010:
As of December 31, 2010, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling were $6.1 million, all of which were related to exploratory wells located in the Powder River Basin. In this basin, we drill wells into various coal seams. In order to produce gas from the coal seams, a period of dewatering lasting up to 36 months, or in some cases longer, is required prior to obtaining sufficient gas production to justify capital expenditures for compression and gathering and to classify the reserves as proved.
The exploratory well costs are suspended pending the completion of an economic evaluation including, but not limited to, results of additional appraisal drilling, facilities, infrastructure, well test analysis, additional geological and geophysical data and approval of a development plan. Management believes these projects with suspended exploratory drilling costs have the potential for sufficient quantities of hydrocarbons to justify their development and is actively pursuing efforts to assess whether reserves can be attributed to their respective areas. If additional information becomes available that raises substantial doubt regarding the economic or operational viability of any of these projects, the associated costs will be expensed.
Depreciation, Depletion and Amortization. DD&A was $260.7 million for the year ended December 31, 2010 compared with $253.6 million for the year ended December 31, 2009. The increase of $7.1 million was a result of increased production for 2010 compared with 2009, offset by a decrease in the DD&A rate. The increase in production accounted for $18.8 million of additional DD&A expense, which is partially offset by $11.7 million related to an overall decrease in the DD&A rate.
During 2010, the weighted average DD&A rate was $2.70 per Mcfe. During 2009, the weighted average DD&A rate was $2.83 per Mcfe. Under successful efforts accounting, DD&A expense is separately computed for each producing area based on geologic and reservoir delineation. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a weighted average DD&A rate for current production. Future DD&A rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.
General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased to $40.9 million for the year ended December 31, 2010 from $37.9 million for the year ended December 31, 2009. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 53 for a reconciliation and explanation. This increase was primarily due to an increase in employee compensation and benefit programs as well as an increase in costs associated with our efforts, and our support of industry-wide efforts, to educate the public concerning the benefits of natural gas. On a per Mcfe basis, general and administrative expense, excluding non-cash stock based compensation, was $0.42 for both years ended December 31, 2010 and 2009.
Non-cash stock-based compensation expense was $16.9 million in 2010 compared with $16.5 million in 2009. Non-cash stock-based compensation expense for 2010 and 2009 related primarily to the vesting of our stock option awards and nonvested shares of common stock granted to employees.
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The components of non-cash stock-based compensation expense for 2010 and 2009 are shown in the following table:
Interest Expense. Interest expense increased to $44.3 million for the year ended December 31, 2010 from $30.6 million for the year ended December 31, 2009 due to a higher effective interest rate in 2010 compared with 2009. Our effective interest rate increased to 12.1% for the year ended December 31, 2010 compared with 8.1% for the year ended December 31, 2009 primarily due to interest expense on our Senior Notes that were issued in July 2009 along with increased commitment fees due to lower outstanding debt balances on our Amended Credit Facility during 2010. Our weighted average outstanding debt balance for the year ended December 31, 2010 was $403.4 million compared with $429.8 million in 2009.
Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. We capitalized interest costs of $4.2 million and $4.6 million for the years ended December 31, 2010 and 2009, respectively.
Income Tax Expense. Income tax expense totaled $48.0 million for the year ended December 31, 2010 and $38.0 million for the year ended December 31, 2009, resulting in effective tax rates of 37.3% and 43.0% in 2010 and 2009, respectively. Our effective tax rate differs from the federal statutory rate primarily because we recorded stock-based compensation expense and other operating expenses that are not deductible for income tax purposes as well as the effect of state income taxes. The effective tax rate decrease from 2009 to 2010 was primarily the result of a net reduction in permanent differences affecting the tax rate calculation, principally the increase in tax deductible compensation related to incentive stock options. Additionally, a greater proportion of our operating revenue was attributable to lower tax rate jurisdictions, thereby decreasing the overall statutory tax rate. The effect of this rate decrease on our prior year net deferred tax liability was included in income tax expense for 2010. At December 31, 2010, we had approximately $94.8 million of federal tax net operating loss carryforwards, or “NOLs”, which expire through 2029. We also had a federal alternative minimum tax credit carryforward of $0.1 million, which has no expiration date. We believe it is more likely than not that we will use these tax attributes to offset and reduce current tax liabilities in future years.
Capital Resources and Liquidity
Our primary sources of liquidity since our formation in January 2002 have been net cash provided by operating activities, sales and other issuances of equity and debt securities, including our Convertible Notes and senior notes, bank credit facilities, proceeds from joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the exploration, development and acquisition of oil and natural gas properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources, including issuance of equity and debt securities, available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. The credit market dislocation that has existed over the past several years has improved; however, the costs to raise future debt and equity capital may be higher than previous issuances and such dislocations may recur. We are monitoring market conditions and are considering taking on additional debt, which may be in the form of bank debt, debt securities or other sources of financing. We cannot assure you that we will take on any such debt
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or what the terms would be. We have on file with the SEC an effective universal shelf registration statement that we may use for future securities offerings. We believe that we have significant liquidity available to us from cash flows from operations and under our Amended Credit Facility for our planned uses of capital. In addition, our hedge positions currently provide relative certainty on a majority of our cash flows from operations through 2012 even with the general decline in the price of natural gas. See, “-Trends and Uncertainties-Declining Commodity Prices” below. We actively review acquisition opportunities on an ongoing basis. If we were to make significant additional acquisitions for cash, we may need to obtain additional equity or debt financing, which may be at a higher cost than previous issuances.
At December 31, 2011, we had cash and cash equivalents of $57.3 million and a $70.0 million balance outstanding under our Amended Credit Facility. On October 18, 2011, we further amended our Amended Credit Facility, to extend the maturity date to October 31, 2016, increase commitments to $900.0 million from 17 lenders and increase the borrowing base to $1.1 billion based upon June 30, 2011 reserves and hedge positions. The amendment also decreased the interest margin to LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and reduced the commitment fee to between 0.375% to 0.5% based on borrowing base utilization. Our borrowing capacity was reduced by $26.0 million to $804.0 million due to an outstanding irrevocable letter of credit related to a firm transportation agreement. We currently expect that the holders of our Convertible Notes will put the notes to us in March 2012, and we have sufficient availability under our Amended Credit Facility with which to repay the Convertible Notes.
Cash Flow from Operating Activities
Net cash provided by operating activities was $479.3 million, $447.2 million and $480.7 million in 2011, 2010 and 2009, respectively. The changes in net cash provided by operating activities are discussed above in “-Results of Operations.”
Commodity Hedging Activities
Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for natural gas, NGLs and oil. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “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 Price Risk
Our primary market risk exposure is in the prices we receive for our 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, NGLs and oil has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for future 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. Based on our average daily production and our derivative contracts in place during 2011, our income before income taxes for the year ended December 31, 2011 would have decreased by approximately $5.5 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.7 million for each $1.00 per barrel decrease in crude oil prices. The Company is more susceptible to proved and unproved property impairments due to the current commodity price environment.
We routinely enter into commodity hedges relating to a portion of our projected production revenue through various financial transactions that hedge future prices received. These transactions may include financial price swaps whereby we will receive a fixed price and pay a variable market price to the contract counterparty and cashless price collars that set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we and the counterparty
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to the collars would be required to settle the difference. These commodity hedging activities are intended to support oil and natural gas prices at targeted levels that provide an acceptable rate of return and to manage our exposure to natural gas and oil price fluctuations. In addition to the swaps and collars discussed above, we also entered into basis only swaps. With a basis only swap, subject to the risk that our counterparty will be unable to perform its obligations under the swap, we have fixed the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location to mitigate the risk of large differences between NYMEX (Henry Hub) and our primary sales points, CIG and NWPL. We may consider entering into hedge transactions based on a NYMEX price in the future with a volume equal to the volume for our basis only swaps, thereby effectively fixing a price for CIG or NWPL.
As of January 27, 2012, we have financial derivative instruments related to natural gas, NGLs and oil volumes in place for the following periods indicated. Further detail of these hedges is summarized in the table presented under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Capital Resources and Liquidity-Commodity Hedging Activities.”
Interest Rate Risks
At December 31, 2011, there was $70.0 million outstanding balance under our Amended Credit Facility, which bears interest at floating rates. The average annual interest rate incurred on this debt was 2.5% and 2.2% for each of the years ended December 31, 2011 and 2010, respectively. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the year ended December 31, 2011 would have resulted in an estimated $0.8 million increase in interest expense for the year ended December 31, 2011. We also had $172.5 million principal amount of Convertible Notes and $250.0 million of Senior Notes due in 2016 and $400.0 million of Senior Notes due in 2019 outstanding at December 31, 2011, which have fixed cash interest rates of 5.0%, 9.875% and 7.625% per annum, respectively.
Item 8.
Item 8. Financial Statements and Supplementary Data
The information required by this item is included below in “Item 15. Exhibits, Financial Statement Schedules”.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. As of December 31, 2011, we carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective as of December 31, 2011.
Management’s Report on Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining internal control over financial reporting. Our internal control over financial
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reporting is a process designed under the supervision of the Chief Executive Officer and Chief Financial Officer 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.
Management assessed the effectiveness of our internal control over financial reporting. In making this assessment, it used the criteria set forth by the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment we have concluded that, as of December 31, 2011, our internal control over financial reporting is effective.
Our independent registered public accounting firm has issued an attestation report on our internal control over financial reporting. That report is set forth below.
Changes in Internal Controls. There has been no change in our internal control over financial reporting during the fourth fiscal quarter of 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Bill Barrett Corporation
Denver, Colorado
We have audited the internal control over financial reporting of Bill Barrett Corporation and subsidiaries (the “Company”) as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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 by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the 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, 2011, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2011 of the Company and our report dated February 23, 2012, expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Company’s adoption of a new accounting standard in 2009.
/s/ Deloitte & Touche LLP
Denver, Colorado
February 23, 2012
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Item 9B.
Item 9B. Other Information
None.
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PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Information regarding our directors and executive officers will be included in an amendment to this Form 10-K or in the “Directors and Executive Officers” section of the proxy statement for the 2012 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2011, and is incorporated by reference to this report.
Code of Business Conduct and Ethics
We have adopted a Code of Business Conduct and Ethics that applies to our Chief Executive Officer (our principal executive officer), Chief Financial Officer (our principal financial officer) and Senior Vice President - Accounting (our principal accounting officer) as well as other officers and employees. A copy of our Code of Business Conduct and Ethics is located on our website at www.billbarrettcorp.com under Corporate Governance in the Investor Relations sections.
Item 11.
Item 11. Executive Compensation
Information regarding executive compensation will be included in an amendment to this Form 10-K or in the “Executive Compensation” section of the proxy statement for the 2012 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2011, and is incorporated by reference to this report.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information regarding beneficial ownership will be included in an amendment to this Form 10-K or in the “Beneficial Owners of Securities” section of the proxy statement for the 2012 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2011, and is incorporated by reference to this report.
Equity Compensation Plan Information
The following table provides aggregate information presented as of December 31, 2011 with respect to all compensation plans under which equity securities are authorized for issuance.
(1) The weighted average exercise price relates to the 2,885,506 outstanding options included in column (a). Column (a) does not include 835,258 nonvested shares of common stock (restricted stock) granted under our shareholder-approved equity compensation plans.
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Item 13.
Item 13. Certain Relationships and Related Transactions and Director Independence
Information regarding certain relationships and related transactions will be included in an amendment to this Form 10-K or in the “Transactions Between the Company and Related Parties” and “Directors and Executive Officers” sections of the proxy statement for the 2011 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2011, and is incorporated by reference to this report.
Item 14.
Item 14. Principal Accountant Fees and Services
Information regarding principal accounting fees and services will be included in an amendment to this Form 10-K or in the “Fees to Independent Auditors” section of the proxy statement for the 2012 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2011, and is incorporated by reference to this report.
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PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules
See “Item 8. Financial Statements and Supplementary Data” beginning on page.
(a)(3) Exhibits.
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- 92 -
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* Indicates a management contract or compensatory plan or arrangement, as required by Item 15(a)(3).
** Filed herewith.
*** Users of this data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the XBRL-Related Documents is unaudited. Furthermore, users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these Sections.
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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.
BILL BARRETT CORPORATION
Date: February 23, 2012
By:
/s/ FREDRICK J. BARRETT
Fredrick J. Barrett
Chairman, Chief Executive Officer and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
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FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Bill Barrett Corporation
Denver, Colorado
We have audited the accompanying consolidated balance sheets of Bill Barrett Corporation and subsidiaries (the “Company”) as of December 31, 2011 and 2010, 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, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the 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, such consolidated financial statements present fairly, in all material respects, the financial position of Bill Barrett Corporation and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, the Company changed its method of oil and gas reserve estimation and related required disclosures in 2009 with the implementation of new accounting guidance.
We have also 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, 2011, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2012 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Denver, Colorado
February 23, 2012
BILL BARRETT CORPORATION
CONSOLIDATED BALANCE SHEETS
See notes to consolidated financial statements.
BILL BARRETT CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
See notes to consolidated financial statements.
BILL BARRETT CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
For the years ended December 31, 2009, 2010, and 2011
See notes to consolidated financial statements.
BILL BARRETT CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
See notes to consolidated financial statements.
BILL BARRETT CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2011, 2010 and 2009
1. Organization
Bill Barrett Corporation, a Delaware corporation, together with its wholly-owned subsidiaries (collectively, the “Company”) is an independent oil and gas company engaged in the exploration, development and production of natural gas and crude oil. Since its inception in January 2002, the Company has conducted its activities principally in the Rocky Mountain region of the United States.
2. Summary of Significant Accounting Policies
Basis of Presentation. The accompanying consolidated financial statements include the accounts of the Company. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates. In the course of preparing the Company’s financial statements in accordance with GAAP, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenues and expenses and in the disclosure of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.
Areas requiring the use of assumptions, judgments and estimates relate to the expected cash settlement of the Company’s 5% Convertible Senior Notes due 2028 (“Convertible Notes”) in computing diluted earnings per share, volumes of oil and natural gas reserves used in calculating depreciation, depletion and amortization (“DD&A”); the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining future asset retirement obligations, the timing of dry hole costs, impairments of undeveloped properties, valuing deferred tax assets, and estimating fair values of derivative instruments and stock-based payment awards.
Cash Equivalents. The Company considers all highly liquid investments with an original maturity of three months or less when purchased to be cash equivalents.
Oil and Gas Properties. The Company’s oil and gas exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Consolidated Statements of Cash Flows. If an exploratory well does find proved reserves, the costs remain capitalized. The costs of development wells are capitalized whether proved reserves are added or not. Oil and gas lease acquisition costs are also capitalized. Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. The weighted average interest rates used to capitalize interest for the years ended December 31, 2011, 2010 and 2009 were 10.2%, 12.1% and 8.1%, respectively, which include interest and amortization of discounts and deferred financing fees on the Company’s Convertible Notes, its 9.875% Senior Notes due 2016 (“9.875% Senior Notes), its 7.625% Senior Notes due 2019 (“7.625% Senior Notes”) and its credit facility. The Company capitalized interest costs of $1.4 million, $4.2 million and $4.6 million for the years ended December 31, 2011, 2010 and 2009, respectively.
Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.
Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage and other relevant matters.
Materials and supplies consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market value, on a first-in, first-out basis.
The following table sets forth the net capitalized costs and associated accumulated DD&A and non-cash impairments relating to the Company’s oil and natural gas producing activities:
Net changes in capitalized exploratory well costs for the years ended December 31, 2011, 2010 and 2009, respectively, are reflected in the following table:
All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. As of December 31, 2011, there were no exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling.
The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. The Company considers oil and gas properties impaired when the estimated undiscounted cash flows are less than the asset’s carrying value or if other qualitative factors indicate that the carrying value is less than the estimated fair value of the oil and gas property; for example in a low commodity price environment. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.
During the years ended December 31, 2011, 2010 and 2009, the Company recognized non-cash impairment charges of $100.3 million, $15.6 million and $19.7 million, respectively, which were included within impairment, dry hole costs and abandonment expense in the Consolidated Statements of Operations.
As a result of declining natural gas prices, the Company recorded a non-cash impairment charge of $82.8 million regarding proved oil and gas properties within the Powder River and Wind River Basins for the year ended December 31, 2011. For the year ended December 31, 2010 the Company did not record any impairment charges on proved oil and gas properties. For the year ended December 31, 2009 the Company recorded an impairment charge of $2.8 million based upon the fair value analysis of proved oil and gas properties in the North Hill Creek field located in the Uinta Basin. These properties were subsequently sold in 2010 for an immaterial loss. Further, in 2009, the Company recorded a non-cash impairment charge of $16.9 million on its proved oil and gas properties in the Yellow Jacket prospect located in the Paradox Basin. The impairment expense was primarily the result of sub-economic performing wells in the Yellow Jacket prospect.
For the year ended December 31, 2011 the Company recorded a non-cash impairment charge of $17.5 million related to certain unproved oil and gas properties within various exploration projects. This non-cash impairment charge was primarily a result of unfavorable market conditions as well as uneconomic drilling results in exploratory areas where the Company has no future plans to develop or evaluate the remaining acreage based on current 2012 capital allocation plans. The non-cash impairment charge of $15.6 million for the year ended December 31, 2010 related to certain unproved oil and gas properties within various exploration projects. This non-cash impairment charge was primarily a result of unfavorable market conditions as well as uneconomic drilling results in exploratory areas where the Company had no future plans to develop or evaluate the remaining acreage based on 2011 capital allocation plans. In addition, the Company incurred non-cash impairment charges on unproved oil and gas properties related to acreage in other areas that the Company no longer considered prospective. For the year ended December 31, 2009 the Company did not record any impairment charges on unproved oil and gas properties.
The provision for DD&A of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Oil is converted to natural gas equivalents, Mcfe, at the rate of one barrel to six Mcfe. Estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values, are taken into consideration by this calculation.
On December 31, 2008, the SEC adopted the final rules and interpretations updating its oil and gas reserves reporting requirements. Many of the revisions were updates to definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management System, which is a widely accepted set of evaluation guidelines that were designed to support assessment processes throughout the resource asset lifecycle. These guidelines were prepared by the Society of Petroleum Engineers (“SPE”) Oil and Gas Reserves Committee with cooperation from many industry organizations. One of the key changes to the previous SEC rules related to using a 12-month average commodity price to calculate the value of proved reserves versus the previous method of using year-end prices. Other key revisions included the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, the opportunity to establish proved undeveloped reserves without the requirement of an adjacent producing well and permitting disclosure of probable and possible reserves. The SEC required companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 31, 2009. The new SEC rules were effective beginning with the Company’s 2009 filing, and all new rules and disclosure requirements were incorporated.
In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-03, Extractive Activities- Oil and Gas (Topic 932), Oil and Gas Reserve Estimation and Disclosures, which aligned the FASB oil and gas reserve estimation and disclosure requirements with the requirements in the SEC’s final rule as discussed above. The adoption of the FASB Accounting Standards Codification (“ASC”) Topic 932 changed the methodology under which the Company calculated proved oil and gas reserves. The Company’s fourth quarter 2009 DD&A and impairment calculations were based upon proved reserves that were determined using the new reserve guidelines, whereas DD&A and impairment calculations in previous quarters within 2009 were based on the prior SEC methodology. The Company’s 2011 and 2010 DD&A and impairment calculations were based on the current SEC and FASB guidance.
Furniture, Equipment and Other. Land and other office and field equipment are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Leasehold improvements are amortized over the lesser of the estimated life of the improvements or the life of the lease. Maintenance and repairs are expensed when incurred. Depreciation of other property and equipment is computed using the straight-line method over their estimated useful lives of three to 20 years. Upon retirement or disposition of assets, the costs and related accumulated depreciation are removed from the accounts with the resulting gains or losses, if any, reflected in results of operations.
Accounts Payable and Accrued Liabilities. Accounts payable and accrued liabilities are comprised of the following:
Environmental Liabilities. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated.
Revenue Recognition. The Company records revenues from the sales of natural gas, natural gas liquids (“NGLs”) and crude oil when delivery to the purchaser has occurred and title has transferred. The Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company records revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners’ gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over- and under-produced gas balancing positions are considered in the Company’s proved oil and gas reserves. Gas imbalances at December 31, 2011 and 2010 were not material.
Comprehensive Income (Loss). Comprehensive income (loss) consists of net income and the effective component of derivative instruments classified as cash flow hedges. Comprehensive income (loss) is presented net of income taxes in the Consolidated Statements of Stockholders’ Equity and Comprehensive Income.
Derivative Instruments and Hedging Activities. The Company periodically uses derivative financial instruments to achieve a more predictable cash flow from its natural gas, NGLs and oil sales by reducing its exposure to price fluctuations. Derivative instruments are recorded at fair market value and included in the Consolidated Balance Sheets as assets or liabilities.
The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. The Company is required to formally document, at the inception of a hedge, the hedging relationship and the risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment.
For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in accumulated other comprehensive income (“AOCI”) until the hedged item is recognized in earnings. Hedge effectiveness is assessed quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in earnings.
The Company utilizes financial derivative instruments that have not been designated as cash flow hedges, but they still protect the Company from changes in commodity prices. These instruments are marked to market with the resulting changes in fair value recorded in earnings. For additional discussion of derivatives, please see Note 8.
Deferred Financing Costs. Costs incurred in connection with the execution or modification of the Company’s credit facility, and in connection with the Convertible Notes, 9.875% Senior Notes and 7.625% Senior Notes, are capitalized and amortized over the life, or expected life, of the debt using the straight-line method, which approximates the effective interest method.
Income Taxes. Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates.
The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more-likely-than-not recognition threshold will be recognized.
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 credit-adjusted, risk-free 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 on a field-by-field basis. The associated liability is classified in current and long-term liabilities in the 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 DD&A expense in the Consolidated Statements of Operations.
Repurchases and Retirements of Capital Stock. The Company records treasury stock acquisitions at cost. Upon retirement of treasury shares, the excess of purchase or contribution cost over associated common stock par value is allocated to additional paid-in capital (“APIC”). The allocation to APIC is based on the per-share amount of capital in excess of par value for all shares.
Stock-Based Compensation. The Company recognizes compensation expense for all stock-based payment awards made to employees and directors. Stock-based compensation expense is measured at the grant date based on the fair value of the award and is recognized as expense on a straight-line basis over the requisite service period, which is generally the vesting period. The Company generally uses the Black-Scholes option-pricing model to determine the fair value of the stock-based awards, which requires the input of highly subjective assumptions, including the expected volatility of the underlying stock, the expected term of the award, the risk-free interest rate and expected future divided payments. Expected volatilities are based on the Company’s historical volatility, if available, or based on an average of volatilities of similar-sized oil and gas companies in the Rocky Mountain region. The expected life of an award is estimated using historical exercise behavior data and estimated future behavior. The risk-free interest rate is based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the expected life of the award. The Company does not expect to declare or pay dividends in the foreseeable future. The Company also uses the Monte Carlo simulation method to determine the fair value of market-based performance awards, which is based on random projections of stock price paths and must be repeated numerous times to achieve a probable assessment.
Earnings Per Share. Basic net income per common share is calculated by dividing net income attributable to common stock by the weighted average number of common shares outstanding during each period. Non-vested equity shares of common stock are included in the computation of basic net income per common share only after the shares become fully vested. Diluted net income per common share is calculated by dividing net income attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted net income per common share calculations consist of nonvested equity shares of common stock, in-the-money outstanding stock options to purchase the Company’s common stock and shares into which the Convertible Notes are convertible.
In satisfaction of its obligation upon conversion of the Convertible Notes, the Company may elect to deliver, at its option, cash, shares of its common stock or a combination of cash and shares of its common stock. The Company currently expects to settle the Convertible Notes in cash at or near the initial redemption date of March 26, 2012; therefore, the treasury stock method was used to measure the potentially dilutive impact of shares associated with that conversion feature. The Convertible Notes issued March 12, 2008 have not been dilutive since their issuance, and therefore, did not impact the diluted net income per common share calculation for the years ended December 31, 2011, 2010 and 2009. The diluted net income per common share excludes the anti-dilutive effect of 115,215, 217,073 and 211,131 shares of stock options and nonvested performance-based shares of common stock for the years ended December 31, 2011, 2010 and 2009, respectively.
The following table sets forth the calculation of basic and diluted earnings per share:
Industry Segment and Geographic Information. The Company operates in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of the Company’s operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment.
New Accounting Pronouncements. In January 2010, the FASB issued Accounting Standards Update 2010-06, Improving Disclosures about Fair Value Measurements, which amended FASB ASC 820, Fair Value Measurements and Disclosures. The intent of this update is to improve disclosure requirements related to fair value measurements and disclosures. New disclosures were required regarding transfers in and out of Levels 1 and 2 and activity within Level 3 fair value measurements, as well as clarification of existing disclosures regarding the level of disaggregation of derivative contracts and disclosures about fair value measurement inputs and valuation techniques. The guidance was effective for interim and annual periods beginning after December 15, 2009, except for the Level 3 reconciliation disclosures, which were effective for interim and annual periods beginning after December 15, 2010. The Company adopted the provisions on January 1, 2010, except for the Level 3 reconciliation disclosures, which were adopted on January 1, 2011. Adoption of the disclosure requirements did not have a material impact on the Company’s financial position or results of operations.
In December 2010, the FASB issued Accounting Standards Update 2010-29, Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations, which amended FASB ASC Topic 805, Business Combinations. The objective of this update is to clarify and expand the pro forma revenue and earnings disclosure requirements for business combinations. The guidance was effective for fiscal years beginning after December 15, 2010, and the Company adopted the provision on January 1, 2011. Adoption of the disclosure requirements did not have a material impact on the Company’s financial position or results of operations.
In May 2011, the FASB issued Accounting Standards Update 2011-04, Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS, which amended FASB ASC Topic 820, Fair Value Measurement. The objective of this update is to create common fair value measurement and disclosure requirements between GAAP and International Financial Reporting Standards (“IFRS”). The amendments clarify existing fair value measurement and disclosure requirements and make changes to particular principles or requirements for measuring or disclosing information about fair value measurements. These amendments are not expected to have a significant impact on companies applying GAAP. This provision is effective for interim and annual periods beginning after December 15, 2011. Adoption of this update is not expected to have a material impact on the Company’s disclosures and financial statements.
In June 2011, the FASB issued Accounting Standards Update 2011-05, Presentation of Comprehensive Income, which amended FASB ASC Topic 220, Comprehensive Income. The intent of this update is to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. To facilitate convergence of GAAP and IFRS, the FASB eliminated the option to present components of other comprehensive income as part of the statement of stockholders’ equity and requires an entity to present total comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. The guidance is effective for interim and annual periods beginning after December 15, 2011. Adoption of this update is not expected to have a material impact on the Company’s disclosures and financial statements.
In December 2011, the FASB issued Accounting Standards Update 2011-12, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. The intent of this update is to indefinitely defer certain provisions of Accounting Standards Update 2011-05 Presentation of Comprehensive Income, which require entities to present reclassification adjustments by component in both the statement where net income is presented and the statement where other comprehensive income is presented for both interim and annual financial statements. Adoption of this update is not expected to have a material impact on the Company’s disclosures and financial statements.
3. Supplemental Disclosures of Cash Flow Information
Supplemental cash flow information is as follows:
4. Acquisitions
On June 8, 2011, the Company completed an acquisition, from an unrelated party, of oil properties and related assets in the East Bluebell area of the Uinta Basin (“East Bluebell Acquisition”) located in Duchesne and Uintah Counties in Utah. The properties were purchased for approximately $116.8 million. As of December 31, 2011, the final purchase price allocation is as follows (in thousands):
On August 16, 2011, the Company completed an acquisition, from an unrelated party, of oil and gas properties and related assets in the Denver-Julesburg Basin (“DJ Basin Acquisition”) located in northeastern Colorado and southeastern Wyoming. Total consideration given was approximately $145.6 million in cash. The final purchase price allocation is as follows (in thousands):
The East Bluebell Acquisition and the DJ Basin Acquisition qualified as business combinations and, as such, the Company estimated the fair value of each property as of the respective acquisition dates, June 8, 2011 and August 16, 2011. To estimate the fair values of the properties as of the acquisition date, the Company used a net asset value approach. The Company utilized a discounted cash flow model that took into account the following inputs to arrive at estimates of future net cash flows:
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Estimated ultimate recovery of crude oil and natural gas as prepared by the Company’s internal petroleum engineers;
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Estimated future commodity prices based on NYMEX crude oil and gas futures prices as of each acquisition date and adjusted for estimated location and quality differentials as well as related transportation costs;
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Estimated future production rates; and
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Estimated timing and amounts of future operating and development costs.
To estimate the fair value of proved properties, the Company discounted the future net cash flows using a market-based rate that the Company determined appropriate at the acquisition date for the various proved reserve categories. To compensate for the inherent risk of estimating and valuing unproved properties, the Company reduced the discounted future net cash flows of the unproved properties by additional risk-weighting factors. Due to the unobservable nature of the inputs, the fair values of the proved and unproved oil and gas properties are considered Level 3 fair value measurements.
The Company has not presented pro forma information for the acquired businesses as the impact of the acquisitions were not material to the results of operations for the twelve months ended December 31, 2011 or 2010. The results of operations from the East Bluebell Acquisition and the DJ Basin Acquisition are included in the Company’s consolidated financial statements from the acquisition dates of June 8, 2011 and August 16, 2011, respectively. Revenue related to the East Bluebell Acquisition that was included in the Company’s Consolidated Statements of Operations was approximately $7.7 million for the twelve months ended December 31, 2011 and net income was $1.7 million. Revenue related to the DJ Basin Acquisition that was included in the Company’s Consolidated Statements of Operations was approximately $6.1 million for the twelve months ended December 31, 2011 and net income was $1.0 million.
5. Long-Term Debt
The Company’s outstanding debt is summarized below (in thousands):
(1) The recorded value of the credit facility approximates its fair value due to its floating rate structure.
(2) The aggregate estimated fair value of the 9.875% Senior Notes was approximately $273.8 million as of December 31, 2011 based on reported market trades of these instruments.
(3) The aggregate estimated fair value of the Convertible Notes was approximately $173.4 million as of December 31, 2011. Because there is no active, public market for the Convertible Notes, the fair value was based on market-based parameters of the various components of the Convertible Notes and over-the-counter trades.
(4) The Company currently expects that the holders will put the Convertible Notes to the Company in March 2012, which would require the Company to settle the notes in cash. The Company has sufficient availability under the Amended Credit Facility with which to repay the Convertible Notes. The Company also has the option to call the Convertible Notes at any time thereafter.
(5) The aggregate estimated fair value of the 7.625% Senior Notes was approximately $418.0 million as of December 31, 2011 based on reported market trades of these instruments.
Amended Credit Facility
On March 16, 2010, the Company amended its revolving credit facility (the “Amended Credit Facility”) and extended the maturity date to April 1, 2014. The Amended Credit Facility bears interest, based on the borrowing
base usage, at the (i) London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 2.0% to 3.0% or (ii) an alternate base rate (“ABR”), based upon the greater of the prime rate, the federal funds effective rate plus 0.5%, or the adjusted one month LIBOR plus 1.0%, plus applicable margins ranging from 1.0% to 2.0%.
On October 18, 2011, the Company further amended the Amended Credit Facility to extend the maturity date to October 31, 2016, increase commitments to $900.0 million and increase the borrowing base to $1.1 billion based upon June 30, 2011 reserves and hedge positions. The amendment also decreased the interest margin to LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and reduced the commitment fee to between 0.375% to 0.5% based on borrowing base utilization. The average annual interest rates incurred on the Amended Credit Facility were 2.5% and 2.2% for each of the years ended December 31, 2011 and 2010, respectively.
The borrowing base is required to be re-determined twice per year. On June 30, 2011, the borrowing base was reaffirmed for the October 18, 2011 amendment which increased the borrowing base to $1.1 billion with commitments of $ 900.0 million based on June 30, 2011 reserves and hedge positions. Future borrowing bases will be computed based on proved oil and natural gas reserves, hedge positions and estimated future cash flows from those reserves, as well as any other outstanding debt of the Company. The Company pays annual commitment fees between 0.375% and 0.5% of the unused amount of the commitments. The Amended Credit Facility is secured by oil and natural gas properties representing at least 80% of the value of the Company’s proved reserves and the pledge of all of the stock of the Company’s subsidiaries. The Amended Credit Facility also contains certain financial covenants. The Company is currently in compliance with all financial covenants and has complied with all financial covenants for all prior periods. As of December 31, 2011, the Company had $70.0 million outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit was issued under the Amended Credit Facility, effective May 4, 2010, which reduced the borrowing capacity of the Amended Credit Facility by $26.0 million to $804.0 million.
5% Convertible Senior Notes Due 2028
On March 12, 2008, the Company issued $172.5 million aggregate principal amount of Convertible Notes. As of January 1, 2009 with the adoption of new authoritative accounting guidance under FASB ASC subtopic 470-20, Debt with Conversion Options, the Company recorded a debt discount of $23.1 million, which represented the fair value of the equity conversion feature as of the date of the issuance of the Convertible Notes. The value of the equity conversion feature was also recorded as APIC, net of $8.6 million of deferred taxes. The full $172.5 million principal amount of the Convertible Notes is currently outstanding. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by the Company. The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of the Company’s existing and future senior unsecured indebtedness; are senior in right of payment to all of the Company’s future subordinated indebtedness; and are effectively subordinated to all of the Company’s secured indebtedness with respect to the collateral securing such indebtedness. The Convertible Notes are structurally subordinated to all present and future secured and unsecured debt and other obligations of the Company’s subsidiaries. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility, the 9.875% Senior Notes and the 7.625% Senior Notes.
The conversion price is approximately $66.33 per share of the Company’s common stock, equal to the applicable conversion rate of 15.0761 shares of common stock, subject to adjustment, for each $1,000 of the principal amount of the Convertible Notes. Upon conversion of the Convertible Notes, holders will receive, at the Company’s election, cash, shares of common stock or a combination of cash and shares of common stock. If the conversion value exceeds $1,000, the Company will also deliver, at its election, cash, shares of common stock or a combination of cash and shares of common stock with respect to the remaining value deliverable upon conversion. Currently, it is the Company’s intention to net cash settle the Convertible Notes. However, the Company has not made a formal legal irrevocable election to net cash settle and reserves the right to settle the Convertible Notes in any manner allowed under the indenture for the Convertible Notes as business conditions warrant.
The Convertible Notes bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year. On or after March 26, 2012, the Company may redeem for cash all or a portion of the Convertible Notes at a redemption price equal to 100% of the principal amount of the Convertible Notes to be redeemed, plus accrued and unpaid interest, if any, up to, but excluding, the applicable redemption date. Holders of the Convertible Notes may require the Company to purchase all or a portion of their Convertible Notes for cash on each of March 20, 2012, March 20, 2015, March 20, 2018 and March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date. The Company currently expects to call the Convertible Notes to be redeemed in 2012 or that the holders will put the convertible Notes to the Company in 2012. The Company has sufficient availability under the Amended Credit Facility with which to repay the Convertible Notes.
9.875% Senior Notes Due 2016
On July 8, 2009, the Company issued $250.0 million in aggregate principal amount of 9.875% Senior Notes due 2016 at 95.172% of par resulting in a discount of $12.1 million. The 9.875% Senior Notes mature on July 15, 2016. Interest is payable in arrears semi-annually on January 15 and July 15, which began January 15, 2010. The Company received net proceeds of $232.3 million (net of related offering costs), which were used to repay a portion of the borrowings under the Amended Credit Facility. The 9.875% Senior Notes are senior unsecured obligations of the Company and rank equal in right of payment with all of the Company’s other existing and future senior unsecured indebtedness, including the Company’s Convertible Notes and 7.625% Senior Notes. The 9.875% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.625% Senior Notes. The 9.875% Senior Notes include certain covenants that limit the Company’s ability to incur additional indebtedness, pay dividends, make restricted payments, create liens and sell assets. The Company was in compliance with all financial covenants for all periods.
7.625% Senior Notes Due 2019
On September 27, 2011, the Company issued $400.0 million in principal amount of 7.625% Senior Notes due 2019 at par. The 7.625% Senior Notes will mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1 beginning April 1, 2012. The Company received net proceeds of $393.0 million (net of related offering costs), which were used to repay the outstanding borrowings under the Amended Credit Facility. The 7.625% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of the Company’s other existing and future senior unsecured indebtedness. The 7.625% Senior Notes are fully and unconditionally guaranteed by the Company’s subsidiaries. The 7.625% Senior Notes include certain covenants that limit the Company’s ability to incur additional indebtedness, pay dividends, make restricted payments, create liens and sell assets. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance.
The following table summarizes the cash portion of interest expense related to the Amended Credit Facility, 9.875% and 7.625% Senior Notes and Convertible Notes along with the non-cash portion resulting from the amortization of the debt discount and transaction costs through interest expense:
(1) Cash interest includes amounts related to interest and commitment fees paid on the Amended Credit Facility and participation and fronting fees paid on the letter of credit.
(2) The stated interest rate for the 9.875% Senior Notes is 9.875% per annum with an effective interest rate of 11.3% per annum.
(3) The stated interest rate for the Convertible Notes is 5% per annum with an effective interest rate of 9.7% per annum. The effective interest rate of the Convertible Notes includes amortization of the debt discount, which represented the fair value of the equity conversion feature at the time of issue.
(4) The stated interest rate for the 7.625% Senior Notes is 7.625% per annum with an effective interest rate of 7.9% per annum. The cash interest will be paid with the first interest payment due on April 1, 2012.
6. 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 credit-adjusted discount 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 on a field-by-field basis. The associated liability is classified in current and long-term liabilities in the 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 DD&A expense in the Consolidated Statements of Operations.
A reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2011, 2010 and 2009, which includes $1.6 million associated with assets that were held for sale as of December 31, 2009, is as follows:
7. Fair Value Measurements
Assets and Liabilities Measured on a Recurring Basis
The Company’s financial instruments, including cash and cash equivalents, accounts and notes receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Amended Credit Facility, as discussed in Note 5, approximates its fair value due to its floating rate structure. The Company’s other financial and non-financial assets and liabilities that are measured on a recurring basis are measured and reported at fair value.
Fair value is defined as 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 (exit price). The Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) for valuation as a practical expedient for assigning fair value. The Company uses market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market and income approaches for recurring fair value measurements and utilizes the best available information. Given the Company’s historical market transactions, its markets and instruments are fairly liquid. Therefore, the Company has been able to classify fair value balances based on the observability of those inputs. A fair value hierarchy was established that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
Level 1-Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed securities and U.S. government treasury securities.
Level 2-Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by
observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.
Level 3-Pricing inputs include significant inputs that are generally less observable than objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.
The following tables set forth by level within the fair value hierarchy the Company’s financial assets and financial liabilities as of December 31, 2011 and 2010 that were measured at fair value on a recurring basis. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of assets and liabilities and their placement within the fair value hierarchy levels.
All fair values reflected in the table above and on the Consolidated Balance Sheets have been adjusted for non-performance risk. For applicable financial assets carried at fair value, the credit standing of the counterparties is analyzed and factored into the fair value measurement of those assets. In addition, the fair value measurement of a liability has been adjusted to reflect the nonperformance risk of the Company. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.
Level 1 Fair Value Measurements-The Company maintains a non-qualified deferred compensation plan (as discussed in more detail in Note 11) which allows certain management employees to defer receipt of a portion of their compensation. The Company maintains assets for the deferred compensation plan in a rabbi trust. The assets of the rabbi trust are invested in publicly traded mutual funds and are recorded in other current and other long-term assets on the Consolidated Balance Sheets. The company also has highly liquid short term investments in money market funds. The deferred compensation plan financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs. The money market fund investments are recorded at carrying value, which approximates fair value, which represent Level 1 inputs.
Level 2 Fair Value Measurements-The fair value of the natural gas and crude oil forwards and options are estimated using a combined income and market valuation methodology with a mid-market pricing convention based upon forward commodity price and volatility curves. The curves are obtained from
independent pricing services reflecting broker market quotes. The Company did not make any adjustments to the obtained curves. The pricing services publish observable market information from multiple brokers and exchanges. No proprietary models are used by the pricing services for the inputs. The Company utilized the counterparties’ valuations to assess the reasonableness of the Company’s valuations.
Level 3 Fair Value Measurements-As of December 31, 2011 and 2010, and for the years ended December 31, 2011 and 2010, the Company did not have assets or liabilities that were measured on a recurring basis classified under a Level 3 fair value hierarchy.
Assets and Liabilities Measured on a Non-recurring Basis
The Company utilizes fair value on a non-recurring basis to perform impairment tests as required on its property and equipment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property and equipment. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3. The Company also applied fair value accounting guidance to measure the assets and liabilities acquired in the East Bluebell Acquisition and the DJ Basin Acquisition. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. The final fair values of these items were primarily determined using the present value of estimated future cash inflows and outflows. Because of the unobservable nature of these inputs, they are classified within Level 3. See Note 4 for additional discussion of the East Bluebell Acquisition and the DJ Basin Acquisition and disclosure of the inputs used to determine the final fair value of the assets and liabilities acquired. Additionally, the Company uses fair value to determine the inception value of its asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition and would generally be classified within Level 3.
8. Derivative Instruments
The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable cash flow from its production revenues by reducing its exposure to commodity price fluctuations. The Company has entered into financial commodity swap and collar contracts to fix the floor and ceiling prices related to the sale of a portion of the Company’s production. The Company does not enter into derivative instruments for speculative or trading purposes.
In addition to financial contracts, the Company may at times be party to various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sale exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas production revenues at the time of settlement.
All derivative instruments, other than those that meet the normal purchase and normal sale exception, as mentioned above, are recorded at fair value and included in the Consolidated Balance Sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative instruments in the Consolidated Balance Sheets as of the periods indicated:
(1) Amounts are netted against derivative liability balances with the same counterparty, and, therefore, are presented as a net liability on the Consolidated Balance Sheet.
(2) As of December 31, 2011, this line item on the Consolidated Balance Sheet also includes $25.9 million of deferred financing costs and other noncurrent assets.
(3) As of December 31, 2011 and 2010, this line item on the Consolidated Balance Sheets also includes $2.9 million and $1.3 million of other noncurrent liabilities, respectively.
(4) Amounts are netted against derivative asset balances with the same counterparty, and, therefore, are presented as a net asset on the Consolidated Balance Sheet.
For derivative instruments that qualify and are designated as cash flow hedges, changes in fair value, to the extent the hedges are effective, are recognized in AOCI until the forecasted transaction occurs. The Company will reclassify the appropriate cash flow hedge amounts from AOCI to oil and gas production revenues in the Consolidated Statements of Operations as the hedged production quantity is sold. Based on projected market prices as of December 31, 2011, the amount to be reclassified from AOCI to net income in the next 12 months would be an after-tax net gain of approximately $50.8 million. Any actual increase or decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur. The Company anticipates that all originally forecasted transactions related to the Company’s derivatives that continue to be accounted for as cash flow hedges will occur by the end of the originally specified time periods.
The commodity hedge instruments designated as cash flow hedges are at highly liquid trading locations but may contain slight differences compared to the delivery location of the forecasted sale, which may result in ineffectiveness. Although those derivatives may not achieve 100% effectiveness for accounting purposes, the
Company believes that its derivative instruments continue to be highly effective in achieving its risk management objectives. The ineffective portion of commodity hedge derivatives is reported in commodity derivative loss in the Consolidated Statements of Operations. The following table summarizes the cash flow hedge gains and losses, net of tax, and their locations on the Consolidated Balance Sheets and Consolidated Statements of Operations as of the periods indicated:
(1) Gains and losses reclassified from AOCI into income are located in the Interest Expense line item in the Consolidated Statement of Operations.
(2) Gains and losses reclassified from AOCI into income as well as gains and losses on ineffective hedges are located in the Oil and Gas Production Revenues and the Commodity Derivative Loss line item, respectively, in the Consolidated Statement of Operations.
During the derivative’s term, if the Company determines that the hedge is no longer effective or necessary, hedge accounting is prospectively discontinued. All subsequent changes in the derivative’s fair value are recorded in earnings, and all accumulated gains and losses, based on the effective portion of the derivative at that date, recorded in AOCI will remain in AOCI and are reclassified to earnings when the underlying transaction occurs. If the forecasted transaction to which the hedging instrument had been designated is no longer probable of occurring within the specified time period, the hedging instrument loses cash flow hedge accounting treatment, and all subsequent mark-to-market gains and losses are recorded in earnings and all accumulated gains or losses recorded in AOCI related to the hedging instrument are also reclassified to earnings.
Some of the Company’s commodity derivative instruments do not qualify or are not designated as cash flow hedges but are, to a degree, an economic offset to the Company’s commodity price exposure. If a commodity derivative instrument does not qualify or is not designated as a cash flow hedge, the change in the fair value of the derivative is recognized in commodity derivative loss in the Consolidated Statements of Operations. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. The Company’s cash flow is only impacted when the underlying physical sales transaction takes place in the future and when the associated derivative instrument is settled by making or receiving a payment to or from the counterparty. Realized gains and losses of commodity derivative instruments that do not qualify as cash flow hedges are recognized in commodity derivative loss in the Consolidated Statements of Operations and are reflected in cash flows from operations on the Consolidated Statements of Cash Flows.
Effective January 1, 2012 the Company elected to discontinue hedge accounting prospectively. Consequently, as of January 1, 2012 the Company will no longer designate any hedges as cash flow hedges and the Company will de-designate all commodity hedge instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting on January 1, 2012, the mark-to-market value of all commodity hedge instruments within AOCI at December 31, 2011 will be frozen in AOCI as of the de-designation date and will be reclassified into earnings in future periods as the original hedged transactions affect earnings.
In addition to the swaps and collars discussed above, the Company has entered into basis only swaps. Basis only swaps hedge the difference between the New York Mercantile Exchange (“NYMEX”) gas price and the price received for the Company’s natural gas production at a specific delivery location. Although the Company believes that this is an appropriate part of a risk mitigation strategy, the basis only swaps do not qualify for hedge accounting because the total future cash flow has not been fixed. As a result, the changes in fair value of these derivative instruments are recorded in earnings and recognized in commodity derivative loss in the Consolidated Statements of Operations. The Company has also entered into swap contracts to hedge the amount received related to NGLs resulting from the processing of its natural gas. The NGL hedges were not designated as cash flow hedges and the changes in fair value of these derivative instruments were recorded in earnings.
The following table summarizes the location and amounts of gains and losses on derivative instruments that do not qualify for hedge accounting for the periods indicated:
As of December 31, 2011, the Company had financial instruments in place to hedge the following volumes for the periods indicated:
As a result of the various swap and collar contracts that settled during the years ended December 31, 2011, 2010 and 2009, the Company recognized a net increase in natural gas production revenues of $73.9 million, $133.2 million and $265.1 million for the years ended December 31, 2011, 2010 and 2009, respectively. The Company also recognized a decrease in oil production revenues related to these contracts of $2.0 million for the year ended December 31, 2011 and increases of $2.2 million and $6.7 million during the years ended December 31, 2010 and 2009, respectively.
The table below summarizes the realized and unrealized gains and losses the Company recognized related to its oil and natural gas derivative instruments for the periods indicated:
(1) Included in Oil and gas production revenues in the Consolidated Statements of Operations.
(2) Included in Commodity derivative loss in the Consolidated Statements of Operations.
Derivative financial instruments that hedge the price of oil and gas are generally executed with major financial or commodities trading institutions that expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company has hedges in place with 12 different counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non-performance by the counterparties, are substantially smaller. The creditworthiness of counterparties is subject to continual review by management, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties.
It is the Company’s policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility or potential lenders in the Amended Credit Facility. Two counterparties that were lenders in the Amended Credit Facility withdrew from the facility when the Company amended the facility in October 2011. The Company will continue to monitor the credit worthiness of these two counterparties during the remaining duration of the derivatives that were entered into while they were lenders in the Amended Credit Facility. The Company’s derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. (“ISDA”) Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Amended Credit Facility. The Company has set-off provisions in its derivative contracts with lenders under its Amended Credit Facility which, in the event of a counterparty default, allow the Company to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed the Company under derivative contracts. Where the counterparty is not a lender under the Company’s Amended Credit Facility, it may not be able to set-off amounts owed by the Company under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility.
9. Income Taxes
The expense for income taxes consists of the following:
Income tax expense differed from the amounts computed by applying the U.S. federal income tax rate of 35% to pretax income from continuing operations as a result of the following:
The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at December 31, 2011 and 2010 are presented below:
At December 31, 2011, the Company had approximately $125.3 million of federal tax net operating loss carryforwards, that expire through 2031. The tax return net operating loss carryforward of $125.3 million is greater than the financial statement net operating loss carryforward by $13.4 million due to excess tax benefits related to stock-based compensation not recognized for financial reporting purposes. The Company has a federal alternative minimum tax credit carryforward of $0.1 million, which has no expiration date.
In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. As a result, it may be determined that a deferred tax asset valuation allowance should be established. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense. In 2011, the Company recorded a valuation allowance against a deferred tax asset of the same amount for state income tax credit carryforwards in the amount of $4.2 million. It is currently estimated that the $4.2 million of state income tax credits will not be utilized because the Company does not project to have sufficient future taxable income in the appropriate jurisdictions.
At December 31, 2011, the Consolidated Balance Sheet reflected a net deferred tax liability of $311.4 million, of which $33.7 million pertains to the tax effects reflected in AOCI.
The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits.
A rollforward of changes in the Company’s unrecognized tax benefits is shown below:
In 2011, the Company generated no uncertain tax positions. The Company anticipates that no uncertain tax positions will be recognized within the next 12-month period. The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. As of December 31, 2011, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the current year.
The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and in various states. With few exceptions, the Company is subject to U.S. federal tax examination for years 2008 through 2011 and is subject to state tax examination for years 2007 through 2011.
10. Stockholders’ Equity
Common and Preferred Stock. The Company’s authorized capital structure consists of 75,000,000 shares of preferred stock, par value $0.001 per share and 150,000,000 shares of common stock, par value $0.001 per share. In October 2004, 150,000 shares of $0.001 per share par value preferred stock were designated as Series A Junior Participating Preferred Stock, none of which are outstanding. The remainder of the authorized preferred stock is undesignated. There are no issued and outstanding shares of preferred stock.
When issued, each share of Series A Junior Participating Preferred Stock will entitle the holder thereof to 1,000 votes on all matters submitted to a vote of the Company’s stockholders.
Treasury Stock. The Company may occasionally acquire treasury stock, which is recorded at cost, in connection with the vesting and exercise of stock-based awards or for other reasons. As of December 31, 2011, all treasury stock held by the Company was retired.
The following table reflects the activity in the Company’s common and treasury stock for the periods indicated:
Accumulated Other Comprehensive Income. The components of accumulated other comprehensive income and related tax effects for the years ended December 31, 2008, 2009, 2010 and 2011 were as follows:
11. Equity Incentive Compensation Plans and Other Employee Benefits
The Company maintains various stock-based compensation plans and other employee benefits as discussed below. Stock-based compensation is measured at the grant date based on the value of the awards, and the fair value is recognized on a straight-line basis over the requisite service period (usually the vesting period).
The following table presents the non-cash stock-based compensation related to equity awards for the periods indicated:
Unrecognized compensation cost as of December 31, 2011 was $25.4 million related to grants of nonvested stock options and nonvested equity shares of common stock that are expected to be recognized over a weighted-average period of 2.5 years.
Stock Options and Nonvested Equity Shares. In January 2002, the Company adopted a stock option plan to benefit key employees, directors and non-employees. This plan was amended and restated in its entirety by the Amended and Restated 2002 Stock Option Plan (the “2002 Option Plan”). The aggregate number of shares that the Company may issue under the 2002 Option Plan may not exceed 1,642,395 shares of the Company’s common stock. Options granted under the 2002 Option Plan expire up to ten years from the grant date. The options vest 40% on the first anniversary of the date of grant and 20% on each of the following three anniversaries of the date of grant.
In December 2003, the Company adopted its 2003 Stock Option Plan (the “2003 Option Plan”) to benefit key employees, directors and non-employees. In April 2004, the 2003 Option Plan was approved by the Company’s stockholders. The aggregate number of shares that the Company may issue under the 2003 Option Plan may not exceed 42,936 shares of the Company’s common stock. Options granted under the 2003 Option Plan expire up to ten years from the date of grant with an exercise price not less than 100% of the fair market value, as defined in the 2003 Option Plan, of the underlying common shares on the date of grant. Options granted under the 2003 Option Plan vest 25% on each of the first four anniversaries of the date of grant.
In December 2004, the Company’s stockholders approved the 2004 Stock Incentive Plan (the “2004 Incentive Plan”) for the purpose of enhancing the Company’s ability to attract and retain officers, employees, directors and consultants and to provide such persons with an interest in the Company parallel to its stockholders. The maximum number of shares that may be granted under the 2004 Incentive Plan is 4,900,000 shares. In addition, the maximum number of shares of common stock that may be granted to a participant in any one year is 1,225,000 shares. Options granted to date under the 2004 Incentive Plan generally expire seven years from the date of grant and vest 25% on each of the first four anniversaries of the date of grant.
In May 2008, the Company’s stockholders approved the 2008 Stock Incentive Plan (the “2008 Incentive Plan”). The total number of shares of the Company’s common stock available for issuance under the 2008 Incentive Plan is 3,000,000 shares, subject to adjustment for future stock splits, stock dividends and similar changes in the Company’s capitalization. The maximum number of shares of common stock that may be the subject of awards other than options and stock appreciation rights is 1,000,000 shares, while the maximum number of shares of common stock that may be issued pursuant to stock options and stock appreciation rights is 3,000,000 shares. The aggregate number of shares of common stock subject to options and/or stock appreciation rights granted during any calendar year to any one participant may not exceed 500,000 shares. The aggregate number of shares of common stock subject to restricted stock and/or restricted stock unit awards granted during any calendar year to any one participant may not exceed 500,000 shares. Options granted to date under the 2008 Incentive Plan generally expire seven years from the date of grant and vest 25% on each of the first four anniversaries of the date of grant.
The Company’s Compensation Committee may grant awards on such terms, including vesting and payment forms, as it deems appropriate within its discretion; however, no award may be exercised more than 10 years after its grant (five years in the case of an incentive stock option granted to an eligible individual who possesses more than 10% of the total combined voting power of all classes of stock of the Company). The purchase price or the manner in which the exercise price is to be determined for shares under each award will be determined by the Compensation Committee and set forth in the agreement. However, the exercise price per share under each award may not be less than 100% of the fair market value of a share on the date the award is granted (110% in the case of an incentive stock option granted to an eligible individual who possesses more than 10% of the total combined voting power of all classes of stock of the Company).
Currently, the Company’s practice is to issue new shares upon stock option exercise. The Company does not expect to repurchase any shares in the open market or issue treasury shares to settle any such exercises. For the years ended December 31, 2011, 2010 and 2009, the Company did not pay cash to repurchase any stock option exercises.
The fair value of each share-based option award under all of the Company’s plans is estimated on the date of grant using a Black-Scholes pricing model that incorporates the assumptions noted in the following table. For expected terms for which the Company had adequate historical data relating to its own common stock, estimated expected volatilities were based upon historical volatility of the Company’s common stock. Where the Company did not have enough historical data relating to its own common stock to compute volatilities associated with certain expected terms, expected volatilities were estimated based on an average of volatilities of similar sized oil and gas companies in the Rocky Mountain region whose common stock is publicly traded. The Company does not expect to declare or pay dividends in the foreseeable future; thus, the Company used a 0% expected dividend
yield, which is comparable to most of its peers in the industry. The expected terms range from 1.25 years to 6.0 years, or a weighted average of 4.5 years to 4.6 years, based on 25% of each grant’s vesting on each anniversary date and factoring in potential blackout dates, historic exercises and expectations of future employee behavior. The risk-free rate is based on the U.S. Treasury yield curve in effect on the date of grant and extrapolated to approximate the expected life of the award. The Company estimated a 4% to 10% annual compounded forfeiture rate for the years 2011, 2010 and 2009 based on historical employee turnover and actual forfeitures.
A summary of share-based option activity under all the Company’s plans as of December 31, 2011, and changes during the year then ended, is presented below:
(1) The aggregate intrinsic value includes 1,252,934 awards outstanding at December 31, 2011, 1,233,035 awards vested or expected to vest at December 31, 2011 and 732,800 awards vested and exercisable at December 31, 2011 that have no intrinsic value based on the Company’s closing stock price of $34.07 on December 31, 2011.
The per share weighted-average grant date fair value of options granted for the years ended December 31, 2011, 2010 and 2009 was $12.55, $10.55 and $10.79, respectively, and the total intrinsic value of options exercised during the same periods was $10.0 million, $9.7 million and $0.4 million, respectively. The aggregate intrinsic value in the preceding table represents the total pre-tax intrinsic value, based on the Company’s closing stock price of $34.07 on December 31, 2011. With respect to stock option exercises, the Company received $22.2 million, $23.7 million and $0.9 million for the years ended December 31, 2011, 2010 and 2009, respectively.
A summary of the Company’s nonvested equity shares of common stock as of December 31, 2011, 2010 and 2009, and changes during the years then ended, is presented below:
The fair value of equity awards vested for the years ended December 31, 2011, 2010 and 2009 was $8.8 million, $6.9 million and $3.5 million, respectively. The excess tax benefit realized from stock options and restricted stock is recognized as a credit to APIC and is calculated as the amount by which the tax deduction the Company receives exceeds the deferred tax asset associated with recorded stock compensation expense. The Company did not realize any excess tax benefits from stock compensation for the years ended December 31, 2011, 2010 or 2009 because there was not sufficient taxable income to realize the deduction due to the availability of federal and/or state net operating loss carryforwards.
Performance Share Programs. On May 9, 2007, the Compensation Committee of the Board of Directors of the Company approved a performance share program (the “2007 Program”) pursuant to the Company’s 2004 Incentive Plan for the Company’s officers and other senior employees, pursuant to which vesting of awards is contingent upon meeting various Company-wide performance goals. Upon commencement of the 2007 Program and during each subsequent year of the 2007 Program, the Compensation Committee met to approve target and stretch goals for certain operational or financial metrics that were selected by the Compensation Committee for the upcoming year and to determine whether metrics for the prior year had been met. These performance-based awards contingently vested over a period up to four years, depending on the level at which the performance goals were achieved. Each year for four years, it was possible for up to 50% of the original shares to vest based on the achievement of the performance goals. Twenty-five percent of the total grant would vest for metrics met at the target level, and an additional 25% of the total grant would vest for performance met at the stretch level. If the actual results for a metric were between the target levels and the stretch levels, the vested number of shares was adjusted on a prorated basis of the actual results compared to the target and stretch goals. If the target level metrics were not met, no shares would vest. In any event, the total number of common shares that could vest could not exceed the original number of performance shares granted. At the end of four years, any shares that had not vested were to be forfeited. A total of 250,000 shares under the 2004 Incentive Plan were set aside for the 2007 Program.
As new goals were established each year for the performance-based awards, a new grant date and a new fair value was created for financial reporting purposes for those shares that could potentially vest in the upcoming year. Compensation cost was recognized based upon an estimate of the extent to which the performance goals would be met. If such goals were not met, no compensation cost was recognized and any previously recognized compensation cost was reversed.
Based upon Company performance in 2007, 30% of the performance shares vested in February 2008. Based upon the Company’s performance in 2008, 50% of the performance shares vested in February 2009. After the February 2009 vesting, 20% of the initial grant remained available for future performance vesting. On February 26, 2009, the Compensation Committee approved a supplemental grant to each participant remaining in the performance share program equal to 30% of the initial grant received by that participant (a total of 72,479 shares) in order to provide sufficient shares so that up to 50% of the performance shares initially granted to each participant would be available for vesting if all stretch goals for 2009 were met. Based upon the Company’s performance in 2009, 50% of the total performance shares (including the supplemental grant) vested in February 2010. The Company recorded non-cash stock-based compensation cost associated with these shares of $0.2 million and $2.4 million for the years ended December 31, 2010 and 2009, respectively.
In February 2010, the Compensation Committee approved a new performance share program (the “2010 Program”) pursuant to the Company’s 2008 Incentive Plan. A total of 325,000 shares under the 2008 Incentive Plan were set aside for this program. The 2010 Program has the same four-year term and vesting provisions as the 2007 Program. For the year ended December 31, 2010, the performance goals consisted of finding and development costs per Mcfe (weighted at 37.5%), combined lease operating expenses and general and administrative expenses (weighted at 25%) and production growth (weighted at 37.5%). Based on the Company’s performance with respect to those metrics and the Compensation Committee’s approval, 25.9% of the total grant related to the year ended December 31, 2010 performance metrics vested in February 2011. Accordingly, the Company recorded non-cash stock-based compensation cost associated with these shares of $0.2 million and $1.9 million for the years ended December 31, 2011 and 2010, respectively.
In 2010, the Company also issued nonvested equity awards that are subject to a market performance-based vesting condition, which is based on the Company’s total stockholder return (“TSR”) ranking relative to a defined peer group’s individual TSR. The aggregate grant date fair value of the market-based awards was determined using the Monte Carlo simulation method. The fair value of the market-based awards is amortized ratably over the four year requisite service period. All compensation expense related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. Based on the Company’s TSR performance and the Compensation Committee’s approval, 37.5% of the total TSR grant related to the year ended December 31, 2010 performance metrics vested in February 2011. The Company recorded non-cash stock-based compensation related to market-based equity awards of $0.5 million for the year ended December 31, 2010.
In March 2011, the Compensation Committee set the performance metrics under the 2010 Program for vesting of the performance shares based on 2011 performance. For the year ending December 31, 2011, the performance goals consist of annual production growth (weighted at 25%), increases to oil and natural gas proved, probable and possible reserves (weighted at 25%), finding and development costs (weighted at 25%) and increases to the Company’s present value (at a 10% annual discount) of future net cash flows from proved reserves (weighted at 25%). For the year ended December 31, 2011, the remaining nonvested performance shares that were granted in 2010, along with 4,922 performance-based nonvested equity shares of common stock that were granted in February 2011, were subject to the new grant date, and the fair value was remeasured at $39.88 per share. The Company granted an additional 640 performance-based nonvested equity shares of common stock at a fair value of $45.27 during the year ended December 31, 2011. Based on the Company’s performance with respect to those metrics and the Compensation Committee’s approval, 26.6% of the total grant related to the year ended December 31, 2011 performance metrics will vest in February 2012. Accordingly, the Company recorded non-cash stock-based compensation cost associated with these shares of $2.4 million for the year ended December 31, 2011. As of December 31, 2011, there was $0.2 million of total compensation expense that will be recognized through February 2012, which represents the remaining time vesting requirement.
In March 2011, the Compensation Committee set the market-based performance metrics under the 2010 Program for the vesting of the market-based performance awards based on 2011 performance. The remaining unvested market-based performance shares that were granted in 2010, along with 1,038 market-based equity
shares that were granted in February 2011, were subject to a new grant date, and the fair value was remeasured at $39.88 per share. During the year ended December 31, 2011, the Company granted an additional 160 market-based non-vested equity shares of common stock at a fair value of $45.27. The fair value of the market-based awards is amortized ratably over the requisite service period. All compensation expense related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. Based on the Company’s TSR performance and the Compensation Committee’s approval, 12.5% of the total TSR grant related to the December 31, 2011 performance metrics will vest in February 2012. The Company recorded non-cash stock-based compensation related to market-based equity awards of $0.6 million for the year ended December 31, 2011. As of December 31, 2011, there was $0.8 million of total compensation expense that will be recognized over 2.1 years.
A summary of the Company’s non-vested performance-based equity shares of common stock as of December 31, 2011, 2010 and 2009, and changes during the years then ended, is presented below:
(1) As the Compensation Committee approved new performance metrics for the vesting of performance shares in the upcoming year, a new grant date was then created for any unvested awards that were granted in previous years, and a new fair value was established for financial reporting purposes.
The fair value of the performance-based shares vested in the years ended December 31, 2011, 2010 and 2009 was $2.3 million, $3.7 million and $2.7 million, respectively. The fair value of the market-based performance shares vested in the year ended December 31, 2011 was $0.8 million. The Company did not have any market-based performance shares vested in the years ended December 31, 2010 and 2009.
Director Fees. The Company’s non-employee, or outside, directors may elect to receive all or a portion of their annual retainer and meeting fees in the form of the Company’s common stock issued pursuant to the Company’s 2004 Incentive Plan. After each quarter, shares of common stock with a value equal to the fees payable for that quarter, calculated using the closing price on the last trading day before the end of the quarter, will be delivered to each outside director who elected before that quarter to receive shares for payment of director fees.
A summary of the Company’s directors’ fees and share-based compensation for the years ended December 31, 2011, 2010 and 2009 is presented below:
Other Employee Benefits-401(k) Savings Plan. The Company has an employee-directed 401(k) savings plan (the “401(k) Plan”) for all eligible employees over the age of 21. Under the 401(k) Plan, employees may make voluntary contributions based upon a percentage of their pretax income.
The Company matches 100% of each employee’s contribution, up to 6% of the employee’s pretax income, with 50% of the match made with the Company’s common stock. The Company’s cash and common stock contributions are fully vested upon the date of match and employees can immediately sell the portion of the match made with the Company’s common stock. The Company made matching cash and common stock contributions of $1.7 million, $1.6 million and $1.6 million for the years ended December 31, 2011, 2010 and 2009, respectively.
Deferred Compensation Plan. In 2010, the Company adopted a non-qualified deferred compensation plan for certain employees and officers whose eligibility to participate in the plan was determined by the Compensation Committee of the Company’s Board of Directors. The Company makes matching cash contributions on behalf of eligible employees up to 6% of the employee’s cash compensation once the contribution limits are reached on the Company’s 401(k) Plan. All amounts deferred and matched under the plan vest immediately.
Participants earn a return on their deferred compensation based on investment earnings of participant-selected mutual funds. Participants’ deferred compensation amounts are not directly invested in these investment vehicles; however, the Company tracks the performance of each participant’s investment selections and adjusts the deferred compensation liability accordingly. Changes in the market value of the participants’ investment selections are recorded as an adjustment to deferred compensation liabilities, with an offset to compensation expense included within general and administrative expenses in the Consolidated Statements of Operations. Deferred compensation, including accumulated earnings on the participant-directed investment selections, is distributable in cash at participant-specified dates or upon retirement, death, disability, change in control or termination of employment.
The table below summarizes the activity in the plan during the years ended December 31, 2011 and 2010 and the Company’s ending deferred compensation liability as of December 31, 2011 and 2010 (in thousands):
The Company is not obligated to fund the liability. It has, however, established a rabbi trust to offset the deferred compensation liability and protect the interests of the plan participants. The trust assets are invested in publicly-traded mutual funds. The investments in the rabbi trust seek to offset the change in the value of the related liability. As a result, there is no expected impact on earnings or earnings per share from the changes in market value of the investment assets because the changes in market value of the trust assets are offset by changes in the value of the deferred compensation plan liability. The gains and losses from changes in fair value of the investments are included in interest and other income in the Consolidated Statements of Operations.
The following table represents the Company’s activity in the investment assets held in the rabbi trust during the years ended December 31, 2011 and 2010 (in thousands):
12. Significant Customers and Other Concentrations
Significant Customers. During 2011, the Company had three customers individually account for over 10% of the Company’s oil and gas production revenues. During 2010, the Company had two customers individually account for over 10% of the Company’s oil and gas production revenues. During 2009, The Company had two customers individually account for over 10% of the Company’s oil and gas production revenues. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.
Concentrations of Market Risk. The future results of the Company’s oil and gas operations will be affected by the market prices of oil and natural gas. A readily available market for crude oil, natural gas and liquid products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of oil, gas and liquid products, the regulatory environment, the economic environment and other regional, national and international economic and political events, none of which can be predicted with certainty.
The Company operates in the exploration, development and production phase of the oil and gas industry. Its receivables include amounts due from purchasers of oil and gas production and amounts due from joint venture partners for their respective portions of operating expenses and exploration and development costs. The Company believes that no single customer or joint venture partner exposes the Company to significant credit risk. While certain of these customers and joint venture partners are affected by periodic downturns in the economy in general or in their specific segment of the natural gas or oil industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations in the long-term. Trade receivables are generally not collateralized. The Company analyzes customers’ and joint venture partners’ historical credit positions and payment histories prior to extending credit.
Concentrations of Credit Risk. Derivative financial instruments that hedge the price of oil and gas and interest rate levels are generally executed with major financial or commodities trading institutions which expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company’s policy is to execute financial derivatives only with major, credit worthy financial institutions. The Company has hedges in place with 12 different counterparties, of which 10 are lenders or affiliates of lenders in the Amended Credit Facility. It is the Company’s policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility or potential lenders in the Amended Credit Facility. Two counterparties that were lenders in the Amended Credit Facility withdrew from the facility when the Company amended the facility in October 2011. The Company will continue to monitor the credit worthiness of these two counterparties during the remaining duration of the derivatives that were entered into while they were lenders in the Amended Credit Facility. The Company’s derivative contracts are documented using an industry standard contract known as an ISDA master agreement or other contracts.
The credit worthiness of counterparties is subject to continuing review, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties. Where the counterparty is a lender under the Amended Credit Facility, the counterparty risk is mitigated to the extent that the Company is indebted to such lender under the Amended Credit Facility.
13. Commitments and Contingencies
Transportation Demand and Firm Processing Charges. The Company has entered into contracts that provide firm transportation capacity on pipeline systems and firm processing charges. The remaining terms on these contracts range from one to 12 years and require the Company to pay transportation demand and processing charges regardless of the amount of pipeline capacity utilized by the Company. The Company paid $35.3 million, $18.1 million and $15.5 million of transportation demand charges for the years ended December 31, 2011, 2010 and 2009, respectively. The Company paid $5.0 million, $4.1 million and $4.1 million of firm processing charges for the years ended December 31, 2011, 2010 and 2009, respectively. All transportation costs, including demand charges and processing charges, are included in gathering, transportation and processing expense in the Consolidated Statements of Operations.
The values in the table below represent the Company’s gross future minimum transportation demand and firm processing charges as of and subsequent to December 31, 2011. However, the Company will record in its financial statements only the Company’s proportionate share based on the Company’s working interest and net revenue interest, which will vary from property to property.
Drilling, Lease and Other Commitments. At December 31, 2011, the Company had three drilling rigs under contract through 2012 and two through 2013, which have total commitments of $34.7 million. These contracts may be terminated but the Company would be required to pay a penalty of $21.9 million. All other rigs currently performing work for the Company are on a well-by-well basis and, therefore, can be released without penalty at the conclusion of drilling on the current well. The Company also has one take-or-pay purchase agreement for supply of carbon dioxide (“CO2”), which has a total financial commitment of $12.8 million. Under this contract, the Company is obligated to purchase a minimum monthly volume at a set price. If the Company takes delivery of less than the minimum required amount, the Company is responsible for full payment (deficiency payment). At this time, the Company anticipates sufficient need for CO2 and, therefore, expects to avoid any deficiency payments. The CO2 is for use in fracture stimulation operations in the Company’s West Tavaputs field.
The Company leases office space, vehicles and certain equipment under non-cancelable operating leases. Office lease expense was $1.5 million, $1.5 million and $1.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. Additionally, the Company has entered into various long-term agreements for telecommunication services.
Future minimum annual payments under such drilling, lease and other agreements as of and subsequent to December 31, 2011 are as follows:
(1) The values in the table represent the gross amounts that the Company is committed to pay. However, the Company will record in its financial statements only the Company’s proportionate share based on the Company’s working interest and net revenue interest, which will vary from property to property.
In addition to the commitments above, the Company has commitments for the purchase of facilities and infrastructure as of and subsequent to December 31, 2011 of $10.5 million.
Litigation. The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the course of ordinary business. It is the opinion of the Company’s management that current claims and litigation involving the Company are not likely to have a material adverse effect on its consolidated financial position, cash flows or results of operations.
14. Guarantor Subsidiaries
In addition to the Amended Credit Facility, the 9.875% Senior Notes, the 7.625% Senior Notes and the Convertible Notes, which are registered securities, are jointly and severally guaranteed on a full and unconditional basis by the Company’s 100% owned subsidiaries (“Guarantor Subsidiaries”). Presented below are the Company’s condensed consolidating balance sheets, statements of operations and statements of cash flows, as required by Rule 3-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended.
The following condensed consolidating financial statements have been prepared from the Company’s financial information on the same basis of accounting as the consolidated financial statements. Investments in the subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Company and the Guarantor Subsidiaries are reflected in the intercompany eliminations column.
Condensed Consolidating Balance Sheets
Condensed Consolidating Statements of Operations
Condensed Consolidating Statements of Cash Flows
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(In Thousands, Except Per Share Data Unless Otherwise Indicated)
(Unaudited)
Oil and Gas Producing Activities
Costs Incurred. Costs incurred in oil and gas property acquisition, exploration and development activities and related depletion per equivalent unit-of-production were as follows:
Supplemental Oil and Gas Reserve Information. The reserve information presented below is based on estimates of net proved reserves as of December 31, 2011, 2010 and 2009 that were prepared by internal petroleum engineers in accordance with guidelines established by the SEC and were audited by the Company’s independent petroleum engineering firm Netherland, Sewell & Associates, Inc. (“NSAI”) in 2011, 2010 and 2009.
Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Analysis of Changes in Proved Reserves. The following table sets forth information regarding the Company’s estimated net total proved and proved developed oil and gas reserve quantities:
At December 31, 2011, the Company revised its proved reserves upward by 37.9 Bcfe, excluding pricing revisions, due primarily to the positive results of increased operational focus and engineering and geological study of the Company’s Blacktail Ridge field in the Uinta Basin. At December 31, 2011, the Company also revised its 2011 proved reserves upward by 5.5 Bcfe, as 2011 pricing was $3.93 per MMBtu and $92.71 per barrel of oil compared with the 2010 pricing of $3.95 per MMBtu and $75.96 per barrel of oil. Prices were adjusted by lease for quality, transportation fees and regional price differences.
At December 31, 2010, the Company revised its proved reserves upward by 39.8 Bcfe, excluding pricing revisions, due to improved production performance in Piceance and Wind River Basins and the addition of 24.7 Bcfe of reserves from the third offsetting development spacing areas added as proved undeveloped in the Piceance Basin. At December 31, 2010, the Company revised its proved reserves upward by 27.4 Bcfe, as 2010 pricing was $3.95 per MMBtu and $75.96 per barrel of oil compared to 2009 pricing of $3.04 per MMBtu and $57.65 per barrel of oil. Prices were adjusted by lease for quality, transportation fees and regional price differences.
At December 31, 2009, the Company revised its proved reserves upward by 101.5 Bcfe, excluding pricing revisions, due to improved production performance in Piceance, West Tavaputs and Blacktail Ridge and the increased revenue associated with the recovery of NGLs and reduced drilling and completion costs in Piceance. Also included in the engineering revisions was the addition of 64 Bcfe from the second offsetting development spacing areas added as proved undeveloped in the Piceance Basin. The total reserves from the second development spacing areas in the Piceance Basin was 86.3 Bcfe, of which 64 Bcfe was in the engineering revision category and 22.3 Bcfe was in the extension and discoveries category resulting from drilling and completion operations in 2009. At December 31, 2009, the Company also revised its proved reserves downward by 42.8 Bcfe, as 2009 pricing was $3.04 per MMBtu and $57.65 per barrel of oil compared to 2008 pricing of $4.61 per MMBtu and $41.00 per barrel of oil (using the former SEC end of year pricing). Prices were adjusted by lease for quality, transportation fees and regional price differences.
Standardized Measure. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.
For the years ended December 31, 2011, 2010 and 2009, future cash inflows are calculated by applying the 12-month average pricing (as is required by the rules of the Securities and Exchange Commission) of oil and gas relating to the Company’s proved reserves to the year-end quantities of those reserves. For the year ended December 31, 2011, calculations were made using prices of $92.71 per Bbl for oil and $3.93 per MMBtu for gas, as compared to the average benchmark prices of $78.04 per Bbl for oil and $5.16 per Mcf for gas. For the year ended December 31, 2010, calculations were made using prices of $75.96 per Bbl for oil and $3.95 per MMBtu for gas, as compared to the average benchmark prices of $63.01 per Bbl for oil and $4.76 per Mcf for gas. For the year ended December 31, 2009, calculations were made using prices of $57.65 per Bbl for oil and $3.04 per MMBtu for gas, as compared to the average benchmark prices of $45.26 per Bbl for oil and $3.50 per Mcf for gas. The differences between the average benchmark prices and the average prices used in the calculation of the standardized measure are attributable to adjustments made for transportation, quality and basis differentials. The Company also records an overhead charge against its future cash flows.
The assumptions used to calculate estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.
Future development and production costs are calculated by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.
Future income tax expenses are calculated by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.
The following table presents the standardized measure of discounted future net cash flows related to proved oil and gas reserves:
The “standardized measure” is the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10% to reflect timing of future cash flows.
The present value (at a 10% annual discount) of future net cash flows from the Company’s proved reserves is not necessarily the same as the current market value of its estimated oil and natural gas reserves. The Company bases the estimated discounted future net cash flows from its proved reserves on prices and costs in effect on the day of estimate in accordance with the applicable accounting guidance. However, actual future net cash flows from its oil and natural gas properties will also be affected by factors such as actual prices the Company receives for oil and natural gas, the amount and timing of actual production, supply of and demand for oil and natural gas and changes in governmental regulations or taxation.
The timing of both the Company’s production and incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% annual discount factor the Company uses when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry in general.
A summary of changes in the standardized measure of discounted future net cash flows is as follows:
Quarterly Financial Data
The following is a summary of the unaudited quarterly financial data, including income before income taxes, net income and net income per common share for the years ended December 31, 2011 and 2010.